OGJ Newsletter

Nov. 30, 2015
International news for oil and gas professionals


US crude oil reserves increase on 6-year trend

At yearend 2014, US crude oil reserves reached nearly 40 billion bbl for the first time since 1972, according to the US Energy Information Administration.

In its latest survey, released Nov. 23, EIA noted that proved reserves of oil and lease condensate reached 39.9 billion bbl at yearend 2014-an increase of 3.4 billion bbl from 2013.

This marks the sixth consecutive increase in oil reserves, EIA said. Proved natural gas reserves, meanwhile, increased 9.8% to 388.8 tcf at yearend 2014, marking the second consecutive increase of proved gas reserves.

EIA's report cites 2014 as the fourth-highest reserves estimate for US crude. Highlights include Texas' addition of 2.1 billion bbl from the state's portion of the Permian basin and the Eagle Ford shale. North Dakota added 0.4 billion bbl, mostly from the Bakken shale.

The highest proved reserves additions of gas were from Pennsylvania's Marcellus shale, where operators added a net 10.4 tcf to 2014 estimates.

Several other states contributed to gas reserves growth in the US. West Virginia surpassed Wyoming and Colorado to become the fourth-largest state for proved gas reserves. Ohio more than doubled its gas reserves in 2014 due to further development of the Utica shale. Idaho also reported gas reserves for the first time in 2014.

Sustained low oil and gas prices are expected to reduce reserves for EIA's next report for yearend 2015. Drilling has curtailed throughout much of the US, and lower prices have made recovery economics more challenging. Since Aug. 21, the overall rig count has fallen 118 units (OGJ Online, Nov. 23, 2015).

Pacific E&P exits PNG, to focus on South America

Pacific Exploration & Production Corp., formerly Pacific Rubiales, has decided to exit its interests in Papua New Guinea that include the Triceratops and Raptor gas-condensate discoveries in retention license PRL 39 and exploration permit PPL 475, respectively (OGJ Online, Dec. 3, 2014).

Pacific E&P had 12.09032% of PRL 39 under a farm-in arrangement with InterOil Corp. and its withdrawal will mean InterOil's interest reverts to 100%. InterOil will now have 78.1114% of the Triceratops discovery. In PPL 475, formerly PPL237, InterOil's gross interest will also revert to 100% and its interest in the Raptor find to 79.1114%.

Trceratops-3 appraisal well flowed gas at 17.1 MMcfd on test last September with condensate flowing at an average rate of 200 b/d. The flows were constrained by tubing size.

Appraisal of Raptor has been postponed so the the rig can be used to appraise the nearby Elk-Antelope field to advance the Papua LNG project.

Pacific E&P will now refocus its operations on Columbia, Peru, Guatemala, Brazil, Guyana, Belize, and Mexico.

The company has production of 153,000 boe/d from Columbia and Peru. Rubiales field, in Columbia, contributes 36% to that production.

PrairieSky to acquire CNRL royalty acreage

Canadian Natural Resources Ltd. and PrairieSky Royalty Ltd., both of Calgary, have agreed to combine their royalty businesses into what will become Canada's largest independent oil and gas royalty position, owned by PrairieSky.

CNRL will receive $680 million (Can.) in cash and new PrairieSky shares worth about $1.12 million in exchange for 5.4 million acres of royalty land in western Canada with oil and gas production of about 6,700 boe/d. The acquired land includes 2.2 million acres of fee simple mineral title land.

CNRL agreed to distribute to its shareholders enough PrairieSky shares to keep its ownership of the firm below 10%. The transaction represents about 81% of CNRL's royalty production.

Through a leasing arrangement and drilling commitment with PrairieSky on part of the fee simple mineral title lands to be transferred, CNRL preserved the right to develop a core area on 104,000 acres of undeveloped land in western Saskatchewan that it believes holds heavy-oil potential.

The land position after the combination-totaling 14.7 million acres of royalty land, including 7.7 million acres of fee simple mineral title excluding coal-covers the Viking light oil play in western Sakatchewan and the multizone Deep basin fairway of Alberta and British Columbia.

Mitsui to buy stake in Kipper field from Santos

Mitsui & Co. Ltd. has agreed to purchase 35% stake in Australia's Kipper gas-condensate field from Santos Ltd. for $520 million (Aus.).

Kipper field lies in 100 m of water in the Gippsland basin, about 45 km offshore Victoria (OGJ Online, Mar. 3, 2009). Mitsui said production is expected to start in 2016.

Operator Esso Australia Resources and BHP Billiton Petroleum each own 32.5%. Recoverable gas reserves are estimated at 620 bcf, while condensate and LPG reserves are estimated at 30 million bbl.

