General Interest — Quick Takes
European energy grants total €2.3 billion
The European Commission has selected 31 gas and 12 electricity projects to receive grants totaling a record €2.3 billion for energy infrastructure.
The investments are part of almost €4 billion set aside in March 2009 for European economic recovery. They reflect desires by the European Union to interconnect member states and reduce isolation of outlying members such as the three Baltic states, Ireland, and Malta.
The spending will help provide for emergency pipeline flow reversal in nine EU countries and support the Nabucco gas line between Turkey and Germany and the Galsi line between Algeria and Italy. The EU investments, expected to encourage industry commitments of as much as €22 billion, will be allocated over the next 18 months.
The €1,390 million identified for 31 gas line projects includes €200 million for Nabucco, €200 million to increase capacity of the France-Belgium interconnection, over €175 million to develop gas interconnections between France and Spain, €120 million for the Galsi pipeline, and €35 million for the Germany-Belgium-UK pipeline.
An LNG terminal at Poland's port of Swinoujscie will receive €80 million, while infrastructure and equipment to reverse pipeline flow of gas in the event of short-term supply disruption will be granted €79.5 million.
Quest companies emerge as PostRock Energy
Shareholders and unitholders of Quest Resource Corp., Quest Energy Partners LP, and Quest Midstream Partners LP approved a recombination as PostRock Energy Corp., Oklahoma City.
PostRock Energy said the action will make it more competitive by allowing it to increase development activity, further reduce costs, improve operational efficiency, and simplify the organizational structure.
Vertically integrated PostRock Energy owns more than 2,800 wells and nearly 2,200 miles of natural gas gathering pipelines and is the largest gas producer in the Cherokee basin of Southeast Kansas and Northeast Oklahoma. It owns nearly 400 gas and oil producing wells and undeveloped acreage in the Appalachian basin of the northeastern US. It owns more than 1,100 miles of interstate gas transmission pipelines in Oklahoma, Kansas, and Missouri.
Shell, PetroChina make offer for Arrow Energy
Royal Dutch Shell PLC and PetroChina have made a joint takeover offer worth $3.3 billion (Aus.) for Brisbane-based coal seam methane gas (CSM) player Arrow Energy Ltd.
Arrow has received the nonbinding conditional bid from a company jointly owned by Shell and PetroChina under which Arrow shareholders would receive $4.45 (Aus.)/share in cash plus one share in a new company comprising Arrow's international business.
Arrow had been planning to list 20% of its international arm on the Singapore or Hong Kong stock exchanges after an initial public offering to be held during the first half of the 2010-11 financial year. As of Mar. 8, the company recommended that its shareholders take no immediate action in relation to their shares.
Observers say the bid has been sparked by the recent ownership restructure of Arrow's planned Fisherman's landing CSM-LNG project in Gladstone—in particular a potential sell-down of Arrow's interest in its domestic CSM acreage to help fund the cost of the project, which has worried Shell.
Shell already holds 10% interest in these assets as well as a 10% stake in Arrow's international business.
Arrow's recent fall in share price, its increase in CSM reserves and its move to acquire 100% of the Fisherman's Landing project have combined to make the company an attractive takeover target.
The move marks another step by the majors into the CSM-LNG projects in Queensland. It follows BG Group's $5.6 billion (Aus.) buy-out of Queensland Gas Co. in 2008 and ConocoPhillips's $9.6 billion (Aus.) investment in Origin Energy's Queensland CSM-LNG project soon afterwards.
Exploration & Development — Quick Takes
Atlas sees 13 tcfe net Marcellus recoverable
Atlas Energy Inc., Pittsburgh, said it has identified more than 3,150 horizontal Marcellus shale drilling locations on its acreage from which it estimates the net incremental recovery is 13 tcf of gas equivalent.
The figures assume 1,000-ft spacing between laterals, and Atlas noted that downspacing could result in more horizontal locations and reserve potential.
The company listed 1.02 tcfe of proved reserves. Its reserve report includes 73 Marcellus shale horizontal locations as proved developed. Atlas replaced more than 8.5 times its production in 2009.
