GENERAL INTEREST — Quick Takes
NIOC qualifies 29 firms for tender round
National Iranian Oil Co. has designated 29 non-Iranian companies as qualified to participate in its pending tender round for upstream projects.
The long-delayed round will use the country's new Iran Petroleum Contract, a service contract more flexible than the largely unsuccessful buyback contract (OGJ Online, Sept. 1, 2016).
The companies are CEPSA of Spain, CNOOC International Ltd., CNPC, CNPW, DNO, Eni, Gazprom, Inpex Corp., Itochu, and Japan Petroleum Exploration.
Also on the list are Korea Gas Corp., Lukoil, Maersk, Mitsubishi Corp., Mitsui, OMV, ONGC Videsh Ltd., Perenco Holding, Pertamina, and Petronas.
Others are PGNiG, Pluspetrol, POSCO Daewoo, PTTEP, Schlumberger, Shell, Sinopec International, Total, and Wintershall.
BP awarded 10% interest in ADCO concession
BP PLC has signed an deal with the Supreme Petroleum Council of Abu Dhabi and Abu Dhabi National Oil Co. (ADNOC) that grants BP 10% interest in Abu Dhabi Co. for Onshore Petroleum Operations Ltd.'s (ADCO) onshore oil concession.
In addition to the interest in the ADCO concession, BP becomes a 10% shareholder in ADCO, which operates the concession. The agreement includes BP becoming asset leader for the Bab asset group within the concession.
In connection with the transaction, BP has agreed to issue new ordinary shares representing about 2% of BP's issued share capital, to be held on behalf of the Abu Dhabi government.
BP becomes a 10% shareholder of ADCO and the concession alongside Total SA 10%, Inpex Corp. 5%, and GS Energy 3%. ADNOC continues to look for partners to take up the remaining 12% stake of the 40% earmarked for foreign partners.
The ADCO concession, including Bab, Bu Hasa, Shah, and Asab fields, has total resources of 20-30 billion bbl of oil equivalent over the term of the concession. The overall production in 2016 is expected to average 1.66 million b/d of oil. The concession, put in place in January 2015, is valid until yearend 2054.
BP has been present in Abu Dhabi since 1939. Since the 1970s, BP held 9.5% interest in the ADCO onshore concession that expired in late-2014. It also holds 14.67% interest in the offshore concession and ADMA-OPCO, which operates this concession, and 10% interests in both the Abu Dhabi Gas Liquefaction Co. and National Gas Shipping Co.
SM Energy to sell Eagle Ford assets for $800 million
A subsidiary of Venado Oil & Gas LLC, an Austin-based affiliate of private equity firm KKR & Co. LP, has agreed to acquire nonoperated Eagle Ford assets owned by SM Energy Co., Denver, for $800 million.
The assets cover 37,500 net acres in the Maverick basin-Eagle Ford area of South Texas and 12.5% interest in the Springfield gathering system. As of yearend 2015, net proved reserves associated with the assets were 65 million boe, of which 38% was oil, 31% natural gas, and 31% NGLs. In third-quarter 2016, the assets produced 27,260 boe/d net, of which 33% was oil, 33% natural gas, and 34% NGLs.
The deal, effective Nov. 1, is expected to close in this year's first quarter.
"The proceeds from this sale will provide us with additional flexibility to pursue aggressive growth from our Midland basin assets, with related capital expenditures in excess of cash flow over the next few years, while at the same time improving our debt metrics and maintaining strong liquidity," explained Jay Ottoson, SM Energy president and chief executive officer.
SM Energy's first deal of 2017 follows a 2016 in which the firm spent about $2.5 billion to boost its position in the Midland basin with moves that were, in part, funded by asset divestitures, including its sale of 55,000 net acres in the Williston basin to Oasis Petroleum Inc. for $785 million.
The firm's Midland expansion comprised a $980-million purchase of 24,783 net acres in Howard County, Tex., from private equity firm Riverstone Holdings LLC; and $1.6-billion purchase of 35,700 net acres in Howard and Martin counties of West Texas from a portfolio company of EnCap Investments LP and a related entity.
