OGJ Newsletter

Exploration & Development — Quick Takes

Oil, wet gas seen in Kenya Lokichar discovery

Tullow Oil PLC and Africa Oil Corp. have made a second large oil discovery in the Lokichar basin in northwestern Kenya.

The companies said the Twiga South-1 exploratory well on Block 13T encountered 30 m of net oil pay in Tertiary sandstone reservoirs with further potential to be assessed on test. The well also encountered a tight fractured rock section with oil and wet gas shows over a 796-m gross interval.

Twiga South-1 has been drilled to a total depth of 3,250 m and successfully logged and sampled. Three sandstone reservoir zones, analogous to those in the companies' mid-2012 Ngamia-1 discovery on Block 10BB, were encountered and movable oil of higher than 30° gravity was recovered. Further potential exists updip of the well and will be subsequently appraised, Tullow said.

Tullow also sampled movable oil lighter than 30° gravity from the 796-m tight fractured rock section below 2,272 m. This tight fractured rock section is a new play-type for the region that will require further evaluation to understand its extent and any productive potential, the company added.

The Twiga South structure is the second prospect to be tested in the Lokichar basin as part of a multiwell drilling campaign in Kenya and Ethiopia and is the first oil discovery in Block 13T. Twiga South is 22 km north of Ngamia-1 and further derisks a number of other similar features on the basin's western margin (OGJ Online, July 5, 2012).

A series of flow tests will be run on Twiga South-1 in the next 4-8 weeks, after which the rig will return to flow-test Ngamia-1.

Elsewhere in Tullow's East African Rift basin acreage, a result from the Paipai-1 well in Block 10A in Kenya is expected by the end of 2012, and the Sabisa-1 well on the South Omo block in Ethiopia is expected to spud by the end of December.

Tullow has a 50% operated interest in Twiga South-1, and Africa Oil has 50%.

New Zealand Energy gauges basin discovery

New Zealand Energy Corp. will watch production at its Waitapu-2 well in New Zealand's Taranaki basin before deciding whether to continue trucking oil or laying a 1.3-km pipeline.

Waitapu-2, the company's fifth oil discovery in the basin, has recovered 1,880 bbl of oil from the Miocene Mount Messenger formation and is flowing 325 b/d of 40° gravity oil and 800 Mcfd of gas on a 24⁄64-in. choke. It went to 2,085 m measured depth and encountered 6.2 m of net pay.

NZE is trucking the sweet crude 45 km north to the Shell-operated Omata tank farm, where it is sold at Brent pricing.

The company said Waitapu-2 is flowing from natural reservoir pressure, as its Copper Moki wells did, further confirming the geological model, whereas most Mount Messenger wells require artificial lift almost immediately.

NZE continues to refine the geological model based on drilling success to date and interpretation of the recently completed 3D seismic survey. The company said it has many prospects to drill that it believes are similar to the Copper Moki and Waitapu discoveries.

The company's Waitapu-1 well had permeability and porosity that did not yield economic production. It was completed across a 30-m gross interval in the Mount Messenger.

NZE has reached target depth of 2,380 m MD and is preparing to run casing at Arakamu-2, third well in its current eight-well program. It cut 8.1 m of net pay in two potentially productive Mount Messenger zones. Following completion of Arakamu-2, NZE will spud Arakamu-1A, which targets the deeper Moki formation.

Petronas Sarawak gas find sets company depth mark

Malaysia's Petronas has made two sizable gas finds offshore Sarawak, one of which is the company's deepest vertical well and its first completed high-pressure high-temperature well.

Petronas Carigali drilled Tukau Timur Deep-1 to a record 4,830 m on the SK307 block and discovered 12 gas-bearing reservoirs with a combined 183 m net thickness.

A preliminary assessment indicates gas in place in Tukau Timur field to be about 2.1 tscf, the firm said. Subsequent work will start to estimate the range of recoverable volumes.