About 52% of the company's proved reserves, and 99% are natural gas. Most of its Marcellus properties are in southwestern Pennsylvania.
Atlas incurred total capital costs of $109 million drilling and completing wells in 2009, which was comprised of its own investments in drilling partnerships it sponsored as well as the cost of wells drilled directly for its own account.
In 2010, having improved cash flow through in a transformation from a master limited partnership making large distributions into an operating entity reinvesting cash flow in operations, Atlas plans to hike its reserves and cash flow at an increased rate by drilling most horizontal Marcellus shale wells for its own account, the company said.
None of the proved undeveloped locations in the company's 2009 reserve report are more than one offset away from another proved undeveloped location, although farther offsets are permitted by new federal rules.
In Appalachia, Atlas Pipeline Partners LP is a 49% joint venture partner with Williams Cos. in Laurel Mountain Midstream LLC, which manages the gas gathering system in that region, namely from the Marcellus shale in southwestern Pennsylvania.
MOL tests Bijeel oil find in Iraq Kurdistan
A unit of MOL Hungarian Oil & Gas PLC has gauged oil and gas at the Bijeel-1 exploratory well in Iraqi Kurdistan.
The well, in the east-central part of the 889 sq km Akri Bijeel block, flowed at rates of as much as 3,200 b/d of 18° gravity oil and 933 Mscfd of associated gas at 420 psi flowing wellhead pressure on a 48⁄64-in. choke. The tested zone is in the Upper Jurassic.
MOL's Kalegran Ltd. has an 80% undiluted equity working interest in the block, and Gulf Keystone Petroleum Ltd., Hamilton, Bermuda, has 20%.
After completion of the full test cycle, drilling will resume from the present depth of 3,831 m to a final planned depth of 4,400 m pending actual well results, Gulf Keystone said.
The Akri Bijeel block is north of Erbil and just east of the Shaikan Block, where the two companies reported the Shaikan-1 oil discovery last August (OGJ Online, Aug. 11, 2009).
The companies were awarded the Shaikan and Akri Bijeel blocks in late 2007, and in July 2009 Gulf Keystone announced the award of interests in production sharing contracts covering the Sheikh Adi and Ber Bahr blocks west of Shaikan.
Etamic Ltd., an independent energy fund founded for the purpose of making investments in the upstream oil and gas exploration and production business in the Middle East and Central Asia, negotiated for the award of the Sheikh Adi PSC and the assignment of an interest in the Ber Bahr PSC.
Gulf Keystone proposed and it was agreed that Etamic merge these interests with Gulf Keystone's existing interests in exchange for Gulf Keystone shares conferring Etamic a 50% equity interest in GKPI. Etamic will fund 50% of the costs to be incurred by Gulf Keystone following the drilling of Shaikan-1 and Bijeel-1.
Gulf Keystone will operate the 180 sq km Sheikh Adi Block with 80% interest, and Genel Energy International Ltd. will operate the 350 sq km Ber Bahr block with 40% interest and Gulf Keystone will have 40% interest.
The block interests obtained through Etamic are at terms far more favorable than those of the Shaikan and Akri Bijeel blocks, Gulf Keystone said.
Anadarko, Origin to drill Canterbury deep water
An Anadarko Petroleum Corp. unit will operate a frontier exploratory well with Origin Energy Resources NZ Ltd. in the nonproducing Canterbury basin east of New Zealand's South Island.
The companies will drill to an unstated depth to test the Cretaceous Kawau and Herbert formations on the twin-crest Carrack-Caravel prospect in 3,300 ft of water 40 miles east of Dunedin in the southern part of the basin. At Cretaceous level the prospect covers more than 390 sq km, compared with 160 sq km at Maui, New Zealand's largest gas field.
Both formations contained hydrocarbons in the BP-Shell Todd Galleon-1 well that went to a total depth of 10,100 ft in 298 ft of water 18.6 miles northwest in 1985 (see map, OGJ, Feb. 3, 2003, p. 47).
Anadarko, which at its expense reprocessed Origin's 2009 3D seismic data, will earn a 50% interest in PEP 38262 by paying the first $30 million of drilling costs. The firms will share costs 50-50 after that. PEP 38262 extends from south of Dunedin to south of Christchurch.