The transaction will be completed after government approvals and partner waiver of preemptive rights.

Mitsui said it believes Australia's east coast requires new investments in developing gas resources to meet demand.

Most recently Santos sold its interest in Stag field offshore Western Australia (OGJ Online, Nov. 2, 2015).

Exploration & DevelopmentQuick Takes

BG farming into Aphrodite block off Cyprus

Principals of the farmout of a large interest in Block 12 offshore Cyprus expect the deal to advance development of Aphrodite natural gas field.

BG Group is acquiring 35% interest in the block from Noble Energy Inc. for $165 million cash.

Aphrodite, discovered in 2011, has gross mean natural resources of 4 tcf. It's across the sector line from undeveloped Leviathan gas field, a 2010 discovery by a group led by Noble in Israeli waters.

Noble will remain operator of the Aphrodite block with a 35% working interest. Delek Group holds the other 30%.

Several development schemes have been discussed for Aphrodite, including an LNG plant at Vassilikos, Cyprus, that also would receive gas from Leviathan field. Another possibility is a pipeline to Egypt, where Eni SPA recently reported the giant deepwater Zohr gas discovery (OGJ Online, Aug. 31, 2015).

"We are continuing to work with the government of Cyprus to finalize Aphrodite development plans," said J. Keith Elliott, Noble Energy senior vice-president of Eastern Mediterranean. "In conjunction with that work, we have recently commenced gas marketing efforts, primarily targeting customers in Egypt, including both domestic purchasers and underutilized [LNG] plants."

In a statement about the Block 12 deal, BG Group also cited Egyptian projects.

"This upstream position provides a potential source of gas to Egypt, where BG Group holds equity in the two-train LNG export facility at Idku as well as LNG offtake rights to lift 3.6 million tonnes/year," it said.

BG Group made the undeveloped Gaza Marine discovery off Palestinian territory in 2000.

Separately, Noble Energy is selling its 47% interests in the Alon A and Alon C licenses off Israel, which include Tanin and Karish gas fields, to Dele Group for $73 million.

The divestments accommodate a regulatory agreement in Israel under which Delek will sell its Tanin and Karish interests and Noble Energy will diminish some of its Israeli holdings.

Petrobras confirms Pitu oil discovery

Petroleo Brasileiro SA (Petrobras) has confirmed the presence of oil in the Pitu area of the Potiguar basin after drilling the Pitu North 1 extension well, the first such well drilled in the area.

The discovery was first reported in December 2013. Pitu North 1, also known as 3-BRSA-1317-RNS, 60 km offshore Rio Grande do Norte state, was drilled to a total depth of 4,200 m in 1,844 m of water.

The company says the find was proved by analyzing profiles and fluid samples that will be further analyzed in a laboratory.

Petrobras is operator of the BM-POT-17 concession with 40% interest. Partners are BP PLC 40% and Petrogal SA 20%.

Antelop-4 ST-1 finds more gas onshore PNG

The Total SA-led joint venture has confirmed the discovery of a 597-ft column of gas-bearing dolomite with a vertical gas column of 1,112 ft with its Antelope-4 ST-1 sidetrack well drilled in PRL 15 onshore Papua New Guinea.

The Antelope-4 ST-1 well intersected the top of the reservoir 118 ft higher than the original Antelop-4 penetration. Joint-venture partner InterOil Corp. said its interpretation of data from Antelop-4 and Antelope-5 suggests that the field-wide gas-water contact is deeper than previously thought (OGJ Online, Feb. 16, 2015).

Both Elk and Antelope are located onshore in Papua New Guinea's Gulf Province. The JV includes InterOil and Oil Search Ltd. (OGJ Online, Feb. 11, 2015).

Elk-Antelope is estimated to hold 7-9 tcf of gas, which is sufficient enough to supply two LNG trains. There also is a significant liquids component.

The partners intend to begin drilling Antelope-6 in December as part of the appraisal program to define resource for the Papua LNG project.

The JV also is considering an additional appraisal well on the western flank of Antelope field that could add 1-3 tcf of gas equivalent.

Kosmos makes second gas discovery off Mauritania

Kosmos Energy Ltd., Dallas, reported making a second natural gas discovery offshore Mauritania with its Marsouin-1 exploration well, drilled in 2,400 m of water in the northern part of Block C-8.

The discovery, which Kosmos called "significant" and "play-extending," was drilled 60 km north of the company's basin-opening Tortue-1 well, renamed Ahmeyim, which was also drilled on Block C-8 and intersected 351 ft of net hydrocarbon pay in the primary Lower Cenomanian objective (OGJ Online, Apr. 27, 2015).

