OGJ Newsletter

July 27, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Mexican round nets two successful bids

Two of 14 shallow-water blocks received successful bids on July 15 in Mexico's historic Round One offering of exploration and production rights (OGJ Online, Dec. 19, 2014).

A joint venture of Talos Energy LLC, Houston; Sierra Oil & Gas, Mexico City; and Premier Oil PLC, London, submitted both bids.

Before bidding opened, Juan Carlos Zepeda, president of Mexico's National Hydrocarbons Commission, had indicated the round would be considered successful if it led to the award of four to seven contracts.

The round was the first to make participation in Mexican oil and gas exploration and production available to non-Mexican companies. Terms are based on production-sharing.

Five individual companies and four groups submitted bids for six of the blocks on offer. Four bids fell below minimum terms set by the government.

Large companies registered for the auction were Statoil ASA, Murphy Oil Corp., Eni SPA, and Oil & Natural Gas Corp.

Twenty-five of 49 companies purchasing data-room access had prequalified to bid.

The successful bids were for Block 2, off Veracruz, and Block 7, off Tabasco (see map, OGJ, Mar. 2, 2015, p. 30). Both have minimum drilling requirements of two wells.

In a statement, Premier said drilling locations might be identified "towards the end of 2016." It said both blocks contain Tertiary clastic plays typical of the Salinas subbasin of the Sureste basin.

Talos Energy is operator of the joint venture. It and Sierra Oil & Gas hold 45% interests each. Premier holds 10% with an option to participate in the drilling program at an equity interest of up to 25%.

PV seen gaining on gas-fueled electricity

Utility-scale photovoltaic (PV) conversion of solar energy into electricity soon will be competitive with generation fueled by natural gas, predicts energy analyst Leonardo Maugeri.

The cost of PV modules dropped almost 80% during 2000-14, notes Maugeri, a former Eni SPA executive who's now senior associate at the Belfer Center for Science & International Relations at Harvard University's John F. Kennedy School of Government.

The cost has fallen 65% since 2008 and almost 40% in the last 3 years.

"Because the technology and costs of PV power continue to improve each year at rates unequaled by other sources of energy, it is probable that in a few years utility-scale PV will be more competitive than natural gas ones," Maugeri writes in a July 20 energy briefing.

Total capacity of PV installations worldwide increased to 177 Gw in 2014 from 1.3 Gw in 2000. Maugeri says it might grow by 30% this year and reach 500 Gw by 2020.

Although most efficiency improvements and cost declines have been noted in distributed-power applications, Maugeri says, "it is in the utility-scale PV market that we can perceive the signs of a revolution."

There, PV technology has advanced strongly in competition with concentrated solar power, the technology based on mirrors and steam turbines once thought to be most applicable to utility-scale generation.

Because of storage limits, the largest PV stations still require back-up by small and medium-size gas-fired plants for dark periods.

But Maugeri sees great potential in the sunny Middle East, especially in countries with rapidly growing demand for electricity. There, solar's gains will come at the expense of nuclear power. Maugeri says the cost of a nuclear plant is now at least 2.3 times that of a utility-scale PV plant.

UAE easing gasoline, diesel price controls

The United Arab Emirates is moving prices of gasoline and diesel toward deregulation effective Aug. 1.

The Ministry of Energy said a committee will set prices monthly in accordance with average international levels.

Chaired by the energy ministry undersecretary, the committee includes the undersecretary of the Ministry of Finance and the chief executive officers of ADNOC Distribution and Emirates National Oil Co.

According to the energy ministry, prices last year were $1.67/gal for regular gasoline, $2.42/gal for diesel in Abu Dhabi, and $3.52/gal for diesel in northern emirates.

Exploration & DevelopmentQuick Takes

BHP Billiton still interpreting deepwater seismic data

BHP Billiton, the operator of all of the deepwater blocks awarded by Trinidad and Tobago, has said it will decide how many wells it will drill based on its ongoing interpretation of the 20,000 sq km of seismic data it has collected in 2,500-8,500 ft of water.

In an e-mail response to several questions from OGJ, the Australian outfit said the structures in the deep water are "complex" and in depth analysis is required. It added that the drilling campaign will begin 2016 but did not say in which quarter.