Drilling a well becomes a permit commitment after Aug. 21, and the companies likely will drill in 2011. They are seeking a suitable rig and wish to share mobilization costs with other operators. Anadarko has an option to acquire for $100,000 a 50% interest in PEP 38264, which adjoins 38262 seaward, by Apr. 8.
Origin Energy said, "Seismic data over the structure is characterized by the presence of amplitude anomalies that conform to structure at the level of inferred Cretaceous reservoirs. More localized anomalous seismic responses are also observed in the overlying Tertiary sequence, which are interpretable as gas-charged reservoirs shallower in the section."
The Galleon well flowed 10.6 MMcfd of gas and 2,240 b/d of condensate from Cretaceous sandstones at about 9,000 ft.
Origin Energy previously said Carrack-Caravel could hold a mean of 750 million bbl of recoverable oil or 2.7 tcf of gas and 500 million bbl of condensate in Herbert formation reservoirs. If Kawau sandstone reservoirs also trapped hydrocarbons, the recoverable volumes could more than double.
Drilling & Production — Quick Takes
Grizzly files Algar Lake oil sands plans
Grizzly Oil Sands ULC submitted applications to the Alberta Energy Resources Conservation Board and Alberta Environment for developing the 11,300 b/d Algar Lake steam-assisted gravity drainage oil sands project.
The project is about 45 km southwest of Fort McMurray and near the JACOS Hangingstone and Connacher Great Divide oil sands developments.
The project will have an average 10,000 b/d production capacity during its 30-year life, according to Gulfport Energy Corp., an Oklahoma City-based independent that holds about a 25% interest in Grizzly.
Gulfport described the project as consisting of two 5,000 b/d plants and 40 well pairs on four well pads. It said upon regulatory approval, Grizzly intends to construct the first phase consisting of one modular central processing facility, ten well pairs on one well pad, and associated roads and pipelines. These would be followed in 2 years by a second modular central processing facility and ten addition well pairs on one well pad.
Gulfport said the initial gross capital cost of each phase will be about $120 million. To maintain production, the project also will require an additional well pad for each phase every 5 years at an estimated cost of $35 million/pad.
During the project's life, Grizzly plans to drill about 100 well pairs from 10 well pads. It expects each well pair to produce for 5-7 years.
Engineering firm McDaniel & Associates has estimated that the project will recover about 89 million bbl of bitumen.
Grizzly expects regulatory approvals within 12-18 months and to start production in about 18 months after obtaining the approvals. Grizzly started delineating the area during the 2007-08 winter season and has subsequently drilled 61 core holes and shot 3D seismic on the acreage.
Deepwater drillship starts work off India
The new Dhirubhai Deepwater KG2 drillship, owned by a joint venture of Transocean Ltd. and Pacific Drilling Ltd., has begun work under a 5-year contract with Reliance Industries Ltd. off India.
The dynamically positioned drillship, with a variable deckload of about 20,000 tonnes, can drill to 35,000 ft in 12,000 ft of water.
Syncrude to increase oil sands processing capacity
Canadian Oil Sands Trust said that based on preliminary scoping and design work the debottlenecking of Syncrude Canada Ltd.'s existing Mildred Lake upgrading facility, 40 km north of Fort McMurray, Alta., would increase the facility's capacity to 425,000 b/d of synthetic crude oil by 2020, compared with the current 350,000 b/d capacity.
The debottlenecking projects involve accessing the excess coking capacity constructed during Syncrude's last expansion, making modifications to other facilities, and potentially adding new ancillary units. The debottlenecking would eliminate the need to build a new upgrading facility, Canadian Oil Sands said.
The undeveloped Aurora South mine will supply the bitumen for the debottlenecked facility. Syncrude plans to start construction of the first 100,000 b/d mining train on Aurora South in about 2012, with production expected by yearend 2016. A second 100,000 b/d train would follow, with construction starting in 2014 and production expected by 2020.
After construction of these trains, Canadian Oil Sands said Syncrude will have a 600,000 b/d bitumen production capacity or about 115,000 b/d more than its upgrading capacity.