Petronas Carigali is operator of SK307 with 50% interest, and Sarawak Shell Bhd. has 50%.

Meanwhile, Petronas discovered Kuang North field on the SK316 block with an estimated 2.3 tscf of gas in place in the older carbonate section, opening an exploratory play type with what the company calls "substantial hydrocarbon potential."

Petronas found Kuang North field with the Kuang North-1 and 2 exploratory wells. Kuang North-2 went to 3,223 m and penetrated 636 m of gas column.

The SK316 block also contains the recent Kasawari and NC8 gas field discoveries, Petronas noted.

Noble Energy group has deepwater gulf oil find

A group led by Noble Energy Inc. has encountered 150 ft of net oil pay in two high-quality Miocene reservoirs at a deepwater discovery in the Gulf of Mexico.

The Big Bend prospect went to 15,989 ft in 7,200 ft of water on Mississippi Canyon Block 698.

Noble Energy said Big Bend well results "appear at least as good as our predrill mean resource expectations and derisked our offset prospect Troubadour. The combination of excellent reservoir properties, fluid characteristics and our high working interest in this project will contribute significant production and cash flow for our business."

Noble Energy is operator with a 54% working interest in Big Bend. W&T Energy VI LLC, a unit of W&T Offshore Inc., has 20%, Red Willow Offshore LLC 15.4%, and Houston Energy Deepwater Ventures V LLC 10.6%.

Drilling & Production — Quick Takes

Athabasca Oil reports strong Duvernay results

Athabasca Oil Corp. reported strong test results in the Duvernay shale play in west-central Alberta, and AOC said a better understanding of the shale's fracture characteristics has enabled the company to evolve its hydraulic fracturing techniques.

The Duvernay is about 3,000 m deep and is an interbedded quartz-shale source rock (OGJ, Nov. 5, 2012, p. 32).

AOC's third Duvernay well, 02-34-62-20W5M at Kaybob West, flowed at a final test rate of more than 6 MMcfd along with 900 b/ of 50° gravity condensate at a steady 3,000 psig.

The 02-34 well is expected to come on stream during December upon completion of a pipeline tie-in to the Kaybob West plant, AOC said.

AOC's second Duvernay well, 06-10-62-23W5M, was flow tested on two separate occasions.

Following its initial completion, the well sat for a 40-day "soak" period. On its second test, the well flowed at 5 MMcfd along with 450 b/d of 50° gravity condensate at 2,500 psig. The 06-10 well is expected to come on stream in mid-December when the Saxon plant is commissioned, AOC said.

Earlier this year, AOC reported results on its first Duvernay horizontal well at Kaybob and also completed Montney and Nordegg multistage fractured horizontal wells at Kaybob in the Deep basin (OGJ Online, Feb. 7, 2012).

Visund South flow starts offshore Norway

Production has begun from Visund South oil and gas field in the North Sea offshore Norway (OGJ Online, June 10, 2011).

The start-up is the first in operator Statoil's fast-track scheme for developing offshore fields.

Visund South encompasses the Pan and Pandora discoveries 10 km from the Gullfaks C and Visund A platforms. Development involves a four-slot subsea template through which three have been drilled and tied back to Gullfaks C.

Statoil estimates reserves at 67 million boe, one-fourth oil and the rest natural gas. It didn't report flow rates.

Interests are Statoil 53.2%, Total 7.75%, Petoro 30%, and ConocoPhillips 9.1%.

Svalin development offshore Norway approved

Development of Svalin oil field in the North Sea offshore Norway has received approval of the Norwegian Ministry of Petroleum and Energy (OGJ Online, June 15, 2012).

Statoil, the operator with a 57% interest, said production from Svalin M, one of two structures in the field, will start in late 2013 from a well drilled from the Grane platform about 6 km northeast. Production from Svalin C, the other structure, will begin in 2014 through a well completed subsea and connected to the Grane platform with a 6-km flowline.

Compression facilities on the Grane platform will be modified to accommodate Svalin natural gas.

