GeoPark makes oil field discovery in Colombia
GeoPark Ltd., an independent Latin American oil and gas explorer, operator, and consolidator with operations and growth platforms in Colombia, Chile, Brazil, Argentina, and Peru, has discovered a new Curucucu oil field in the Llanos 34 block (GeoPark operated with a 45% WI) in Colombia.
GeoPark drilled and completed the Curucucu 1 exploration well to a total depth of 14,600 feet. A production test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 1,700 barrels of oil per day, of 15.8 degrees API, with 0.4% water cut, through a choke of 100/64 inches and wellhead pressure of 70 pounds per square inch. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production. Petrophysical log analysis during drilling also indicated the presence of potentially productive hydrocarbons in the shallower Mirador formation.
To minimize surface construction costs and share production facilities, the Curucucu 1 exploration well was drilled from an existing well pad in the recently discovered Jacamar oil field. The well was drilled with a horizontal extension of more than 9,000 feet; representing a record for the Llanos 34 block. Curucucu oil field is located on a new fault trend to the east of Tigana/Jacana fault trend, adjacent to the Jacamar oil field. It is the eleventh oil field discovered by GeoPark since acquiring the prolific Llanos 34 block in 2012, and one of three new oil fields added in 2017.
GeoPark plans to drill approximately seven wells in the Llanos 34 block during 3Q2017 with a focus on further delineating the southern Jacana and northern Tigana oil fields.
Hansa Hydrocarbons confirm gas discovery offshore Netherlands
Hansa Hydrocarbons Limited (Hansa) and its partners reported a gas discovery from the N05-1 exploration well drilled offshore Netherlands on the GEms licences. The well encountered gas in the target basal Rotliegend sandstones. Hansa and its partners Oranje-Nassau Energie BV (ONE) and Energie Beheer Nederland BV (EBN, the Dutch State entity), further appraised the reservoir distribution and delineated the structure with a downdip geological side-track which also encountered gas. The reservoir interval was cored throughout and 24m of net sand was encountered with high permeability. This was confirmed by the DST in the vertical well which was flow tested at a maximum sustained flow rate of 53 million standard cubic feet per day, which was the limit of surface equipment. The results of the well exceeded pre-drill expectations.
The Ruby discovery extends across the N04, N05, N08, and Geldsackplate licences in the Dutch and German North Sea sectors respectively in a water depth of 28m. The N05-1 well was drilled as a joint well between the N05 and Geldsackplate licence groups, with Hansa participating at a 40% working interest. The well was operated by ONE and drilled with the Paragon Offshore Prospector-1 rig, which moved off location on August 30, 2017.
Hansa is operator of both the Dutch and German GEms licences, Blocks N04, N05, N8 and N07c in the Netherlands, with interests post-EBN participation of 25% to 30%, and the Geldsackplate licence in Germany with an interest of 50%.
New assessment targets marketable oil and gas resources in Alberta's Duvernay Shale
The National Energy Board (NEB), together with the Alberta Geological Survey (AGS), released a new resource assessment for the Duvernay Shale in central Alberta that adds significant quantities of marketable light oil resources in the province as well as natural gas and natural gas liquids (NGLs).
Using geological and in-place hydrocarbon data provided by the AGS, the NEB estimates the Duvernay Shale contains 3.4 billion barrels of marketable light oil and field condensate, or 17 years of Alberta's annual production. It also shows marketable gas resources equivalent to nearly 25 years of Canada's annual consumption.
The Duvernay Shale covers nearly 20% of the province, stretching from just below Grande Prairie to just north of Calgary and east of Edmonton. Companies have been drilling the Duvernay for shale gas and oil since 2011, and the region has extensive existing pipeline infrastructure.
Deposited about 370 million years ago, the Duvernay Shale is rich in organic matter and ranges from about one kilometre to more than five kilometres deep. The Duvernay generally starts getting prospective for oil and gas production below 2.5 km, with the formation generally oily in areas shallower than 3 km and gassier in areas deeper than 3 km.
Although most of current development has focused on the Duvernay's West Shale Basin, such as the Kaybob Field northwest of Edmonton, recent provincial land sales show increasing industry interest in the Duvernay's East Shale Basin.
A resource assessment of a formation's marketable petroleum estimates the total amount of sales-quality oil, natural gas and even NGLs that can potentially be recovered from a formation with existing technology. Resource assessments are based on a number of factors such as the geology of the reservoir and production from existing wells.
The NEB will be releasing a second report later this fall examining the economics of the Duvernay Shale resource.
The National Energy Board is an independent federal regulator of several parts of Canada's energy industry. The Alberta Geological Survey (AGS) is a branch of the Alberta Energy Regulator (AER) and provides geological information and advice to the Government of Alberta, the AER, industry and the public.