It said Syncrude is considering incorporating new technology in the construction of the Aurora South mine trains to improve bitumen recovery, energy efficiency, and product quality. The improved product quality would allow for pipeline transportation and sales of surplus bitumen and broaden Syncrude's production from the current light, sweet synthetic blend to a slate including heavy and sour blends.
Aramco orders coiled-tubing drilling systems
Saudi Aramco awarded Baker Hughes Inc. a 2-year contract for two fit-for-purpose coiled-tubing drilling rigs for reentering existing wells and drilling horizontal laterals into untapped reservoir sections of southern Saudi Arabia gas fields.
Saudi Aramco plans to drill the laterals underbalanced to minimize formation damage.
Baker Hughes will provide project management oversight and downhole drilling and completion services, including its CoilTrak steerable drilling system deployed on coiled tubing.
The drilling will also use Baker Hughes's newly developed rib-steering motor, designed for coiled-tubing applications.
The contract has an option for a 1-year extension, with drilling expected to start in the second quarter.
Oil production restarts from Woollybutt
Oil production has restarted from Woollybutt field off Western Australia after being offline for a year, said joint-venture partner Eni SPA.
The field was shut in on Apr. 28, 2009, to enable the Four Vanguard floating production, storage, and offloading vessel—now renamed Four Rainbow—to undergo a scheduled dry dock for extensive life extension refit.
After various checks and ramp-up procedures are completed during the next few weeks, Woollybutt production is expected to return to levels of 8,000-9,000 b/d.
Four Rainbow's refit will enable the vessel to remain at the field until it is depleted, forecast to be 2013.
Eni operates Woollybutt field with 65%. JV partners are Tap Oil Ltd. 15% and ExxonMobil Corp. 20%.
Processing — Quick Takes
Contract let for Camisea cryo plant
Pluspetrol Peru Corp. SA, operator of Peru's Camisea natural gas project, has hired CB&I, Houston, to supply a cryogenic natural gas processing plant in Malvinas as part of an expansion of the project.
Pluspetrol awarded the $45 million contract in its capacity as operator and contract administrator, acting for the licensees, said a CB&I announcement.
CB&I will provide engineering, procurement, and modular fabrication of a plant with inlet capacity of 520 MMscfd of gas. The unit, scheduled for completion later this year, will treat gas produced from Pagoreni field and separate natural gas liquids.
CB&I has been involved in Camisea since its beginning, supplying four cryogenic plants at Malvinas, as well as a fractionation and topping plant at Pisco, and the refrigerated and atmospheric storage tanks on the site.
Contract let for GTL plant in Uzbekistan
Uzbekistan GTL LLC has let to Technip a reimbursable services contract for a detailed feasibility study of the gas-to-liquids project it plans to build 40 km south of Qarshi, Uzbekistan (OGJ, Nov. 16, 2009, p. 20).
Uzbekistan GTL is a joint venture of state-owned Uzbekneftegas, Sasol Synfuels International of South Africa, and state-owned Petronas of Malaysia.
The plant would use the proprietary Sasol Slurry-Phase Distillate process to produce about 1.3 million tonnes/year of diesel, kerosine, naphtha, and LPG.
Transportation — Quick Takes
Williams solicits shippers for Transco expansion
A unit of Williams Partners LP has initiated a binding open season Mar. 4-26 for expansion of its Transco natural gas pipeline, providing incremental firm gas transportation capacity from the Marcellus shale to markets in New York and New Jersey.
The Northeast Supply Link expansion project is designed to provide 420 MMcfd firm service on the Transco line from interconnections accessing Marcellus production along its Leidy line in Pennsylvania to its Station 210 pooling point and existing New York City delivery points. Transco has executed a precedent agreement with an anchor shipper for 200 MMcfd, with the remaining 220 MMcfd offered through the open season.
Subject to regulatory approval, Williams expects the first phase of the project to enter service in November 2012, adding 120 MMcfd. The second phase would follow in November 2013, bringing the expansion to full capacity.