SM Energy has 87,600 net acres in the Midland basin.
Exploration & Development — Quick Takes
ExxonMobil finds gas onshore Papua New Guinea
ExxonMobil Corp.'s Muruk-1 well was drilled to 10,630 ft and encountered similar high-quality sandstone reservoirs as in Hides field 13 miles to the southeast. Hides field is the main source of gas for the new Papua New Guinea LNG project.
According to ExxonMobil, the well results were in line with predrill estimates, suggesting the Muruk-1's target Toro formation could contain 2 tcf of gas (OGJ Online, Nov. 17, 2016). Santos Ltd. subsidiary Barracuda Ltd. recently signed a farm-in agreement with ExxonMobil and Oil Search Ltd. to take a 20% interest in the highlands permit PPL 402, which covers 126,000 acres. Oil Search spudded Muruk-1 on Nov. 2, 2016. Evaluation is ongoing of the Toro formation, but the Muruk-1's early result "underpins the PNG LNG project," ExxonMobil Pres. Steve Greenlee said.
ExxonMobil owns 42.5% interest in PPL 402, Oil Search is operator with 37.5% interest, and Santos owns 20%.
Aker BP makes North Sea oil find near Frigg field
The Norwegian Petroleum Directorate reported that Aker BP ASA has made an oil discovery near Frigg field in the North Sea. Wildcat 25/2-18 S encountered two oil columns in the Hugin formation, both of which had 20 m of sandstones with moderate-to-good reservoir quality.
The objective was to prove petroleum in Middle Jurassic reservoir rocks in the Hugin and Sleipner formations of the Vestland group.
Aker BP also drilled three appraisal wells, one of which was dry. Appraisal well 25/2-18 A, drilled 1 km southeast of the wildcat, also encountered two oil columns in the Hugin, both with about 25 m of sandstones with moderate-to-good reservoir quality. Two formation tests showed moderate flow properties. Maximum oil production rate was 600 cu m/day through a 40/64-in. choke in the lower zone.
Appraisal well 25/2-18 B, drilled 1.4 km north of the wildcat, was dry.
Appraisal well 25/2-18 C, drilled 1 km west of the wildcat, encountered three oil columns in the Hugin, with 15 m, 11 m, and 10 m of sandstones with moderate-to-good reservoir quality. A 7-m condensate column had 3 m of sandstones of moderate quality.
All four wells were terminated in the Dunlin group of the Lower Jurassic. Drilling took place in PL 442, which was awarded in APA 2006.
The wells were drilled using the Maersk Interceptor jack up in 121 m of water. The rig will proceed to PL 001B in the Ivar Aasen area with a plan to drill three water injectors and one oil producer.
Cobalt hits oil pay with North Platte appraisal well
The Cobalt International Energy Inc.-operated North Platte No. 4 appraisal well in the Gulf of Mexico encountered 650 ft of net oil pay, which is greater than the 550 ft of net pay found in the North Platte No. 3 appraisal well in 2015.
The North Platte No. 4 initial appraisal results also indicate high-quality Inboard Lower Tertiary Wilcox reservoirs on the eastern flank of North Platte field, the firm says.
Cobalt is currently evaluating log data, fluid samples, and pressure information, and is preparing for a geologic sidetrack to further analyze the extent of the eastern flank of the field.
The geologic sidetrack is expected to be completed in the first quarter.
"The confirmation of high-quality reservoir on the large eastern flank of the field is encouraging," said Cobalt CEO Timothy J. Cutt. Cobalt says an update to the resource potential will be provided following the sidetrack operations.
Cobalt holds 60% working interest in North Platte. Total E&P USA Inc. has the remaining 40%.
Statoil outlines exploration plans for 2017
Statoil ASA plans to drill about 30 exploration wells in 2017 as operator and partner, an increase of about 30% compared with the 23 in 2016.