Murphy enters deepwater Brazil blocks
Murphy Brazil Exploração E Produção De Petróleo E Gás Ltda., a wholly owned Brazilian subsidiary of Murphy Oil Corp. (NYSE: MUR), has entered into a farm-in agreement with Queiroz Galvão Exploração e Produção SA (QGEP) to acquire a 20% working interest (WI) in Blocks SEAL-M-351 and SEAL-M-428, located in the deep water Sergipe-Alagoas Basin, offshore Brazil.
QGEP will retain a 30% WI in the blocks, and in a related but separate transaction, ExxonMobil Exploração Brasil Ltda. (an affiliate of ExxonMobil Corp.) has farmed into the remaining 50% WI as the operator. The blocks are located 80 to 100 kilometers (50 to 60 miles) off the coast of Brazil and cover a total area of approximately 1,500 square kilometers (580 square miles).
In addition, Murphy and its partners are the high bidder in Brazil's Round 14 lease sale for Blocks SEAL-M-501 and SEAL-M-503, which are adjacent to SEAL-M-351 and SEAL-M-428. ExxonMobil will operate and the partners will maintain the same WI in each of these blocks. These new acreage positions are near several major Petrobras discoveries.
Murphy Oil Corp. is a global independent oil and natural gas exploration and production company. The company's resource base includes offshore production in Southeast Asia, Canada and Gulf of Mexico, as well as North America onshore plays in the Eagle Ford Shale, Kaybob Duvernay and Montney.
Gazprom planning second subsea project offshore Sakhalin
Gazprom expects to finish development drilling this year at the Kirinskoye field offshore Sakhalin Island.
Head of Department Vsevolod Cherepanov, speaking at the Sakhalin Oil & Gas 2017 conference, said production at the field, part of the Sakhalin III project, is dedicated to consumers in Russia's Primorye Territory and the north of the Sakhalin region.
It was the first Russian field to be developed using subsea production technologies. With new producing wells in operation, the field should gradually reach the planned plateau of 5.5 bcm/yr.
Gazprom continues to conduct geological exploration in the Kirinsky, Vostochno-Odoptinsky and Ayashsky blocks in the same Sakhalin III project.
The Yuzhno-Kirinskoye gas field remains at the pre-development stage, with design studies under way for a wholly subsea project.
Gazprom is also continuing its LNG projects in Sakhalin, said Alexander Medvedev, deputy chairman of the company's Management Committee, with design documentation nearly completed for the island's LNG plant's third train.
This will have an annual capacity of up to 5.4 MM tons. -Offshore staff
Extra time for BP and partners at Azeri-Chirag-Guneshli
BP and Azerbaijan today signed a deal extending a production sharing contract for the super-giant Azeri-Chirag-Guneshli (ACG) field, the largest field in the Azerbaijani sector of the Caspian Sea, until 2050.
Commenting on the extension, Laura Bennie, research analyst with Wood Mackenzie's upstream Caspian team, said: "Finalizing the contract extension is fitting recognition of the value that ACG represents - not only for BP and its partners, but also the Azerbaijani economy. The combination of the extension, bonus payment and increased SOCAR stake looks like a balanced outcome.
"For the international partners, it's all about moving down the cost curve and securing long-life assets. Finalizing the ACG contract extension is right on trend for BP and partners - the fruits of many years of talks."
Bennie added: "For Azerbaijan, this reaffirms the wider commitment to its oil and gas industry and the future revenues it will bring.
"ACG production may now be below 600,000 barrels per day, but there are still billions of barrels to recover and billions of dollars to invest. Attention will now turn to a brand-new production platform [Azeri Central East], which will be commissioned in the 2020s."
The production sharing contract extension is pivotal for the post-2024 outlook for Azerbaijan's oil sector. ACG currently produces 75% of Azerbaijan's liquids production, and is the lifeblood of its economy.
The existing PSC is due to expire in 2024. The new deal sees SOCAR increase its stake in the ACG consortium to 25% from 11.65%, while BP, which remains operator, sees its interest drop from 35.8% to 30.37%.
The other consortium partners have also seen their stakes reduce. Chevron now holds 9.57%, Inpex 9.31%, Statoil 7.27%, ExxonMobil 6.79%, TPAO 5.73%, Itochu 3.65% and ONGC Videsh 2.31%.
Latest Wisting appraisal well proves oil in Barents Sea
The semisubmersible Island Innovator has finished drilling appraisal well 7324/8-3 on the Wisting oil discovery in the Barents Sea.
According to the Norwegian Petroleum Directorate, the well was drilled in 396 m (1,300 ft) of water in license PL 537, 2 km (1.2 mi) south of the discovery well 7324/8-1 and 315 km (196 mi) north of Hammerfest.
Prior to drilling this latest well, OMV had estimated the Wisting area's resources in in the range of 22-80 MMcmoe.
The well encountered a 55-m (180-ft) oil column in sandstones from the Mid-Jurassic to Late Triassic (Stø and Fruholmen formations). The former had better reservoir characteristics.
In addition, the rig conducted a successful water injection test in the Stø formation, confirming good injection properties.
The well, which will be permanently P&A'd, was the sixth on the license. -Offshore staff
