OGJ Newsletter

March 24, 2014
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Oil Search completes placement for Elk-Antelope fields

Oil Search Ltd. has completed its share placement to the Papua New Guinea government in the recently announced deal to fund the company's acquisition of a 22.835% stake in retention license PRL15 containing the Elk and Antelope fields in the eastern Highlands of Papua New Guinea for $900 million (OGJ Online, Feb. 27, 2014). The placement involved 149.39 million fully paid ordinary shares to the state, giving it a 10% interest in Oil Search.

The deal, which was completed last week, involved the acquisition of 100% of Pac LNG Group (formerly Pacific LNG), which is affiliated with the privately owned Swiss banking firm Clarion Finanz AG.

However the government's involvement has sparked unrest in Papua New Guinea political circles with opposition leader Belden Namah calling on Prime Minister Peter O'Neill to resign, ostensibly because he has committed Papua New Guinea to a $700 million (Aus.) loan to fund its stake in Oil Search.

Flames were fanned this week when O'Neill sacked the leaders of two coalition partners—William Duma and Don Poyle—from their respective posts as petroleum minister and treasurer.

Rumors abound that the pair were sidelined because of their opposition to the further $700 million debt and the move to raise the country's debt ceiling above 35% of gross domestic product.

O'Neill maintained they were causing instability and he himself has assumed the powers of treasurer.

Namah says the move is a blatant push to borrow more. He said the country's debt had doubled to $2.4 billion from $1.2 billion while the debt-to-GDP ratio will rise to 37% from 35%.

Imperial to sell conventional assets to Whitecap

Imperial Oil Ltd. has reached an agreement to sell its interest in conventional assets in Boundary Lake, Cynthia/West Pembina, and Rocky Mountain House in British Columbia and Alberta to Whitecap Resources Inc. for $855 million. The deal is expected to close in May.

The assets in 2013 produced 15,000 boe/d, split evenly between oil and gas, on a net before royalty basis.

Vermilion to buy southeast Saskatchewan assets

Vermilion Energy Inc., Calgary, has signed an agreement with a private southeast Saskatchewan producer to acquire light oil producing assets in the Northgate region of southeast Saskatchewan for $400 million.

The assets include 57,000 net acres of land, of which 80% is undeveloped, along with seven oil batteries and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction.

Production from the assets this year is projected at 3,750 boe/d, of which 97% is crude oil. More than 90% of the current production base will be operated by Vermilion.

Total proved and proved-plus-probable reserves attributed to the assets by GLJ Petroleum Consultants Ltd. as of Feb. 28 are 10.3 million boe, of which 81% is crude oil and natural gas liquids; and 16.5 million boe, of which 81% crude oil and natural gas liquids.

Vermilion has found 175 (152 net) potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks-Torquay formations. The majority of production and development drilling opportunities are from the Midale formation, with additional opportunities identified in the Frobisher, Bakken, and Three Forks-Torquay formations.

Vermilion said the assets demonstrate a low annual decline of 18% and are expected to provide cash flow that will fully fund the assets' continued growth.

The deal creates a new core area for Vermilion in the Williston basin, providing assets that are geographically complementary to recent leasing activity it has conducted for Mississippian development in southwest Manitoba.

The company said the multihorizon, horizontal well techniques employed in the area are suited to the knowledge it has gained during development of the Pembina area assets in Alberta.

With the purchase, Vermillion is revising its production guidance for this year to 47,500-48,500 boe/d, assuming 8 months of contribution from the assets, and revising the company's guidance for exploration and development capital expenditures by $35 million from the current level of $555-590 million for the year.

The deal, expected to close Apr. 29, is comprised of cash and share consideration of $345 million plus the assumption of $55 million in debt.

Exploration & DevelopmentQuick Takes

DNO completes horizontal wells in Tawke field

DNO International ASA, Oslo, has started production from two newly completed horizontal wells at a combined rate of 37,000 b/d in Tawke field in Iraq's Kurdistan Region.

In one of the wells, Tawke-21, 8 productive fracture corridors penetrated by a 980-m horizontal section in the main Cretaceous reservoir interval flowed an average rate of 9,700 b/d each. In Tawke-22, 6 km away from Tawke-21, 7 productive fracture corridors penetrated by an 800-m horizontal section flowed an average rate of 8,800 b/d each. Both wells are subject to wellbore and surface facilities limitations, DNO said.

"We hit a new production record of 129,000 b/d at the Tawke field on Mar. 5, which is close to the limit of what we currently can deliver by pipeline and road tanker," said Bijan Mossavar-Rahmani, DNO International executive chairman. "With the exceptional results from these latest wells and the installation of early production packages and a new 24-in. pipeline, we are on track to meet our ambitious deliverability goal of 200,000 b/d in 2014," he added.

