OGJ Newsletter

July 23, 2012
International news for oil and gas professionals


BP settles charges from follow-up probe of blast

BP Products North America Inc. has agreed to pay $13 million in fines to settle more than 400 process safety violations at its Texas City, Tex., refinery identified in a 2009 follow-up investigation of a 2005 explosion at the facility that killed 15 workers, the US Occupational Safety and Health Administration reported. BP has resolved 409 of the 439 citations and is expected to abate the others by yearend, OSHA said.

OSHA cited BP for a then-record $21 million in September 2005 after its initial investigation of the accident and reached a deal with the firm requiring it to complete 660 abatement requirements and process safety recommendations in the next 4 years, BP said in its announcement of the settlement.

It noted that in October 2009, OSHA said BP had not met deadlines and other requirements in the 2005 agreement and issued 270 failure to abate notices related to the initial citations as well as 439 new ones. The company settled the 270 allegations stemming from the 2005 agreement in August 2010 and most of the 439 new citations in the latest agreement, BP said on July 12. Discussions will continue on the 30 outstanding notices, it indicated.

OSHA said BP used procedures outlined in the 2010 settlement to reach the latest agreement. BP was required to hire independent experts to monitor its safety improvement efforts and spend another $500 million to improve safety procedures at the 406,000 b/d refinery, OSHA said.

BP said it spent more than $1 billion for safety and infrastructure improvements from 2005 to 2009 in addition to the $500 million specified in the 2010 settlement. The company also has formed a partnership with the United Steelworkers (USW) to establish front-line involvement in process safety management, it said.

DNO drops offer for Calvalley Petroleum

DNO International ASA announced that it has decided against proceeding with its proposed unsolicited takeover offer of $214 million for Calvalley Petroleum Inc.

A Norwegian company, DNO had said on July 5 that it would take its offer directly to shareholders beginning July 12 because Calvalley's board and senior management had not responded to DNO's earlier offer (OGJ Online, July 6, 2012).

On July 6, Calvalley disclosed it had received notice that one of its partners intends to divest its 25% working interest in Yemen's Block 9 to an undisclosed third party.

Under Block 9's joint operating agreement, Calvalley's existing partners have the option to match the offer and acquire either all or their proportionate share of the working interest to be divested. "The opportunity by Calvalley to match the offer on Block 9 may help explain Calvalley's previous reluctance to enter into any meaningful dialogue," DNO said on July 12.

DNO had indicated it was interested in Calvalley's Yemen holdings.

Premier to acquire stake in licenses from Rockhopper

Premier Oil PLC agreed to acquire 60% of Rockhopper Exploration PLC's interest in the North Falkland basin licenses for $1 billion. Upon closing, Premier would become operator of the Sea Lion oil and gas development in the South Atlantic.

The transaction, pending approval from the Falkland Islands government, involves PL023, PL024, PL032, PL033, PL003, and PL004, including the Sea Lion development and an adjacent development area that includes the Casper and Casper South discoveries.

Terms call for Premier initially to pay $231 million, another $48 million to finance Rockhopper's share of future exploration costs, and $722 million to cover Rockhopper's Sea Lion development costs. In addition, Premier agreed to provide standby financing arrangement at Rockhopper's option to cover development expenses beyond the $722 million.

Premier and Rockhopper also announced an Area of Mutual Interest agreement outlining plans for the firms to cooperate on future projects in the North Falkland basin and analogous plays in South Africa, Namibia, and southern Mozambique.

Rockhopper said it retains significant upside in the North Falkland basin through its 40% stake.

The Sea Lion development is in PL032 and PL004b. Rockhopper has said it likely will develop Sea Lion using a floating production, storage, and offloading facility or tension-leg platform with a floating storage unit.

Previously, Rockhopper planned to submit a Sea Lion development plan to the Falkland Islands government by April 2013 (OGJ, Aug. 22, 2011, p. 25). Premier said the acquisition will add an estimated 200 million bbl of contingent reserves together with resources of 175 million boe net. Once on stream, the Sea Lion development is expected to add 50,000 b/d of oil production net to Premier's 60% stake.

The Sea Lion discovery, tested during September 2010 and June 2011, was the first oil to flow to surface in Falkland Islands waters, Rockhopper said.

ERCB approves Quest CCS project in Alberta

The Energy Resources Conservation Board of Alberta has conditionally approved Shell Canada Ltd.'s application for the Quest carbon capture and storage (CCS) project at the Scotford Upgrader north of Edmonton.

The board attached 23 conditions to its approval, mostly about additional data collection, analysis, and reporting. It will require Shell Canada to seek separate approvals for any additions to the project.

ERCB's approval is subject to review by Alberta Environment and Sustainable Resource Development, which might impose additional conditions.