The company will be using Transocean's Deepwater Invictus drillship, which can operate in as much as 12,000 ft of water and drill as deep as 40,000 ft below the surface.

BHP Billiton recently told a meeting of the Geological Society of Trinidad and Tobago that it is excited about the prospects from its deepwater blocks after seeing the initial seismic data. The company reported that it had seen massive structures and that it had also conducted a piston core sample that revealed an active hydrocarbon system.

It is expected that in the northern deepwater blocks in which BHP Billiton is operator with partner BP PLC, there is the same Oligocene trend as found in BHP Billiton's Angostura field (OGJ Online, Oct. 9, 2014). Blocks 23(a) and TTDAA 14 are offshore the east coast of Trinidad and Tobago and BHP Billiton believes that they are a continuation of Angostura.

Angostura is BHP's current field, in which it discovered significant oil and gas that has been difficult to produce because of significant faulting.

The northern blocks that were initially awarded to BP had the same trend as BHP's Angostura field. Greater Angostura field lies in 36-46 m of water on the continental shelf, 37 km east of Trinidad and in the eastern Trinidadian sector of the eastern Venezuela basin.

Geophysical surveys due onshore Tanzania

Tanzania Petroleum Development Corp. has let a contract to CGG for geophysical surveys over two onshore areas in preparation for future licensing rounds.

CGG will acquire high-resolution gravity gradiometry and aeromagnetic data over the southeastern Tanzanian coastal basin and eastern arm of the East African rift.

Surveys of areas totaling 30,000 sq km will begin in mid-August and take up to 2 months. CGG also will interpret the data.

CGG notes that Tanzania's parliament recently passed a petroleum bill recognizing TPDC as a national oil company able to participate fully in exploration and production.

Nile Delta gas strike due on production

Eni SPA said a natural gas discovery on the Nooros prospect in Egypt will be placed on production at an unspecified rate within 2 months.

The discovery well, Nidoco NW2 Dir NFW, encountered 60 m of gas pay in Messianian sandstone with "excellent petrophysical properties" and other gas-bearing strata in the overlying Pliocene section.

Drilled to 3,600 m TD, the well is in the Abu Madi West license in the Nile Delta, 120 km northeast of Alexandria.

Eni, which through subsidiary Ieoc Production BV, holds a 75% working interest in the West Abu Madi development lease, estimated potential hydrocarbons in place at 15 billion cu m of gas plus associated condensates.

The discovery well will be tied into the Abu Madi gas treatment plant 25 km southeast.

BP PLC holds a 25% interest in the development lease.

Concession operator is Petrobel, owned equally by Ieoc and Egyptian General Petroleum Corp.

Drilling & ProductionQuick Takes

Last key structure sails for Cygnus off UK

The last of four main structures for Cygnus natural gas field has departed the Heerema Hartlepool yard in the UK en route to installation on North Sea Blocks 44/11a and 44/12a, 150 km offshore Lincolnshire (OGJ Online, Aug. 13, 2012).

It's the Cygnus Alpha compression module, which will be set atop the Alpha process and utilities topside. That unit, the largest of four platforms due on the field, departed the yard earlier with the Bravo wellhead platform.

The Cygnus Alpha wellhead platform sailed away in May. The field also will have a quarters platform, which, like the Alpha wellhead platform, will be bridge-linked to the process and utilities platform.

The unmanned Bravo wellhead platform will be tied to the process and utilities platform with a 7.5-km, 12-in. production line and umbilicals. Production is to begin by yearend.

Operator GDF Suez E&P UK Ltd. plans to produce from five wells drilled from each of the wellhead platforms. Production will peak at about 250 MMcfd of gas. The total of proved and probable reserves is estimated at 635 bcf.

Cygnus gas will flow through a new 51-km export line linked to the Esmond Transport System pipeline, which makes landfall at Bacton.

Cygnus interests are GDF Suez UK 38.75%, Centrica Energy 48.75%, and Bayerngas Norge 12.5%.

The last of four main structures for Cygnus natural gas field has departed the Heerema Hartlepool yard. Photo from Heerema Hartlepool.

Total starts oil flow from Dalia Phase 1A

Total SA has started production from Dalia Phase 1A, a development on the company's deep offshore operated Block 17, 135 km offshore Angola.