Two previous Tawke horizontal wells began production in the second half of 2013, 2 wells are currently drilling and 3 more are scheduled which, together with Tawke-21 and Tawke-22, will bring to 9 the total number of horizontal wells in the field by yearend (OGJ Online, Oct. 14, 2013).

DNO International is operator of the Tawke license, holding 55% interest. Partners are Genel Energy PLC with 25% and the Kurdistan Regional Government with the remaining 20%.

Cairn, FAR to drill exploration wells off Senegal

FAR Ltd., Perth, will participate in the drilling of two deepwater exploration wells offshore Senegal next month.

The wells, to be operated by Cairn Energy PLC, Edinburgh, will be the first deepwater wells drilled off Senegal and only the second and third deepwater wells along the central Atlantic margin of West Africa.

Cairn will use Transocean Inc.'s Cajun Express semisubmersible rig for the two-well program. The rig is currently finishing up a campaign for Cairn offshore Morocco.

The first Senegal well, Fan-1, will be drilled on the north Fan prospect in 1,500 m of water. It will be immediately followed by a second well to the southeast targeting a Shelf Edge prospect in 1,100 m of water. FAR says the two prospects combined have potential to hold 1.5 billion bbl of oil.

FAR has retained a 15% interest after farming out to Cairn (40%) and ConocoPhillips (35%) to secure a carry of expenditure through the two-well program. Senegal national oil company Petrosen has the remaining 10% also as a carried interest in the drilling program.

Cairn completes drilling on Moroccan prospect

Cairn Energy PLC reported that its JM-1 well offshore Morocco has been plugged and abandoned without testing. The well commenced drilling in January and reached a total depth of 3,711 m. The stated objectives of Upper and Middle Jurassic were reached, the company said.

The JM-1 well confirmed the presence of heavy oil within a gross interval of 110 m in the Upper Jurassic section. This interval was originally tested in 1968 at the MO-2 well, which is 2 km from the JM-1 well. Cairn reported that reservoir quality and oil gravity in the Upper Jurassic across the Cap Juby structure will require further evaluation.

The company holds a 37.5% working interest in the JM-1 along with its joint venture partners, the Office National Des Hydrocarbures et Des Mines and Genel Energy. According to the company, work is continuing to correlate core and log data with other wells on Cap Juby to evaluate the extent of moveable hydrocarbons. Primary porosity and evaluation of well logs and side wall cores is ongoing for the Middle Jurassic section as well.

CNOOC makes gas discovery in Qiongdongnan basin

CNOOC Ltd. has made a natural gas discovery in the east Lingshui Sag of the deepwater area in the South China Sea's Qiongdongnan basin.

The Lingshui 17-2-1 discovery well, drilled in 1,450 m of water, was completed at a depth of 3,510 m and encountered the gas reservoir with 55 m of total thickness.

CNOOC said, "The discovery has not only proven the exploration potential of structural and lithologic trap in central Canyon channel of Lingshui Sag, but also further confirmed the good exploration prospects in deepwater area of Qiongdongnan basin."

Drilling & ProductionQuick Takes

Ivanhoe halts Tamarack oil sands project

Ivanhoe Energy Inc. has suspended activity on its Tamarack oil sands project pending approval for its thermal oil sands application from the government of Alberta.

The company said its decision is based on the uncertainty that there is no timeline defined by the Alberta Energy Regulator (AER) for a new regulatory framework for shallow steam-assisted gravity drainage (SAGD) projects, and the lack of clarity regarding a path for approval for its Tamarack application.

In November 2010, Ivanhoe submitted the application, which involves two 20,000 b/d phases for an eventual production of 40,000 b/d of bitumen. At the time, the company anticipated production from the first phase toward yearend 2013 (OGJ Online, Nov. 8, 2010).

Ivanhoe said it will limit Tamarack spending to only essential items until there is greater regulatory certainty as to a path to approval.

The company believes its application, as submitted, adheres to best practices for safe reservoir development, and is now evaluating novel and advanced technologies that could potentially result in early production from the project.

Ivanhoe estimates that the regulatory uncertainty affects as much as 1 million b/d of future shallow SAGD projects held by various resource owners—a significant percentage of the overall oil sands production growth, as forecasted by the Canadian Association of Petroleum Producers.

Ivanhoe is working with other affected resource owners and the AER to support the early issuance of a long-term policy for shallow SAGD projects.

Shell lets contracts for Majnoon development

Shell Iraq Petroleum Development BV has let engineering and procurement services contracts to Foster Wheeler Kentz Energy Services DMCC, Dubai, for Shell's Majnoon field in Iraq. The 2-year contracts include concept selection, front-end design, detailed design, procurement, and contract services, said Foster Wheeler Kentz.