The field, in 125 m of water, holds reserves estimated at 75 million bbl of oil, about equally split between the structures. Its development, the ninth in Statoil's fast-track scheme, will extend the life of Grane, where production is declining, to 2013, Statoil said.

Operator okays Hangingstone SAGD project

The board of directors of Athabasca Oil Corp. has sanctioned the Hangingstone 1 steam-assisted gravity drainage oil sands project in the southern Athabasca region of Alberta and approved a $536 million (Can.) development budget for it (OGJ Online, Oct. 4, 2012).

The company plans a central processing facility and 20 SAGD well pairs drilled from four well pads. The board also approved spending of $27 million on construction of supporting infrastructure.

Drilling will begin in mid-2013. Start-up of the processing facility is scheduled for the fourth quarter of 2014. First steam is expected by the end of 204, with production starting in early 2015. Production capacity is 12,000 b/d of bitumen.

The company plans two other SAGD projects, which will bring potential production in the area to 80,000 b/d.

PROCESSING — Quick Takes

AFPM asks EPA to reconsider diesel decision

The American Fuel & Petrochemical Manufacturers petitioned the US Environmental Protection Agency to reconsider its final rule to raise the biomass-based diesel minimum for 2013. On Sept. 14, EPA raised the amount to 1.28 billion gal.

In its Nov. 20 petition, AFPM strongly urged EPA to reconsider its decision to increase the biomass-based diesel volumes by 28% starting next year.

Since the federal environmental regulator initially issued the rule, a number of factors have surfaced that could result in unintended consequences that will adversely affect both the domestic refining industry and US consumers, AFPM said.

"EPA's own data estimates that the cost of increasing the biomass-based diesel mandate will add $253-381 million to consumers' transportation fuel bill in 2013," AFPM Pres. Charles T. Drevna said. "The US economy is still struggling, and this increase will hurt the millions who rely on transportation fuels."

AFPM said, contrary to EPA's research, evidence is strong that an increase in the 2013 volume will not affect US energy security as the US currently is a net diesel exporter.

In the category of unintended consequences, EPA's decision would curtail investment in advanced biofuels that complete with biodiesel and will increase carbon emissions in 2013 under the federal Renewable Fuel Standard, AFPM added.

It said the increase also could have a negative impact on the price and supply of agricultural commodities, since additional biodiesel feedstocks, such as soybean oil, would be required under the rule.

"Before increasing the 2013 volume, EPA must resolve the pervasive problem that exists in the biodiesel market of Renewable Identification Number (RIN) fraud," Drevna said. "To date, over 140 million fraudulent RINs have been sold to unsuspecting refiners concerned with meeting their RFS obligations. That number, and the costs associated with the fraud, will grow as investigations of biodiesel producers continue today."

Estonian shale oil complex due sulfur unit

Estonian shale oil miner and processor Viru Keemia Grupp AS let a contract to Jacobs Engineering Group Inc. for licensing and services for a sulfur recovery unit at its Kothia-Jarve complex.

Jacobs also will provide the basic design package, training, start-up, and commissioning assistance. VKG is upgrading its complex, which retorts oil shale and processes the liquids, to produce diesel meeting Euro 5 standards.

TRANSPORTATION — Quick Takes

Teak opens Eagle Ford gas gathering capacity

Teak Midstream LLC has begun operation of more than 250 miles of natural gas gathering and residue delivery pipelines and its adjoining 200 MMcfd Silver Oak cryogenic gas processing plant in South Texas, serving gas producers in the Eagle Ford shale and surrounding area. Teak plans to double the gas processing capacity by first-quarter 2014 based on volume commitments to date and increasing demand to process liquids-rich gas from the Eagle Ford, as well as the Buda, Pearsall, Olmos, and Escondido formations.