Dalia Phase 1A will develop additional reserves of 51 million bbl and will contribute 30,000 b/d to the block's production.

The Dalia Phase 1A project involves the drilling of seven infill wells tied back to the Dalia floating production, storage, and offloading unit.

The Dalia FPSO, says Total, came on stream 9 years ago, and with the addition of Phase 1A will still produce 200,000 b/d.

Total operates Block 17 with a 40% interest alongside Statoil 23.33%, Esso Exploration Angola Block 17 Ltd. 20%, and BP Exploration Angola Ltd. 16.67%. Sonangol is the concessionaire of the license.

The group operates four FPSO units on the major production zones of the block: Girassol, Dalia, Pazflor, and CLOV (Cravo, Lirio, Orquidea, and Violeta) (OGJ Online, May 27, 2015).

Total also operates with a 30% interest the ultradeep Kaombo development on Block 32. A final investment decision was made in April 2014 to develop Kaombo's estimated reserves of 650 million bbl via two converted FPSOs with a total production capacity of 230,000 b/d.

Problems limit oil flow at Jubilee field off Ghana

Tullow Oil PLC reported oil production at Jubilee field offshore Ghana is constrained to 65,000 b/d due to technical issues with gas compression systems on the Kwame Nkrumah floating production, storage, and offloading vessel. First half production averaged 105,000 b/d (OGJ Online, July 1, 2015).

Gas exports to the Ghana gas plant at Atuabo has been suspended since July 3. Tullow expects "a further 3 weeks to reinstate gas export and full oil production."

The company also said that there is "no effect" on the field's reservoir or resources.

Tullow will provide an update on July 29 regarding its 2015 production forecast.

PROCESSINGQuick Takes

Unplanned work under way at Venezuelan refinery

Petroleos de Venezuela SA (PDVSA) said unplanned maintenance to a reformer at its at its 190,000-b/d Puerto La Cruz refinery in eastern Venezuela is nearing completion.

Repairs to the reformer, which processes naphtha to produced high-octane components for gasoline blending, are scheduled to be completed by the end of July, the state-owned company said.

The unplanned maintenance event resulted from an obstruction in the unit, according to PDVSA, which did not disclose details regarding the nature of the obstruction or the date on which it occurred.

PDVSA did, however, bring forward planned preventative maintenance to a catalyst regeneration system at the refinery that originally was scheduled to take place in August.

While the company did not reveal impacts to production levels at the refinery as a result of the maintenance event, PDVSA did say it has taken precautions to prevent supply disruptions to local markets served by the refinery.

Last year, PDVSA began construction activities at Puerto La Cruz for a long-planned expansion and modernization project that will include the remodeling of existing installations and equipment at the refinery as well as some construction to improve the yield of higher-quality products from a heavier slate of crude oil feedstocks (OGJ Online, July 21, 2014).

Upon completion of the deep-conversion project in June 2018, the refinery, which now runs light and medium crude oil, will be able to process 210,000 b/d of heavy and extra-heavy crude oil from Venezuela's Orinoco region (OGJ Online, Apr. 22, 2015).

PDVSA previously said the deep-conversion project at Puerto La Cruz would require a total investment of $5.2 billion and involve the following construction: a two-train, 50,000-b/d deep-conversion unit based on HDH Plus technology developed by Intevep, PDVSA's research unit; a three-train sequential hydroprocessing unit; a 130,000-b/d three-train vacuum unit; and associated auxiliary units, service units, interconnections, and tanks.

The modernization project also will include the upgrading of the refinery's two atmospheric distillation units.

PDVSA plans restart for Amuay refinery's FCCU

Repairs remain under way on the fluid catalytic cracking unit (FCCU) at Petroleos de Venezuela SA's (PDVSA) 645,000-b/d Amuay refinery in northwestern Venezuela's Falcon state following an unplanned shutdown of the unit in early July.

Corrective maintenance at the FCCU is progressing according to plan and is due to reach mechanical completion on or about July 28, PDVSA said.

Once repairs are completed, PDVSA plans to begin the unit's restart process immediately.

The FCCU was shuttered earlier this month following unidentified problems with its regenerator and associated minor equipment, according to a July 1 release from the state-owned company.