In 2010, Iraq's Oil Ministry signed a 20-year contract with Royal Dutch Shell PLC and Malaysia's Petronas to provide technical assistance in the development of the Majnoon oil field (OGJ Online, Jan. 18, 2010). Majnoon, which lies in southern Iraq 70 km north of Basra City, is one of the world's largest oil fields with 38 billion bbl of oil in place, according to the Iraqi government.

Operator Shell holds a 45% share. Partner Petronas holds 30% while Iraq's state holdings are 25%.

Madagascar Oil updates Tsimiroro field activity

Madagascar Oil Ltd. reported that its steam-flood pilot (SFP) in Tsimiroro heavy oil field has increased oil production from 222 b/d in December 2013 to 425 b/d in February. The results of the pilot, scheduled to end by this year's second quarter, will determine if the company proceeds with a commerciality declaration later this year.

The nine-pattern SFP began in late-2012 to test the viability of using a conventional-pattern, vertical, multilayer steam flood. The data acquired will resolve numerous reservoir performance factors that Madagascar Oil expects to derisk the decision to proceed with a full-scale development of the field. According to the company, that decision also is contingent on approvals from l'Office des Mines Nationales et des Industries Strategiques, which manages mineral and petroleum resources in Madagascar.

Tsimiroro field has independently audited contingent resources of 1.7 billion bbl (P50) stock tank oil originally in place. Madagascar Oil says it will update those figures upon completion of a full-field interpretation that is nearing completion.

PROCESSINGQuick Takes

Keyera to buy west central Alberta gas plant

Keyera Corp., Calgary, will pay $133 million to Whitecap Resources Inc. for interests in gas processing in west central Alberta and in associated oil and gas reserves, Keyera reported. The company expects the acquisition to close on May 1.

As part of this agreement, Keyera will acquire:

• 85% ownership in the 78-MMcfd West Pembina 6-28 gas plant (the "Cynthia" gas plant).

• Varying ownership interests in oil batteries, compressors, and gathering pipelines associated with the gas plant.

• The 4.6% interest in the Bigoray gas plant Keyera doesn't already own.

• Nisku reserves currently tied into the two gas plants.

The Cynthia plant sits in west central Alberta near Keyera's Pembina North, Brazeau North, and Bigoray gas plants. It has a turboexpander capable of extracting a deep cut of ethane-rich NGLs from the raw gas stream. It also has acid-gas injection capability that enables it to handle sour gas.

Current throughput is about 46 MMcfd, said the company, and is largely associated gas and NGLs from Nisku oil production in the area. Upon closing, Keyera expects to become the plant operator. A maintenance turnaround scheduled for May will cost about $10 million, said Keyera.

Along with gathering and processing, Keyera is buying reserves from the Nisku geological horizon, with the associated wells producing into the Cynthia and Bigoray gas plants. Production from these wells averaged about 8,700 boe/d in 2013, said the announcement, of which about one-third was crude oil and NGLs and two-thirds natural gas.

Because the reserves are in the late stages of their life cycle, Keyera currently estimates the production decline rate to be 25-30%/year and has no plans to drill additional wells. The company also said that rights of first refusal exist on portions of the reserves and some surface assets associated with the production.

Keyera's gas processing plants and associated facilities are in the west central, foothills, and deep basin natural gas production areas of the Western Canadian Sedimentary Basin. Its NGL and crude oil infrastructure, including pipelines, terminals, and processing and storage, as well as an iso-octane facility, are in Edmonton and Fort Saskatchewan.

Flint Hills proposes $300 million refinery upgrade

Flint Hills Resources (FHR), Wichita, Kan., plans to invest $300 million in two projects that would improve both energy efficiency as well as clean fuels production at its 339,000-b/d Pine Bend refinery at Rosemount, Minn.

One project will include the addition of a combined heat and power (CHP) system that would allow the refinery to generate a portion of its own electricity, while a second project focuses on implementing a process for removing sulfur from gasoline and then using that to produce a stable form of fertilizer, the company said on Mar. 19.

The CHP system will use natural gas and a heat recovery process to produce up to about 50 Mw of electricity, roughly half of what's required to power the refinery, Flint Hills said.

The company said it also expects the Pine Bend CHP system to use air-cooled condenser technology, which will save 400,000 gpd of water compared with traditional water-based cooling systems.

The clean fuels and fertilizer project at Pine Bend will establish a process for capturing sulfur that will help the refinery produce fuels that meet the US Environmental Protection Agency's pending Tier 3 standard for gasoline (OGJ Online, Mar. 3, 2014).

