OGJ Newsletter

Sept. 23, 2013
International news for oil and gas professionals


Tribunal supports Chevron in Ecuador case

An international tribunal has determined that agreements signed by the government of Ecuador in 1995 and 1998 released Texaco Petroleum Co., now part of Chevron Corp., from environmental liability for land on which it once produced oil.

The ruling upholds an important claim Chevron has made in its years-long defense against a lawsuit claiming billions of dollars for environmental damage (OGJ Online, Feb. 14, 2011).

Texaco produced oil in Ecuador as part of a consortium under a concession that ended in 1992. It operated the group until replaced by the state-owned oil company in 1990. Chevron, which acquired Texaco in 2001, says the company spent $40 million on environmental remediation and was released from further liability. Chevron also argues the environmental damage for which Texaco is blamed occurred after the state company took control of the fields.

The Permanent Court of Arbitration at The Hague earlier ordered a court in Ecuador not to enforce a judgment against Chevron, which claims fraud in the case.

"The game is up," declared Hewitt Pate, Chevron vice-president and general counsel, after the latest ruling by the tribunal. He said the partial award "confirms that the fraudulent claims against Chevron should not have been brought in the first place."

An arbitration hearing on alleged collusion between the Ecuadorian courts and plaintiffs and their lawyers is scheduled next January.

Apache to sell Canadian assets for $112 million

Apache Corp. has agreed to sell certain oil and natural gas producing properties in Canada in two separate transactions for a combined total of $112 million.

Apache has agreed to sell its Hatton, St. Lina, Marten Hills, Snipe Lake, Valhalla, and a portion of its Hawkeye producing properties. These are primarily dry gas developments in Saskatchewan and Alberta and comprise 4,000 operated and 1,300 nonoperated wells that averaged production of 38 Mcfd of gas and 750 bbl of oil, condensate, and natural gas liquids, net to Apache, during this year's second quarter.

The St. Lina and Marten Hills properties were the subject of arbitration proceedings in 2011 when Apache disputed the prices of Canadian assets bought from BP Canada as part of a $7 billion transaction. "Apache alleges that in the future various sites that it acquired from BP Canada Energy pursuant to the parties' July 2010 purchase and sale agreement will have to have work carried out to bring the sites into compliance with applicable Alberta environmental laws," BP said at the time the proceedings were initiated (OGJ Online, March 4, 2011).

Last month Apache sold its Nevis, North Grant Lands, and South Grant Lands assets, which also are in Alberta, to Ember Resources Inc. for $214 million (OGJ Online, Aug. 15, 2013). In addition, it sold 33% of its Egypt operations to Sinopec International Petroleum Exploration & Production Corp for $3.1 billion (OGJ Online, Aug. 30, 2013).

Including transactions involving company properties and assets in Canada, the Gulf of Mexico and Egypt, Apache has announced divestments totaling nearly $7.2 billion.

Oasis adding to its Williston basin assets

Oasis Petroleum Inc. has signed four separate, unrelated purchase agreements to acquire certain assets in the Williston basin totaling 161,000 net acres and costing $1.5 billion.

Thomas Nusz, Oasis chairman and chief executive officer, said the acquisitions add acreage "in the heart of the Bakken and Three Forks play."

The four acquisitions are expected to close in early October. Currently, Oasis of Houston operates 11 rigs and the sellers of the assets involved operate two rigs, he said.

"We expect to accelerate development across our overall combined position next year, increasing to 15 to 16 operated rigs by the end of 2014," Nusz said. "As of June 30, we had approximately 331,000 net acres, and these acquisitions increase our overall acreage position by almost 50% to 492,000 net acres."

Oasis agreed to acquire 136,000 net acres in and around its existing position in North Dakota in its West Williston project area for $1.45 billion. It also signed three other agreements to acquire certain assets in East Nesson totaling 25,000 net acres, for $65 million.