Based on preliminary analysis of drilling and wireline logging results, Marsouin-1 encountered at least 230 ft of net gas pay in Upper and Lower Cenomanian intervals, the company said.

The Atwood Oceanics Atwood Achiever drillship will now proceed to the Ahmeyim-2 location in the southern part of Block C-8, where it will drill the top-hole section of the well. The drillship is then expected to go to Senegal, where it will spud Guembeul-1, the first in a series of wells to delineate the Greater Tortue area, before yearend.

Drilling & ProductionQuick Takes

Suncor's oil sands output to slow in 2016

Suncor Energy Inc., Calgary, plans to spend $6.7-7.3 billion and produce 525,000-565,000 boe/d in 2016, with a slight decline in oil sands output.

The company says the "budget incorporates flexibility to respond quickly to any further deterioration in market conditions," adding, "Both capital and operating expenditures can be scaled back to ensure the company continues to live within its means."

Suncor in January slashed its previously reported 2015 budget by $1 billion (Can.) and said it would reduce its workforce by 1,000 (OGJ Online, Jan. 14, 2015). The company also said it would trim $600-800 million in operating expenses over the next 2 years.

Growth projects in 2016 are slated to receive 55% of the spending program with a vast majority targeting the upstream segment.

"Our oil sands production is expected to be slightly reduced in 2016 vs. 2015 as a result of significant planned maintenance activities scheduled at various facilities, including our first 5-year full turnaround at the U2 upgrader and major maintenance at Firebag," said Steve Williams, Suncor president and chief executive officer.

"We remain focused on achieving further reliability improvements across our operations," he said. "And, we'll continue to build upon the momentum gained in 2015 in reducing cash costs per barrel at our oil sands operations."

Suncor in October made a $4.3-billion (Can.) bid for Canadian Oil Sand Ltd., which COS rejected (OGJ Online, Oct. 19, 2015). A month earlier, the company agreed to acquire 10% interest in the Fort Hills oil sands project from Total E&P Canada Ltd. for $310 million (Can.) (OGJ Online, Sept. 21, 2015).

WoodMac: Vaca Muerta output to double by 2018

Production from the giant Vaca Muerta shale play in Argentina is expected to double by 2018, according to a new development study from research and consultancy firm Wood Mackenzie Ltd.

While a marked ramp-up can be expected by 2020, the study highlights that oil and gas output in 2016 should be moderate with year-over-year production at 10%. WoodMac estimates total capital spending for 2016 to reach $1.2 billion as companies prepare for full development.

Horizontal wells will become the development of choice as operators are increasingly able to target the most productive intervals of the play, the firm says, adding that it anticipates 200 wells will be brought online in 2015 and fewer in 2016 as vertical wells are phased down. Currently 460 wells are producing.

"YPF [SA] and its [joint venture] partners continue to decrease drilling and completion costs aiming to move into ramp-up and development phases," explained Horacio Cuenca, WoodMac research director for Latin America.

In the Loma Campana block, the horizontal initial production 30-day average is 646 boe/d, up from 443 boe/d in 2014. In the Karnes trough of the Eagle Ford shale in Texas, for example, the first 100 wells' initial production 30-day average was 420 boe/d, while the average rate today is more than double that total.

Cuenca said that more JV deals will be necessary to fully develop Vaca Muerta as YPF will need outside assistance to develop its 6.3 million acres.

WoodMac adds that the "heavy impact of unions on labor costs and political uncertainty" remain among the largest impediments to international investment.

The US Energy Information Administration estimates the Vaca Muerta to hold 308 tcf of dry, wet, and associated shale gas resources.

Funding approved for GMT No. 1 in NPR-A

ConocoPhillips Alaska Inc. reported that the Greater Mooses Tooth No. 1 (GMT1) development in the National Petroleum Reserve-Alaska (NPR-A) has been approved for funding.

GMT1 is slated to cost $900 million gross. Production is expected to come online in late 2018 with 30,000 bo/d gross at peak production.

The project received its permit to drill from the US Bureau of Land Management on Oct. 22 (OGJ Online, Oct. 22, 2015); and the Corps of Engineers 404 permit on Jan. 16. The development will include a new gravel pad, a 7.7-mile road, facilities, and pipelines.

The project will have nine wells to start and capacity for up to 33 wells. Oil will be processed through the existing Alpine Central facility. Construction will begin in early 2017 and continue into 2018.

GMT1 will produce from lands owned by Kuukpik Corp., Arctic Slope Regional Corp., and BLM. The project will be operated by ConocoPhillips Alaska with 78% interest. Anadarko Petroleum Corp. holds the remaining 22%.