The process at Pine Bend—which involves the conversion of sulfur and nitrogen removed from produced fuels into salable aqueous liquid fertilizer or ammonium thiosulfate (ATS)—will use a combination of two different technologies for removing ammonia and producing ATS that FHR believes to be the first of its kind implemented in the US, the company said.

While both projects still await permits from Minnesota's Pollution Control Agency as well as final approval from FHR's management, if approved, construction could begin in early 2015, FHR said.

The CHP and clean fuels and fertilizer projects follow more than $400 million in projects that were approved last year and that are now being implemented to improve the Pine Bend refinery's reliability, reduce key emissions, and improve its ability to convert crude oil into transportation fuels, according to FHR.

EPP lets contract for Gulf Coast PDH unit

Enterprise Products Partners LP (EPP), Houston, has let a $100 million contract to CB&I, Houston, for pipe fabrication for a propane dehydrogenation (PDH) unit in Mont Belvieu, Tex.

Last year, EPP let an engineering, procurement, and construction contract for the PDH unit to a subsidiary of Foster Wheeler AG's Global Engineering & Construction Group. No contract value was disclosed (OGJ Online, Aug. 6, 2013).

In mid-2012, EPP reported it would build the 35,000-b/d PDH unit to take advantage of low-cost propane derived from increased NGL production out of nearby shale gas development.

The unit will be able to produce as much as 1.65 billion lb/year (about 750,000 tonnes/year) of polymer-grade propylene, a prime feedstock for plastics manufacturers (OGJ Online, June 21, 2012).

For feedstock supply, the PDH will be supported by EPP's Gulf Coast NGL fractionation and storage. With previously announced expansions, the company by 2015 will have 708,000 b/d of NGL fractionation capacity, which would provide up to 177,000 b/d of propane (OGJ, May 7, 2012, p. 88).

In addition, the new PDH unit will be supported by EPP's 100 million bbl of NGL and petrochemical storage along the Texas Gulf Coast.

TRANSPORTATIONQuick Takes

Hiland looks to expand Bakken crude pipeline

Hiland Crude LLC has launched an open season to solicit shipper interest for crude oil transportation on an expanded version of its Double H Pipeline, currently under construction in the Bakken shale. An initial open season in 2012 filled its 50,000 b/d base capacity.

Double H starts in the Bakken oil production areas near Dore, ND, and Sydney, Mont., and ends at Hiland's storage in Guernsey, Wyo. The expansion would include new and increased-capacity pump stations, boosting capacity to as much as 100,000 b/d.

Double H will deliver oil into connecting pipelines in Guernsey, including the Tallgrass Pony Express Pipeline and other proposed interconnections, starting in this year's fourth quarter. Tallgrass expects the 24-in. OD Pony Express to enter service in August, carrying as much as 320,000 b/d from Guernsey to Cushing, Okla. Tallgrass acquired Pony Express from Kinder Morgan Energy Partners LP in 2012 as part of the latter's mandated divestitures following its acquisition of El Paso Corp. (OGJ Online, Aug. 20, 2012).

Hiland's existing crude oil pipeline system connects to Crestwood Midstream Partners LP's 120,000 b/d COLT Hub crude rail and pipeline terminal in Williams County, ND (OGJ Online, Oct. 10, 2013).

FERC issues DEIS on Freeport LNG's Phase II

The US Federal Energy Regulatory Commission has issued a draft environmental impact statement (DEIS) on Freeport LNG's Phase II modification and liquefaction projects.

FERC concluded that "construction and operation of the projects would result in adverse impacts on certain resources and nearby communities."

FERC said, "We have identified that there would be significant and unavoidable impacts on residents of the town of Quintana due to construction noise and construction traffic if the projects are approved by the commission."

The commission added, "However, other adverse impacts would be reduced to less-than-significant levels with the implementation of Freeport LNG's mitigation measures and the additional measures we recommend in the EIS."

The projects proposed by Freeport LNG are in Brazoria County near Freeport, Tex. The proposed Phase II modification project includes modification to the previously authorized LNG vessel berthing dock, LNG transfer pipelines, LNG unloading arms, and the access road system at Freeport LNG's existing Quintana Island terminal. Freeport LNG would not build components of the previously authorized facility, including vaporization equipment that was approved to increase the LNG Terminal's sendout capacity.

The firm's proposed liquefaction project consists of the liquefaction plant at and adjacent to the existing Quintana Island LNG terminal and would provide Freeport LNG the capacity to export about 13.2 million tonnes/year of LNG. Freeport would install three liquefaction trains and supporting equipment capable of liquefying 1.8 bcfd of gas.

In support of the liquefaction plant, Freeport LNG proposes to construct a natural gas pretreatment plant about 2½ miles north of the existing Quintana Island terminal. In addition, several interconnecting pipelines and utility lines would extend from the Quintana Island terminal to the pretreatment plant.