Williams Cos. Inc. entered joint ventures in 2009 with both Rex Energy Corp. and Atlas Pipeline Partners LP fortifying its position in the Marcellus shale (OGJ Online July 9, 2009 and Apr. 2, 2009). The partnership with Atlas is a 51% holding in Laurel Mountain Midstream LLC, which manages the gas gathering system in the Marcellus shale region of southwestern Pennsylvania.
Prelude FLNG plans advanced
Royal Dutch Shell PLC has signed two contracts with Technip and Samsung Heavy Industries related to the company's plans to establish a floating LNG (FLNG) facility at Prelude field in the Browse basin off Western Australia.
The first contract relates to front-end engineering and design aspects of the Prelude project taking into account the composition of gas, local weather conditions, and other site-specific parameters. The second details the terms under which the FLNG will be built.
The two contracts follow a master agreement signed in July 2009 between Shell and the Technip-Samsung joint venture to work on the design, construction, and installation of multiple FLNGs over a 15-year period.
Prelude has estimated reserves of 2.5-3 tcf of gas and 120 million bbl of condensate. Nearby Concerto field, which is likely to be tied into the development, has not been allocated an official reserves figure. Both fields lie in permit WA-371-P.
The Prelude FLNG development is earmarked to produce 3.5 million tonnes/year of LNG. A final investment decision is scheduled for early 2011, from which point it is expected to take 5 years for the FLNG vessel to be built in Korea and towed to the field located 475 km north-northeast of Broome.
Production would begin from eight subsea wells tied back to subsea manifolds and connected to the FLNG via flowlines. If all goes to plan, first gas production should begin in 2016.
ExxonMobil, Mitsui sign LNG carrier deals
Mitsui OSK Lines has signed separate deals with ExxonMobil Corp. for the construction and charter of LNG carriers earmarked for the Papua New Guinea LNG and Gorgon-Jansz LNG projects.
For PNG LNG, Mitsui will charter two existing 177,000-cu m capacity carriers co-owned by Itochu Corp.
Mitsui also entered two heads of agreement for the construction and long-term charter of four other LNG carriers for the PNG LNG and Gorgon-Jansz projects. The vessels will be built in China with delivery dates scheduled for 2014-16. First LNG from both projects is expected in 2014.
The ExxonMobil-operated PNG LNG project will cost $15 billion and have a production capacity of 6.6 million tonnes/year of LNG.
The Chevron Corp.-operated Gorgon-Jansz project (in which ExxonMobil has 25%) will have a production capacity of 15 million tpy of LNG plus a 300 TJ/day gas component via a pipeline to the mainland.
China to increase LNG imports, facilities
The head of China's National Energy Administration, reiterating earlier remarks, announced plans to construct more LNG terminals, pipelines, and storage facilities in southern Guangdong province as part of an effort to secure greater imports of LNG for the region.
Zhang Guobao, China's top energy official, did not provide more details about possible new terminals to be approved or built in Guangdong, which already has one LNG terminal in operation—that operated by CNOOC. Earlier, Zhang said China would build more terminals in Shandong province and at Zhuhai in Guangdong province. CNOOC, described as China's leading LNG project developer, has plans for a second facility near its first one and for another one in Zhuhai, while PetroChina has plans for a terminal at the mouth of the Pearl River in Guangdong province.
CNOOC also is reported to be considering two additional terminals in the eastern and western parts of Guangdong province, which is China's leading consumer of LNG as it has no access to piped gas produced from inland provinces.
Zhang made similar remarks last month, when he said that domestic Chinese firms should "grasp the opportunity that the global LNG market is oversupplied to sign more long-term LNG imports deals."
Given the amount of LNG in the global market, Zhang said China hopes to have more options, and is looking to extend sourcing beyond traditional suppliers like Indonesia and Australia to Malaysia, Qatar, and Papua New Guinea. At the time, Zhang said China would accelerate the construction of LNG terminals, gas lines, and storage facilities in coastal areas.
Zhang also noted that China imported 3.5 million tonnes of LNG in 2009, equal to 5 billion cu m (bcm) of gas, accounting for almost 6% of China's total gas consumption in the year. China National Petroleum Corp. on Feb. 4 said it expects China's gas imports will top 10 bcm in 2010, including 6 million tonnes of LNG.
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