Teak's new pipelines include two inlet high-pressure gas gathering systems. One system consists of 178 miles of 24-in. and 16-in. OD pipeline with 600 MMcfd of gas capacity. This system starts in Dimmit County on the western edge of the Eagle Ford and moves rich gas east through Webb, La Salle, McMullen, and Live Oak counties to the Silver Oak plant in Bee County. Teak jointly owns this gathering system with TexStar Midstream. The second system consists of 22 miles of 20-in. OD pipeline moving 400 MMcfd between Karnes County and the Silver Oak plant.

The pipelines also include 57 miles of 20-in. OD residue gas line, carrying dry gas from the Silver Oak plant to six major intrastate and interstate pipelines: Tennessee Gas Pipeline, Channel, Kinder-Tejas, Transco, Texas Eastern, and NGPL. Teak also built 3 miles of 12-in. OD NGL pipeline, moving liquids recovered at the Silver Oak plant to the DCP Sand Hills NGL pipeline and ultimately to the Mont Belvieu fractionation complex and other fractionation Gulf Coast fractionation capacity.

Teak recently executed long-term gathering and processing agreements with Comstock Resources Inc. and another large Eagle Ford shale producer supporting the lines and plant. Talisman Energy USA Inc. and Statoil Natural Gas LLC signed on as anchor customers earlier this year (OGJ Online, Feb. 22, 2012).

Oneok cancels Bakken Crude Express Pipeline

Oneok Partners LP reported it will not build its proposed Bakken Crude Express Pipeline, having received insufficient long-term transportation commitments during the project's open season, concluded Nov. 20.

The firm said it was disappointed with the open season results, but remained committed to serving Williston basin producers. "We still believe the Bakken Crude Express has a competitive advantage over other competing projects due to its proximity to the route of our Bakken NGL Pipeline currently under construction (OGJ Online, Nov. 13, 2012) and other Oneok Partners natural gas liquids pipeline corridors," said Oneok Pres. Terry K. Spencer.

The system would have been a 1,300-mile, oil pipeline with capacity to transport 200,000 b/d of light-sweet crude from multiple points in the Williston basin in the Bakken shale in North Dakota and Montana to Cushing, Okla.

Sweden to get second LNG terminal

Skangass AS, Stavanger, has awarded a $57 million engineering, procurement, construction, and installation contract to Linde Group, Munich, to build an LNG import terminal at Lysekil on the west coast of Sweden about 62 miles north of Gothenburg.

Start-up will be in spring 2014.

It will supply natural gas to the refinery at Preem as well as to industrial and transportation applications, Linde reported. The contract award includes integration of cryogenic tanks to be erected by an unnamed third party.

Linde also built Sweden's first LNG terminal in Nynashamn last year. The terminal will have storage capacity of 30,000 cu m of LNG, compared with 20,000 cu m at Nynashamn, and will include a truck filling station.

Linde Engineering has performed the basic engineering and will support with procurement of rotating equipment, commissioning, and start-up.

LNG for both terminals comes from the midscale LNG plant at Risavika, near Stavanger. Also owned by Skangass, this plant started operations in 2010 (OGJ Online, July 7, 2007).

Gothenburg is one of northern Europe's largest ports of export, the company said. It is in an "emission control area," where stricter sulfur emission limits will apply in January 2015.

Petronas awards contract for Bintulu LNG

Malaysia LNG Sdn. Bhd., a unit of Malaysia's state oil and gas firm Petronas, has let a contract to Linde Group, Munich, for the construction of a midscale LNG plant in the Bintulu LNG complex in Sarawak, East Malaysia. Design production capacity for the plant will be 1,840 tonnes/day from boil-off feed gas from LNG storage and ship loading. The plant is to go on stream at yearend 2014.

Linde's engineering division will perform detail engineering, procurement, construction, and commissioning. Linde's proprietary LNG process and core cryogenic heat exchanger have been customized to reliquefy the boil-off gases and to accommodate large variations in nitrogen content, flow rate, and temperature. Linde's process also will enable Malaysia LNG to minimize flaring.