Shell appoints downstream director

Royal Dutch Shell PLC has appointed John Abbott as downstream director, effective Oct. 1. In his new role, Abbott succeeds Ben van Beurden, who will become chief executive officer, effective Jan. 1, 2014 (OGJ Online, July 9, 2013). Abbott will become a member of the company's executive committee.

Abbott currently serves as executive vice-president, manufacturing, responsible for 30 oil refineries and petrochemicals plants worldwide. He joined Shell in 1981, and has held a variety of management positions in refining, chemicals, and upstream heavy oil, working in the UK, Singapore, Thailand, the Netherlands, Canada, and the US.

Exploration & DevelopmentQuick Takes

ConocoPhillips drills sidetrack to Proteus discovery

A joint venture of ConocoPhillips and Karoon Gas Australia Ltd. has confirmed the gas-condensate discovery made last month with the Proteus prospect in the Browse basin offshore Western Australia with a strong test in the Proteus-1 sidetrack well.

Flow rates measured up to 7.3 MMcfd of gas with condensate-gas ratios of 19-22 bbl/MMcf. This is the highest ratio recorded in the group's Poseidon project area (OGJ Online, May 19, 2009). Carbon dioxide levels were about 12%.

Karoon has estimated that production wells would be capable of flowing at rates exceeding 100 MMcfd. The reservoir is in the Plover and Montara formations of Jurassic age.

Proteus-1 is in permit WA-398-P, 17 km east of discoveries at Kronos-1 and 10 km southeast of Boreas-1. It is the third well drilled in the Greater Poseidon region. The field is in a tilted fault block 14 km south-southeast of the Poseidon discovery.

ConocoPhillips is using the Transocean Legend semisubmersible rig for the entire drilling campaign, which involves a minimum of six wells to define the size and quality of the accumulations within the company's permits WA-314-P, WA-315-P, and WA-398-P. Drilling will continue into 2014.

Testing starts on second Tawke horizontal well

Extensive testing has started on a second horizontal well that was drilled in Tawke field in the Kurdistan Region of Iraq, said DNO International ASA, Oslo.

The exploration well, Tawke-23, has encountered continuous oil shows within a 930-m horizontal section in Tawke field's main Cretaceous reservoir. The test program, expected to last up to 3 weeks, will focus on ten fracture zones with production potential, DNO said.

The company's first horizontal well in the field, Tawke-20, tested 8,000 b/d from each of ten producing intervals in the Cretaceous reservoir and is currently on stream at an average rate of 25,000 b/d (OGJ Online, July 22, 2013).

Also drilling in Kurdistan are two Tawke horizontal wells, Tawke-21 and Tawke-22, and the highly deviated Benenan-4 well in the Erbil license to appraise the reserves found in Benenan field by the Benenan-3 well (OGJ Online, Nov. 7, 2012).

DNO to develop Summail gas field in Kurdistan

DNO International ASA will deliver gas starting in January 2014 from Summail field to a Dohuk power plant, the first commercial domestic gas sales deal in the Kurdistan Region of Iraq.

The agreement with the Kurdistan Regional Government calls for initial deliveries of about 100 MMcfd on a take-or-pay basis for the duration of the Dohuk production-sharing contract or until deliveries reach 1 tcf. Price will range between $3/Mcf and $4/Mcf over the life of the contract.

The gas will help displace diesel used to generate electricity in a 500-Mw power plant in Dohuk city 40 km from the field.

The next step in Summail's fast-track development is reentry and completion of the Summail-1 discovery well and the installation of a 24-in. pipeline to transport gas to what is slated to become the regional gas gathering and distribution network. A second well, Summail-2, is to spud in this year's fourth quarter, and Summail-3 is set for 2014.

Following Summail field development, the company will shift its focus to appraise the oil potential of the Dohuk license.

DNO International has a 40% interest in and operates the Dohuk license. Genel Energy PLC has 40% and the KRG 20%.

Development of Summail field will help lower costs and grow and diversify DNO International's production and revenue base, said Bijan Mossavar-Rahmani, DNO International's executive chairman.