More than half of the wells will be drilled on the Norwegian Continental Shelf. Statoil expects 16-18 wells to be completed there compared with 14 in 2016. Discoveries are "crucial" to counteract NCS decline, the company said.
The program "is balanced between proven, well-known basins and new frontier opportunities," said Tim Dodson, executive vice-president, exploration.
A 5-7 well exploration campaign is planned in the Barents Sea. Statoil plans to test targets in the relatively well-known geology in the Johan Castberg and Hoop-Wisting areas, and new frontier opportunities with greater geological uncertainty but high-impact potential.
In the Norwegian Sea and North Sea, Statoil seeks to prove near-field volumes to prolong the productive life of existing infrastructure and determine growth potential.
Statoil plans three operated wells in the UK. Partner-operated wells are planned in the US Gulf of Mexico, Indonesia, Suriname, Russia, and Turkey.
Statoil also noted that Brazil has become more important since the company became operator of the Carcara discovery last year, but the company did not provide well plans.
Drilling & Production — Quick Takes
Production starts at Ivar Aasen field in North Sea
Ivar Aasen oil field in the Norwegian North Sea has begun producing (OGJ Online, Oct. 25, 2016).
Oil production began Dec. 24, some 4 years after the plan for development and operation was submitted.
Reserves are estimated at 186 million boe, said operator Aker BP ASA. Depending on oil prices and production development, Aker BP said Ivar Aasen may have a 20-year economic life.
Production capacity is 68,000 boe/d, said Wintershall Norge AS, an interest owner.
Earlier this year, a 15,000-tonne topside was lifted into place. In recent months, Ivar Aasen had an offshore workforce of 400-500 to prepare for production startup.
The field is in the Utsira High, about 175 km west of Karmoy. Ivar Aasen development includes five licenses.
Oil and natural gas from Ivar Aasen is processed and exported from the Edvard Grieg platform, which also supplies power to Ivar Aasen. Edvard Grieg started producing late last year (OGJ Online, Nov. 30, 2015).
Interest holders in Ivar Aasen are Aker BP 34.7862%, Statoil Petroleum 41.473%, Bayerngas Norge 12.3173%, Wintershall Norge 6.4651%, VNG Norge 3.023%, Lundin Norway 1.385%, and OKEA 0.554%.
Wintershall to complete 12-well program by spring
Wintershall Holding GMBH aims to complete a 12-well drilling program this spring in northwest Germany at a cost of about €30 million.
The program started in September and six wells have been completed in Emlichheim field in Lower Saxony near the Dutch border.
The wells are connected to the Bentheimer sandstone at depths of 700-900 m.
Four of the 12 wells will be used to inject steam into the reservoir under high pressure at a temperature of 300° C.
Steam flooding and horizontal drilling have resulted in an above-average oil recovery rate of more than 40%, the company said. Wintershall expects the field to continue producing for another 25 years (OGJ Online, Feb. 12, 2015).
Ohio judge to allow injection well to reopen
An Ohio judge has asked the operator of a closed injection well to submit a plan to reopen the well in Trumbull County's Weatherfield Township, about 65 miles southeast of Cleveland. The well was closed in 2014 because it was believed linked to two nearby small earthquakes.
An Ohio Department of Natural Resources (ODNR) spokesman said state attorneys are considering a response to the judge's order.
Franklin County Common Pleas Judge Kimberly Cocroft ordered the state and well operator, American Water Management Services (AWMS), to submit language for a judgment order to reopen the well.
Cocroft said the state had the authority to shut down the well after earthquakes were detected in July-August 2014. But Cocroft also said the Division of Oil & Gas Resources Management should have allowed AWMS to resume operations after submitting a plan to pump brine at lower pressures and volumes.
Some scientists suggest that injecting waste fluid below ground causes existing faults to become stressed, triggering earthquakes. In 2012-13, ODNR expanded its seismic monitoring around Class II injection wells.