Shell Canada is to decide this year whether to proceed with the CCS project, which would capture and store underground 1 million tonnes/year of CO2 produced by the upgrader.

Shell Canada, with a 60% interest, operates the Athabasca Oil Sands Project, which owns the upgrader and Muskeg River and Jackpine oil sands mines. Other partners are Chevron Canada Ltd. and Marathon Oil Corp., 20% each.

The Alberta and Canadian governments have agreed to invest a total of $865 million in the Quest CCS project (OGJ Online, June 24, 2011).

Exploration & DevelopmentQuick Takes

Tullow's Wawa finds oil in discreet channel system

Tullow Oil PLC said its Wawa-1 exploratory well on the Deepwater Tano license offshore Ghana has intersected oil and gas-condensate in a Turonian turbidite channel system.

Wawa is the first of three remaining exploratory wells to be drilled in the second half of 2012 to close out the exploration phase of the license, Tullow noted.

It found light oil and gas condensate, trapped separately from the Tweneboa-Enyenra-Ntomme fields "and demonstrates once again that liquid rich hydrocarbons are pervasive in this prospective license. We look forward to the drilling of Okure and Sapele in the second half of 2012," the company said.

Wawa-1 encountered 20 m of gas-condensate pay and 13 m of oil pay in turbidite sands. Samples show the oil to be good quality of 38-44° gravity. Wawa, which will be suspended for possible future use, is 10 km north of the Enyenra-3A well, testing the previously undrilled, updip area of the license.

The Atwood Hunter semi submersible rig drilled Wawa-1 to 3,322 m in 587 m of water.

Tullow operates the license with 49.95% interest. Kosmos Energy Co. and Anadarko Petroleum Corp. have 18% each, Sabre Oil & Gas has 4.05%, and Ghana National Petroleum Corp. has a 10% carried interest.

Rialto touts Gazelle appraisal results

Rialto Energy Ltd., Perth, completed drillstem tests at Gazelle field on Block Ci-202 off Ivory Coast and estimated reservoir deliverability at 33 MMscfd with 4-1/2-in. production tubing.

Maximum rates with the 3.5-in. test string were 19.5 MMscfd and an unstabilized 760 b/d of 40° gravity oil from separate sands in the Upper Cenomanian UC-1 reservoir. Downhole equipment limits constrained the gas flow.

Rialto said the Gazelle-P3 ST2 appraisal and well test data obtained will facilitate optimal and timely development and that the offsetting Condor gas discovery demonstrates the block's remaining high impact exploration potential.

The main DST focused on the UC-1C gas reservoir at 2,632.9-2,666.6 m measured depth rotary table, successfully averaging 17.5 MMscfd for 10 hr on a 44/64-in. choke with 1,470 psia flowing wellhead pressure.

Before the oil test, cement bond logs indicated that the zones may not be hydraulically isolated in the wellbore. The UC-1A oil reservoir perforated at 2,678.0-2,713.2 m MDRT achieved an unstabilized flow rate of 760 b/d before gas originating from the overlying gas reservoir via behind-casing channeling prevented further oil flow.

Gazelle-P3 ST1 penetrated the UC-1 reservoirs 800 m from the existing IVCO-14 discovery well and also appraised the Gazelle LC-2 primary gas reservoir. It also successfully penetrated a downdip portion of the high impact, 750 bcf Condor prospect. The ST2 well was then drilled to further appraise and test the UC-1 reservoirs closer to the IVCO-14 well.

The ST1 and ST2 wells are drilled to total depths of 3,685 m RT and 2,979 m RT, respectively. The wells will be suspended for future use.

The rig will spud the Gazelle-P4 well, designed to appraise the UC-2 and UC-4 oil reservoirs, the UC-3, UC-5, and LC-1 gas reservoirs, and obtain another penetration of the LC-2 reservoir. A Condor appraisal well is one of several high impact candidates earmarked for drilling in 2013.

San Leon sees positives in Baltic shale wells

Talisman Energy Inc. and farmee San Leon Energy PLC will proceed to horizontally drill shale formations in Poland's Baltic basin after completing a three-well vertical drilling program with a successful completion, San Leon Energy said.

Talisman drilled the Szymkowo-1 well on the Szczawno concession to 4,551 m and encountered continuous gas shows over more than 600 m of Lower Silurian and Ordovician shales. The gas shows consisted of C1-C3 and are consistent with a potentially wet gas system, San Leon Energy said.

The strongest gas shows were encountered in the Lower Silurian and Ordovician interval, which is estimated to be more than 100 m thick combined. Several intervals had significant gas shows that San Leon Energy believes are related to natural fracturing and possible overpressure.