ConocoPhillips in October brought new oil on stream through Alpine drill site CD5 (OGJ Online, Oct. 28, 2015); and Kuparuk Drill Site 2S (OGJ Online, Oct. 13, 2015). Approval for viscous oil development at Drill Site 1H North East West Sak (NEWS) in the Kuparuk River unit was announced in March of this year and the start of production is expected in 2017. Also, permits for Greater Mooses Tooth No. 2 were filed in August.

The CD5, GMT1, Kuparuk Drill Site 2S, and 1H NEWS developments represent $3 billion gross in new North Slope projects. Peak gross combined production when all projects are on stream is estimated at 40-50,000 bo/d.


Tallest lift completed for Gulf Coast ethane cracker

The tallest lift has been completed for the 1.5 million-tonne/year ethane cracker at Chevron Phillips Chemical Co. LP's Cedar Bayou petrochemical complex at Baytown, Tex.

A joint venture of Fluor Corp. and Japan's JGC Corp. is performing engineering, procurement, and construction of the cracker and associated offsite components (OGJ Online, Apr. 8, 2014). The project is the first greenfield cracker project in the US in more than a decade and will be one of the largest crackers in the country when completed, Fluor says.

Over the past 3 months, Fluor Corp. says it has executed nine mega-lifts at Chevron Phillips Chemical Co. LP's Cedar Bayou petrochemical complex at Baytown, Tex., by erecting the major pieces of equipment that will be used in the plant's operations. The tallest lift was completed for site's 1.5 million-tonne/year ethane cracker. Photo from Fluor.

Over the past 3 months, Fluor says it has executed nine mega-lifts at the site by erecting the major pieces of equipment that will be used in the plant's operations.

Each lift was more than 275 tons, with three of the lifts weighing more than 500 tons. The final lift, to erect a C2 splitter-used for olefin separation-that is part of the ethane cracker, was more than 250 ft tall and weighed more than 570 tons. Two cranes were needed to lift the unit, which weighs more than 300 cars. All nine lifts were completed safely and on schedule.

Construction has begun on the furnaces and aboveground piping systems. Plans for additional expansion at Cedar Bayou were reported in late 2014 (OGJ Online, Nov. 7, 2014).

BP plans sale of Alabama petrochemical complex

BP PLC is putting up for sale its Decatur, Ala., petrochemicals complex as part of a broader reorganization of the company's global petrochemicals business.

The company says its "refocused petrochemicals strategy is pursuing a competitively advantaged portfolio through world-scale, low-cost facilities that utilize BP proprietary technology including the production of purified terephthalic acid, or PTA, a key raw material in the production of polyester."

BP acquired the Decatur complex in the 1998 merger with Amoco. The facility's 50th anniversary was this year.


TransCanada plans NGTL system expansion

NOVA Gas Transmission Ltd. (NGTL), a wholly-owned subsidiary of TransCanada Corp., has signed contracts for 2.7 bcfd of new firm natural gas transportation service that will require a $570-million system expansion for 2018.

The expansion includes multiple projects that total 88 km of 20-48-in. pipeline, one new compressor, 35 new and expanded meter stations, and other associated facilities.

Applications to construct and operate the various components of the 2018 expansion program will be filed with Canada's National Energy Board between second-quarter 2016 and fourth-quarter 2016. Subject to regulatory approvals, construction is expected to start in 2017, with all facilities expected to be in service in 2018.

The 2018 expansion program will increase the overall investment on the NGTL system beyond the previously reported $7.5 billion in projects.

The company says $2.8 billion of those projects have received regulatory approval, with $800 million under construction, and an additional $1.7 billion of facilities are under regulatory review.

Significant growth in unconventional gas supplies in northwestern Alberta and northeastern British Columbia are the primary driver for the new contracts, coupled with continued growth in market demand.

Magnolia LNG Lake Charles project advances

Magnolia LNG LLC (MLNG) has signed an engineering, procurement, and construction contract for its four-train, 8-million-tonne/year natural gas liquefaction plant in Lake Charles, La., and received the final environmental impact statement from the US Federal Energy Regulatory Commission.

MLNG's lump-sum, turnkey EPC contract, worth $4.354 billion, is with a joint venture of KBR Inc. and SK Engineering & Construction, to be led by KBR.

The project includes the liquefaction trains with design capacities of 2 million tpy or greater each, two 160,000-cu-m storage tanks, LNG marine and ship-loading facilities, and supporting facilities.

MLNG's parent, LNG Ltd., developed the project's liquefaction process, called Optimized Single Mixed Refrigerant, which involves ammonia precooling.

FERC's environmental nod covers the LNG project and associated Kinder Morgan Louisiana Pipeline Lake Charles Expansion Project.