Flow test confirms Po Valley gas discovery

The Gradizza-1 gas discovery well on the La Prospera permit in Italy's Po basin has flowed gas at rates of 175-250 Mcfd, which one participant said affirms the viability of a number of analogous drillable prospects on the adjacent Ponte del Diavolo permit.

Operator Po Valley Energy Ltd. flowed the gas from perforations at 2,808-22 ft in a formation of Quaternary age. Initial flowing tubing pressures averaged more than 220 psi.

The well had a drilling break in the target Pleistocene-age sand interval, and after coring and logging, operations confirmed the presence of a gas-bearing reservoir exceeding 33 ft. Initial shut-in pressure is 1,110 psi on 27⁄8-in. tubing, indicating original pressures, said BRS Resources Ltd., Dallas. The well has not yielded water but is still cleaning up.

BRS is participating in the well through its membership interest in AleAnna Resources LLC. Under a farmout between PVE and AleAnna, AleAnna may earn a 10% interest in the Gradizza prospect and La Prospera permit.

Lukoil starts exploratory drilling off Sierra Leone

OAO Lukoil has started exploratory drilling offshore Sierra Leone on the West African shelf. The Savannah well's target depth on Block SL-5-11 exceeds 4,700 m. The 52,500-ton Eirik Raude semisubmersible drilling rig is drilling in 2,000 m of water.

Lukoil said 2D and 3D seismic data were acquired on 1,500 sq km, which led to identification of several prospects.

The current exploration period will expire Dec. 31. Obligations for the next exploration period will depend on drilling results.

Lukoil has 49% of the block; Nigeria's Oranto has 30% and PanAtlantic, 21%.

Drilling & ProductionQuick Takes

Shell starts Prelude drilling

Royal Dutch Shell PLC has started drilling the first of its seven development wells in Prelude natural gas field in the Browse basin offshore Western Australia. It is using the Noble Clyde Boudreaux drilling vessel.

The drilling campaign is expected to last 2 years with the vessel serviced out of Broome on the Kimberley coast.

The Prelude project is expected to be the world's first floating LNG (FLNG) facility. It will tap into an initial reserve base of 3 tcf of gas and condensate contained in the Prelude and nearby Concerto fields.

Shell laid the keel for the FLNG vessel in May. The hull will be assembled in dry dock before the turret and topsides are fitted at Samsung Heavy Industries' Geoje shipyard in South Korea.

PDC Energy halts production amid Colorado flooding

Widespread flooding and numerous road closures in Weld County, Colo., has forced PDC Energy Inc. to suspend gas production operations Sept. 13 from a limited number of wells in Wattenberg field. The company expects to return the majority of suspended wells to production this week.

"As our first concern was for the safety of our employees in the field and to minimize any impact to the environment, we elected to shut-in production sites before they became inaccessible due to road closures and flood conditions," PDC Energy said. "Beginning today we are assessing impacts to individual well sites and expect a full assessment as the flood waters recede this week. We plan to access the well sites using alternate routes around impacted roads and bridges and anticipate the majority of the impacts to operations will be short-term."

PDC operates 2,300 vertical and 80 horizontal wells in Wattenberg field. Its holdings in Wattenberg field include the horizontal Niobrara and Codell plays (OGJ Online, Feb. 6, 2013).

Magellan signs gas supply deal for Dingo field

Magellan Petroleum Corp. has signed a deal with Northern Territory Power & Water Corp. for long-term supply of gas from Dingo field in the Amadeus basin in central Australia.

The 20-year contract ensures the supply of as much as 30 bcf of gas to NTPWC on a take-or-pay basis.

Gas will begin to flow in early 2015 at a fixed but undisclosed price, which will escalate with the Australian consumer price index.

Magellan will soon begin design, construction, and commissioning of the surface facilities at Dingo as well as a tie-in pipeline to the main central Australian trunk line from Alice Springs to Darwin. Currently the work is in front-end engineering and design stage.