Talisman retrieved 315 m of continuous core to evaluate the rock properties of the Lower Silurian and Ordovician intervals. An extensive open-hole logging program was performed to further evaluate the potential. Evaluation and interpretation of the core and logs is expected to take up to 6 months in preparation for continued operations in 2013.

The Szymkowo-1 well was completed and cased for future operations that could include pressure testing of the formations and possibly fracturing several intervals.

San Leon Energy expects Talisman to drill and test its first horizontal well in the first half of 2013 as a continuation of Talisman's commitment. Talisman Energy as operator drilled a combined 10,935 m in the Lewino 1G2, Rogity-1, and Szymkowo-1 vertical wells, took about 900 m of shale cores, and operated for 345 days without lost time accident.

San Leon Energy noted that the Szymkowo-1 well results "continue to show the regional variability of the basin and are proof that the deeper parts of the basin are gas charged."

Drilling & ProductionQuick Takes

BP Alaska puts Liberty oil field project on hold

BP Exploration Alaska Inc. indefinitely suspended its Liberty oil field project in the Beaufort Sea offshore Alaska, citing project engineering and economics although the company said it might redesign the project later.

The BP unit had planned to drill wells nearly 2 miles deep and with offsets as long as 8 miles (OGJ, Oct. 2, 2006, p. 37).

Using a land-based rig to drill ultraextended-reach wells into Liberty field, the BP unit initially expected oil production to begin in 2011, ramping up to 40,000 b/d, with an estimated ultimate recovery of 100 million bbl oil.

"After a full review of project engineering and economics, BP has decided not to pursue the proposed Liberty project, in its current form," company spokeswoman Dawn Patience told OGJ. "BP is in the process of working with regulators to discuss the potential forward plans for the project."

Patience said rig modifications necessary to drill the ultraextended-reach wells to BP standards would increase project costs above the original $1.5 billion project estimate.

BP's decision process included a detailed 18-month review of the rig systems, an analysis of the project's risk and economics, and an assessment of the evolving regulatory framework, Patience said.

All three Galapagos fields flowing in Gulf of Mexico

All three wells in the deepwater Galapagos development in the Gulf of Mexico are producing, reports Noble Energy Inc., operator of two of three fields in the complex.

BP PLC started Galapagos development in June at Isabela field, which it operates (OGJ Online, June 12, 2012). It said gross Galapagos production would peak at about 60,000 boe/d.

Since then, Noble has started production from the other fields, Santiago and Santa Cruz. Production from the subsea fields flows to the Na Kika facility operated by BP. The area lies in 6,500 ft of water about 140 miles southeast of New Orleans.

Noble said it will halt appraisal of its subsalt Deep Blue prospect in 5,100 ft of water on Green Canyon Block 723 off central Louisiana, although the initial well and a sidetrack encountered hydrocarbons. Drilling of the sidetrack was interrupted by the moratorium imposed on gulf activity after the Macondo blowout in April 2010.

Dana, Cieco to develop UK North Sea fields

Dana Petroleum PLC and the Japanese upstream exploration and production company Cieco have begun detailed engineering design phase on the $1.5 billion Western Isles development project in the UK North Sea.

Oil production is expected to start in 2015 and plateau at about 40,000 b/d of oil equivalent from Harris and Barra fields, 160 km east of the Shetland Islands and 12 km west of Tern field. Field life is estimated at 15 years. Reserves are 45 million boe plus further potential.

Western Isles involves a subsea development of at least five production and four water injection wells plus two exploration wells tied back to a newbuild floating production, storage, and offloading vessel with oil export using shuttle tankers.

UK government sanction is expected towards yearend, followed by award of the major contracts. Drilling is expected to begin 2013 with subsea installation in summer 2014 and FPSO installation summer 2015.

Gran Tierra defers spending, cites prices

Busy Colombia operator Gran Tierra Energy Inc., Calgary, is targeting $60 million of capital expenditure deferments from its previously announced 2012 budget of $440 million in connection with curtailed production and lower commodity prices experienced this year.

Gran Tierra said the deferred expenditures are expected to be from areas that do not impact production capacity or near-term, high-value reserve addition projects.

Meanwhile, Gran Tierra said its production in the quarter ended June 30 averaged 12,350 b/d of oil equivalent in Colombia, 3,800 boe/d in Argentina, and 150 boe/d in Brazil, 96% of overall volumes being light oil.

Production and sales have been affected by oil delivery restrictions due to disruptions on the Ecopetrol-operated Oleoducto Transandino pipeline in Colombia, the latest of which occurred on July 3. Gran Tierra Energy continued production at a reduced rate while the OTA pipeline was down, selling part of its crude via trucking and storing the excess. The OTA pipeline continues to be offline with production expected to return to normal levels early next week.