Updates to Ohio state law call for rules that go beyond requirements mandated by the US Environmental Protection Agency for Class II injection wells.
The Seismological Society of America published a related article in 2016 in which professors from Miami University in Ohio linked 2014 earthquakes in Poland Township, Ohio, to hydraulic fracturing activities believed to have activated a previously unknown fault.
Scientists said it's rare for hydraulic fracturing to cause earthquakes that can be felt above ground by humans but that increased seismic monitoring is detecting more earthquakes than might have been reported otherwise.
PROCESSING — Quick Takes
Chinese firm, Kazakhstan form Romanian refining JV
Privately held CEFC China Energy Co. Ltd., Shanghai, has agreed to acquire 51% of shares in KMG International NV-the refining, petrochemicals, retail, and trading arm of Kazakhstan's state-owned KazMunayGas-as part of the creation of a joint venture designed to extend participation of China and Kazakhstan in development of downstream projects to serve European markets.
As part of the agreement, signed on Dec. 15 in Bucharest, CEFC will undertake a number of investments in Europe and Silk Road countries to jointly develop with KMGI projects in the fields of refining and retail outlet networks, KMG and KMGI (formerly Rompetrol SA) subsidiary Rompetrol Rafinare SA said.
The deal also calls for CEFC's commitment to support implementation of KMGI's development plans in Romania and the Black Sea region, which include works to expand KMGI's overall refining capacity to 10 million tonnes/year, as well as project investments to help sustain and extend operations of Rompetrol Rafinare's 5 million-tpy Petromidia refinery in Navodari, Romania, KMGI said.
While jointly developed projects will be executed abroad, most of the major projects to be implemented as part of the strategic agreement between CEFC and KMG will be located in Romania, which is the business priority, KMGI said.
Pending final approvals from Romanian regulators, the European Commission, and respective financial institutions, the transaction is scheduled to be completed during first-half 2017, says KMG, which will hold 49% interest in the newly formed JV.
Specific financial details of the proposed partnership were not disclosed.
Alongside the Petromidia refinery, KMGI, through Rompetrol Rafinare, also owns the 305,000-tpy Vega refinery in Pahova County, near Ploiesti, Romania.
Lucid expands Delaware basin gathering, processing
Lucid Energy Group LLC, Dallas, has completed part of the ongoing, planned expansion of its gas gathering and processing capacity in the Delaware basin of Eddy and Lea counties, NM (OGJ Online, Sept. 2, 2016).
Alongside raising capacity of its recently acquired Red Hills cryogenic processing plant in Lea County to 110 MMcfd from 60 MMcfd, the company also has commissioned two compressor stations and liquids-handling capability at eight existing compressor stations that have resulted in an 80-Mcfd increase in gathering capacity along its South Carlsbad system, Lucid said.
The company currently is in the process of building a 200-MMcfd cryogenic processing train and amine treating installations at the Red Hills plant, as well as 80 miles of gathering pipeline within the South Carlsbad system.
The incremental expansions follow Lucid Energy Group II LLC's Aug. 30 purchase of Agave Energy Co.'s midstream infrastructure in southeastern New Mexico's Delaware basin and the Powder River basin of eastern Wyoming, at which time Lucid announced plans to grow the former Agave gathering and processing assets.
Scheduled to be commissioned in mid-2017, the cryogenic processing train at Red Hills will increase overall processing capacity of the complex to 310 MMcfd.
Enterprise Products restarts Pascagoula gas plant
Enterprise Products Partners LP (EPP) has restarted its 1.5-bcfd Pascagoula natural gas processing plant in Moss Point, Miss., following a nearly 6-month shutdown to repair damage resulting from a late-June fire (OGJ Online, June 28, 2016).
With all necessary repairs now completed, EPP has returned the Pascagoula plant to service, the company said.
EPP disclosed no details regarding the plant's current operational rates or the extent of repairs required prior to its restart.
At the time of the June 27 incident, the three-trained Pascagoula gas plant was averaging about 400 MMcfd of inlet-gas volumes.