Dingo was discovered in 1981 about 60 km south of Alice Springs and southeast of the larger Palm Valley gas field. Reserves were fixed during a four-well exploration-appraisal program during the 1980s and 1990s, but with no customer demand till now the field has lain dormant.

Magellan will produce gas from three of the four wells.


EPP starts up seventh Mont Belvieu fractionator

Enterprise Products Partners LP (EPP) has started operations at its seventh NGL fractionator at Mont Belvieu, Tex., east of Houston. This seventh unit and an eighth at the site are being developed as part of a joint venture with Western Gas Partners LP, an affiliate of Anadarko Petroleum Corp., Houston. EPP will operate the new units and own 75%, while Western Gas holds 25% in each of the two fractionators.

The new unit, which can fractionate up to 85,000 b/d of NGL, increases total fractionation capacity at EPP's Mont Belvieu site to 570,000 b/d (OGJ Online, Nov. 1, 2012). The company said the new fractionator will "facilitate increasing NGL production from domestic shale plays, including the Eagle Ford in South Texas, and other basins in the Rocky Mountain and Midcontinent."

EPP Chief Executive Officer Michael A. Creel said work on an eighth fractionator is ahead of schedule and should be in service by the middle of this year's fourth quarter. Fractionators Nos. 7 and 8 will increase total capacity at Mont Belvieu to 655,000 b/d, compared with 400,000 b/d 3 years ago.

System-wide, said Creel, EPP's fractionation capacity will expand to more than 1 million b/d with the addition of the two new NGL fractionators.

Lukoil resumes operations at Ukrainian plant

A unit of OAO Lukoil has resumed operations at a petrochemical plant in Kalush, Ukraine, after a year of suspension.

Karpatneftekhim has the capacity to produce 300,000 tonnes/year of polyvinyl chloride, 200,000 tpy of caustic soda, 180,000 tpy of chlorine, 250,000 tpy of ethylene, and 100,000 tpy of polyethylene.

Operations were suspended in September 2012 "due to unfavorable conditions in the petrochemical market," the company said. In April, Ukraine's cabinet of ministers and Lukoil signed a memorandum "to bring the plant to a cost-effective production level." A large-scale upgrade of the plant occurred during 2008-11.

Khabarovsk refinery upgrade under way

Alliance Oil Co., Moscow, is upgrading its 90,000 b/d Khabarovsk refinery in Russia's Far East in a project that will push capacity to 100,000 b/d this year.

It has let a contract to Foster Wheeler AG's Global Engineering & Construction Group covering construction management services for a segment of the work it calls the hydroprocessing project.

The complex covered by the contract includes a hydrocracker, hydrotreater, hydrogen unit, amine regeneration unit, sour water stripper, sulfur recovery unit, vapor recovery unit, waste water treatment unit, ground flare, tank farm, and pump houses. The hydrogen unit will use Foster Wheeler technology for steam methane reforming.

Alliance last October said it invested $1 billion of a planned $1.4 billion for the upgrade. Projects completed at that time included installation of a 350,000 tonne/year catalytic reformer and conversion of the refinery to use of gas from fuel oil as operating fuel.

Last year Alliance completed an upgrade of an isomerization unit, bringing capacity to 120,000 tonnes/year. Alliance expects to begin delivery gasoline meeting Euro-5 standards this year. Alliance also is working on a pipeline connection to the East Siberia-Pacific Ocean crude oil pipeline. A first phase includes construction of a transfer unit and 28-km pipeline. Completion of the first phase will allow the refinery to receive 40,000 b/d from the ESPO pipeline next year.

A second phase, including construction of a pump station and upgrade of an existing pump station by pipeline owner Transneft, will increase delivery capacity to the refinery to 100,000 b/d in 2015.


Pembina to expand crude-by-rail terminalling

Pembina Pipeline Corp. acquired a site in the Alberta Industrial Heartland to support future development of a rail, terminalling, and storage complex to be called the Heartland Hub. The site features an existing rail system and utility infrastructure. Heartland Hub is a further build-out of Pembina's larger Nexus terminal (PNT), providing crude oil and diluent customers with terminalling, storage, and rail.