Gran Tierra expects its 2012 exit production rate to be 20,000-21,000 boe/d net after royalties, but due to the repeated OTA pipeline disruptions that have occurred to date the firm does not expect to attain that level of production for 2012.


Petronas lets contract for RAPID project

State-owned Petronas awarded a contract to CB&I for the license and engineering design work for five petrochemicals units. The project is part of the new refinery and petrochemicals integrated development (RAPID) project to be located in Johor, Malaysia.

Lummus Technology will be providing technology for a world-scale steam cracker complex comprising ethylene, butadiene, benzene, isobutylene, and MTBE units.

Contract let for Kochi refinery expansion

Bharat Petroleum Corp. Ltd., Mumbai, has let a contract to Engineers India Ltd. (EIL) for consultancy services related to an expansion and upgrade of its Kochi refinery at Ambalmugal in the Indian state of Kerala.

The project will expand oil capacity at the refinery to 15.5 million tonnes/year from 9.5 million tpy. It includes a new crude distillation unit, fluid catalytic cracker, and delayed coker.

EIL will provide consultancy services for project management, process design and residual process design, detailed engineering, procurement, inspection and expediting, tendering, construction management and supervision including quality assurance, and assistance in start-up and precommissioning activities.


Statoil halts production from Hammerfest LNG

Production was halted temporarily by Statoil at Hammerfest LNG on July 10 "as a result of water ingression in the natural gas dryers," the Norwegian state-owned company reported.

Water ingression causes ice formation in the cooling circuit, Statoil said, adding, "Big efforts are being made to get the gas liquefaction plant back on line quickly." Closer inspection will make it possible to say how long the production halt will last, the company said.

Statoil's share of production from Snohvit—the first petroleum development in the Barents Sea—is about 50,000 boe/d.

Hammerfest has no installations above the sea's surface, therefore large amounts of natural gas are sent ashore and cooled down at Hammerfest LNG on Melkoya.

Hammerfest is the world's northern-most and Europe's first LNG export facility.

Total increases stake in Ichthys LNG project

Total SA has increased its interest in the Ichthys LNG project off northwest Australia to 30% from 24%. The 6% comes from Inpex Corp.'s stake in the project, and will help the Japanese firm reduce its debt burden as it negotiates financing for its share in the project's construction.

The move demonstrates the French firm's confidence in the project, says Total Exploration & Production Pres. Yves-Louis Darricarrere. The stake increase, worth an estimated $2 billion (Aus.), also enhances Total's presence in Australia and its position as a supplier to the Asian LNG market. In addition, the higher stake is in line with Total's overall strategy to become a leading LNG player in the world.

The Ichthys project, operated by Inpex, will produce 8.4 million tonnes/year of LNG and 1.6 million tpy of LPG, along with about 100,000 b/d of condensate at peak.

Condensate will be separated out at the central processing platform and sent to a floating storage facility for direct marketing. Dry gas will be transported via an 889-km subsea pipeline to the LNG plant on Darwin Harbor. First gas is slated for 2016.

Total will take 900,000 tpy of LNG from the project.

The company's increased stake does not affect any LNG offtake agreements, however the deal is still subject to Australian Foreign Investment Review Board approval.

Separately, Inpex has awarded to ABB of Zurich contracts worth $80 million to supply power technologies and medium-voltage drive systems for the project. The ABB equipment will power the liquefaction plant and control the compressors that liquefy the gas. ABB said about half of the order value was booked at the end of this year's first quarter with follow on orders coming in second quarter.

ABB will design and deliver a power supply package for the liquefaction plant, said the announcement, including supply of such key equipment as power and distribution transformers, medium-voltage switchgear, low-voltage motor control centers, and a power-distribution monitoring and control system.

BLM seeks comments on NGL pipeline EA

The US Bureau of Land Management released an environmental assessment (EA) of a proposed 95-mile NGL pipeline in eastern Utah and western Colorado and is seeking public comments on the project, BLM's Grand Junction field office said.

It said Enterprise Mid-America Pipeline Co. is seeking approval to begin construction on the 16-in. line, the Western Expansion Project II, which would be part of a larger system from Colorado and Wyoming to Hobbs, NM.

The segment would begin in southeastern Uintah County, Utah, and follow an existing corridor across Rio Blanco, Garfield, and Mesa counties in Colorado before terminating north of Moab, Utah. It would increase current capacity by 15,000 b/d. Comments will be accepted through July 31.


A newsletter item about the Abu Dhabi-Fujairah crude pipeline contained erroneous information (OGJ, July 9, 2012, Newsletter). The correct information follows: The main pipeline measures 252 miles and will have a maximum capacity of 1.8 million b/d. Storage currently available totals 8 million bbl. Start-up was originally scheduled for August 2011.

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