While its investigation into the cause of the June 27 explosion and subsequent fire remains ongoing, the US Chemical Safety Board (CSB) has confirmed the event was limited to only one of the plant's cryogenic processing trains, according to the minutes of a CSB business meeting held July 27.
While multiple piping and vessel ruptures at the plant had been identified by late July, CSB said it expected determining potential sources for the explosion would require complex work given significant damage caused by incident.
TRANSPORTATION — Quick Takes
EnLink to divest assets, invest in STACK processing
The EnLink Midstream companies will receive $275 million from combined noncore asset sales and invest $100 million in 2017 to construct a new gas processing plant in the Sooner Trend Anadarko basin Canadian and Kingfisher counties (STACK) play of Oklahoma.
EnLink has agreed to divest its 31% common ownership interest in Howard Midstream Energy Partners LLC (HEP) for $190 million. Alberta Investment Management Corp. (AIMCo) and management will acquire a common ownership stake in HEP as a result of EnLink's divestiture, which follows AIMCo's preferred investment in HEP in August.
EnLink also has closed the sale of the North Texas Pipeline, which comprises 140 miles of natural gas transportation pipeline in the Barnett shale, to Atmos Energy Corp.
Proceeds from the sales and planned 2017 estimated at-the-market equity issuances are expected to fund a majority of the equity portion of EnLink's 2017 capital expenditure requirements, including the upcoming $250-million installment payment related to the acquisition of certain Tall Oak Midstream LLC subsidiaries (OGJ Online, Dec. 7, 2016).
In response to producer activity and well results in the STACK, EnLink is proceeding with the development of Chisholm III, a 200-MMcfd processing expansion of its existing Central Oklahoma system that is expected to be operational by yearend 2017.
Upon completion of the Chisholm III expansion, EnLink's Central Oklahoma processing capacity will total 1 bcfd, which represents nearly a threefold increase from the 350 MMcfd of capacity operated in 2015. EnLink's Central Oklahoma platform is underwritten by long-term, fee-based contracts from major producers.
EnLink says its incremental processing capacity will also generate meaningful increases in NGLs produced from the Central Oklahoma platform, which will in turn be transported on the company's Cajun-Sibon pipeline. The NGL output increases are expected to benefit the entirety of the company's Louisiana NGL footprint and current estimates project that throughput on Cajun-Sibon will reach capacity in second-quarter 2017.
FERC issues final EIS for Atlantic Sunrise project
The US Federal Energy Regulatory Commission has issued its final Environmental Impact Statement for Williams Partners' Atlantic Sunrise project.
The issuance of the final EIS is a key step toward FERC's final decision on the project, which is expected early this year.
Following the receipt of all necessary regulatory approvals, Williams Partners anticipates beginning construction in mid-2017, allowing for a full in-service of the project in mid-2018.
The expansion will add 1.7 million dekatherms/day of pipeline capacity to the 8.4 million-dekatherm/day Transco pipeline system.
The project will consist of compression and looping of the Transco Leidy line in Pennsylvania along with a greenfield pipeline segment, referred to as the Central Penn line, connecting the northeastern Marcellus region to the Transco mainline near Station 195 in southeastern Pennsylvania.
The preliminary project design includes 183 miles of new greenfield pipe (Central Penn North and Central Penn South), two pipeline loops totaling 12 miles (Chapman Loop, Unity Loop), 2.5 miles of existing pipeline replacement, two compressor facilities in Pennsylvania, and other facility additions or modifications in Pennsylvania, Maryland, Virginia, North Carolina, South Carolina.
In addition to previously announced gas sale and purchase agreements related to its 850,000 MMbtu/day of transportation capacity on the project, Cabot Oil & Gas Corp. reported the execution of a new definitive gas sale and purchase agreement with an undisclosed company.
Under terms of the new agreement, Cabot has agreed to sell an additional 150,000 MMbtu/day of gas for a 3-year term starting on the full in-service of the Atlantic Sunrise project.