The site is in close proximity to major oil sands pipeline rights-of-way, existing crude oil and petrochemical infrastructure, and Pembina's Redwater site, the company said. Pembina expects Heartland Hub to provide interconnectivity via pipeline and rail to refining markets. The company described Heartland Hub as an integral part of PNT, which interconnects Pembina's terminalling infrastructure in the Edmonton, Redwater, and Fort Saskatchewan areas.

Key features of the acquisition noted by the company include 232 acres of well-developed industrial land; more than 5,000 linear ft of rail track, currently serviced by CN Rail; 160 acres of adjacent, existing Pembina land, which can be developed for future merchant storage and rail expansions; 1,280 acres of Pembina salt rights, close enough to support future cavern development; and the ability to access more than 4-million b/d of existing and future oil sands and conventional crude through current and potential pipeline interconnections.

Pembina also entered into a multiyear agreement with a major North American refiner to load up to 40,000 b/d of oil railcars using existing PNT infrastructure, starting immediately.

Gazprom signs terms for pipeline natural gas

Gazprom and China National Petroleum Corp. signed an agreement covering major terms and conditions of supplying natural gas from Russia to China via the eastern route, in accordance with terms previously reached. Earlier negotiations covered the supply of 30 billion cu m (bcm)/year over 30 years starting in 2015. Pricing will not be linked to the Henry Hub.

Previous talks focused on Gazprom's Eastern Gas Program (EGP) as favorable to the signing of long-term gas supply deals from Russia to China. Gazprom began building the Sakhalin-Khabarovsk-Vladivostok (SKV) gas transmission system as a key component of the EGP in May 2009. The 1,830-km pipeline entered service in September 2011 at an initial capacity of 7 bcm/year, expandable to 47 bcm/year.

Gazprom last year began work on production wells in the Kirinskoye gas-condensate field in the Sea of Okhotsk. The company had previously completed a 139-km onshore pipeline to carry processed gas from the field to the SKV system's Sakhalin main compressor station (OGJ Online, Aug. 6, 2012).

Last year it also indicated plans to accelerate work on the EGP, including a pipeline between Yakutia and a tie-in to SKV at Khabarovsk (OGJ Online, Sept. 17, 2012). The 3,200-km pipeline will parallel the Eastern Siberia-Pacific Ocean crude oil trunkline, entering service in late 2017 with an eventual capacity of 61 bcm/year. Gazprom maps published at the time showed plans to export gas to China through this pipeline at Blagoveshchensk and the SKV pipeline at Dalnerechensk.

Point Thomson pipeline completion near

ExxonMobil Corp. said it expects work to be completed this winter on a pipeline that will carry condensate from the Point Thomson Unit on Alaska's North Slope to the Trans-Alaska Pipeline System (TAPS). The company said condensate production will start at a rate of 10,000 b/d. The pipeline will have capacity of 70,000 b/d.

According to government filings, the elevated, 22-mile, 12-in. pipeline will connect the Point Thomson central production facility with BP's Badami oil pipeline, which connects with TAPS.

An agreement reached last year to start condensate production by the 2015-16 winter moved leaseholders—which also include BP, ConocoPhillips, Chevron, and Leede—and the state away from a 7-year deadlock over how to develop Point Thomson's reserves and transport production (OGJ Online, Apr. 9, 2012). The unit is a retrograde condensate reservoir with gas reserves estimated at 8 tcf.

ExxonMobil said Worley Parsons Group Inc., the primary EPC management contractor has awarded two subcontracts to CH2M Hill Alaska related to the next phases of development:

  • For installation of production system modules, the main components of the permanent Point Thomson facilities. The subcontractor will work with ASRC Energy Services and Delta Construction on field activities beginning in 2014.
  • For fabrication and installation of the standby power-generation module, which will provide backup power for the entire facility in 2014.