Remaining processing units at the Amuay refinery as well as at the nearby 310,000-b/d Cardon refinery-which together comprise PDVSA's 955,000-b/d Paraguana Refining Center (CRP)-have continued to operate normally during the unplanned maintenance event, PDVSA said.

With no interruptions to operations at the Cardon refinery's fluid catalytic cracking plant, PDVSA said it maintains sufficient fuel inventories to meet both its domestic and international supply commitments.

The company did not disclose a timeframe for when CRP might return to its full FCCU processing capacity of 166,500 b/d.

TRANSPORTATIONQuick Takes

Excelerate FSRUs complete LNG transfer

Excelerate Energy LP, The Woodlands, Tex., reported the completion of the first ship-to-ship (STS) transfer of LNG at the Engro Elengy LNG terminal in Port Qasim, Pakistan.

Excelerate's Exquisite floating storage and regasification unit (FSRU) received 130,000 cu m of LNG from the Excelerate FSRU using the double-banked LNG transfer system.

This transfer also marks the company's 500th commercial STS operation using the double-banked cryogenic transfer system technology developed by Excelerate, the company said.

Commissioned in late March, the terminal initially employed the Exquisite for both cargo delivery and regasification. The terminal will continue to receive LNG via periodical STS transfers allowing for the continuous flow of gas into the local gas distribution system.

To date, Excelerate has successfully completed more than 785 STS operations, transferring more than 83 million cu m using its STS protocol.

Excelerate Energy LP completed the first ship-to-ship transfer of LNG at the Engro Elengy LNG terminal in Port Qasim, Pakistan. Photo from Excelerate Energy.

BC bill advances Pacific Northwest LNG

The British Columbia legislature has passed a controversial bill enabling the proposed Pacific Northwest LNG export project to advance (OGJ Online, Mar. 17, 2014).

Meeting in a special session, lawmakers approved the Liquefied Natural Gas Projects Agreement Act, which allows the government to enter a project agreement with the $36-billion Pacific Northwest venture.

Led by Petronas of Malaysia, the group has partners from China, India, Japan, and Brunei. It proposes to build two liquefaction trains initially on Lelu Island near Prince Rupert with capacities of 6 million tonnes/year each.

In June, Pacific Northwest said it would proceed with the project if the legislature ratified the project-development agreement and if the project received federal environmental approval.

At least 17 other LNG export projects are in less-advanced stages of planning for the BC coast.

Liberal BC Premier Christy Clark strongly supported the LNG legislation, which faced opposition from environmentalists, First Nations groups, and lawmakers arguing against assurances granted LNG project sponsors.

The legislation commits the province to compensate the project group if future governments raise income taxes on LNG operations, target the industry with carbon taxes, cut gas tax credits, or change rules on greenhouse gas emissions that financially hurt the industry.

KMI to buy Shell's stake in Elba LNG project

Kinder Morgan Inc., Houston, has reached a deal with Royal Dutch Shell PLC to purchase 100% of Shell's equity interest in Elba Liquefaction Co. LLC (ELC). The ELC joint venture serves as owner of the Elba Liquefaction Project, which is proposed to be built and operated at the existing Elba Island LNG terminal near Savannah, Ga.

KMI's expected incremental investment resulting from this transaction is $630 million, bringing its total incremental investment in all the liquefaction and terminal facilities at Elba Island to $2.1 billion.

KMI currently owns 51% of the ELC JV. Shell owns the remaining 49% and subscribes to 100% of the liquefaction capacity. KMI will purchase the remaining 49% of the JV that it does not already own.

Permitting continues for the proposed Elba project, which consists of 10 small-scale liquefaction units to be purchased from Shell. They will be integrated with the existing Elba Island facility and enable rapid construction compared to traditional large-scale plants.

The next step in the regulatory approval process is for the US Federal Energy Regulatory Commission to issue a draft environmental assessment. Subject to regulatory approvals, construction could begin in this year's fourth quarter, with initial production expected to occur in late 2017.

In 2012, the project received authorization from the US Department of Energy to export to free-trade agreement countries. An application to export to non-FTA countries is pending. Under full development, the Elba Liquefaction Project is expected to have a total capacity of 2.5 million tonnes/year of LNG for export.