ADNOC furthers concession split, ups partnership model
Abu Dhabi National Oil Co. (ADNOC) is working to boost oil production to 3.5 million b/d in 2018 with offshore development being its primary focus.
The company announced in July that it is expanding its partnership model to open more concession opportunities. The new approach targets market access, long-term capital, and technological expertise to deliver growth. Abu Dhabi Marine Operating Co. (ADMA-OPCO) operates Abu Dhabi's offshore concession, which expires in March 2018, and ADNOC is in advanced discussions with more than a dozen potential partners who have expressed an interest, including a mix of existing concession holders in ADNOC's offshore fields and new participants. ADMA-OPCO produces 700,000 b/d of oil, and is expected to increase production to 1 million b/d by 2021.
The existing ADMA-OPCO concession will be split into two or more new concessions with new terms and will be comprised of a mix of Lower Zakum, Umm Shaif, Nasr, Umm Lulu, and Satah Al Razboot (SARB) fields. ADNOC will retain 60% interest in the new concession areas.
ADNOC announced in 2016 its effort to consolidate ADMA-OPCO offshore operations and Zakum Development Co. (ZADCO). The new ADMA-OPCO concessions and the existing Upper Zakum concession, operated by ZADCO, will be operated by the new integrated offshore company. The consolidation of the two companies is due to be completed before yearend.
The company said expansion of its partnership model is part of its "ADNOC 2030" strategy, which envisions higher oil production capacity and innovation in enhanced oil recovery, expansion of petrochemical production to 11.4 million tonnes/year by 2025 from the current 4.5 million tpy, and further development of natural gas resources.
Existing shareholders in ADMA-OPCO are BP PLC 14.67%, Total SA 13.33%, and Japan Oil Development Co. (JODCO) 12%. The international shareholders in ZADCO are ExxonMobil Corp. 28% and JODCO 12%. The Abu Dhabi government, through ADNOC, has a 60% interest in both operating companies.
NNPC gets financing for Chevron, Shell JVs
Nigerian National Petroleum Corp. has signed agreements with joint ventures led by Chevron Corp. and Royal Dutch Shell PLC accommodating third-party financing of its cash commitments for oil and gas development.
The agreement involving the NNPC-Chevron Nigeria Ltd. JV covers $780 million remaining to fund development of Sonam natural gas field, in which Chevron Nigeria has invested $1.5 billion. Chevron expects the shallow-water project, tied to the Escravos gas plant, to produce 215 MMcfd of gas and 30,000 b/d of liquids.
Of the amount in the agreement, $380 million will cover NNPC's 2016 cash commitment. The rest will support drilling of seven wells in Sonam field on Oil Mining License (OML) 91 and the Okan 30E nonassociated gas well on OML 90 as well as completion of associated facilities.
The other agreement, with third-party financing totaling $1 billion, will allow the NNPC-Shell Petroleum Development Co. JV to conduct 156 "development activities" in 30 fields over 12 OMLs in the Niger Delta, NNPC said.
A first phase of the work will include 128 "rigless activities" and 10 workovers. A second phase will further develop EA and EJA shallow-water fields with the drilling of 14 wells and the workover of 3 wells.
Rockliff, Samson ink Texas-Louisiana deal
Privately held Rockliff Energy II LLC, Houston, has agreed to buy the East Texas and North Louisiana properties of Samson Resources II LLC, Tulsa, for $525 million.
The deal covers 210,000 net acres producing a net 90 MMcfd of natural gas equivalent.
Samson Resources II acquired the assets of Samson Resources Corp. out of bankruptcy.
It said it will focus on developing its Wyoming leasehold, 146,000 net acres in the Powder River basin and 59,000 net acres in the Green River basin, "and will explore a number of strategic and development opportunities."
Pacific Drilling says bankruptcy possible
Pacific Drilling SA, Luxembourg, stung by lingering problems in the deepwater oil and gas industry, raised the possibility of bankruptcy in its report of second-quarter financial results.
In a press statement, the company said it is "evaluating various alternatives to address its liquidity and capital structure, which may include a private restructuring or a negotiated restructuring of its debt under protection of Chapter 11 of the US Bankruptcy Code."
It reported a net loss of $138.1 million in this year's second quarter compared with net income of $8.2 million in second-quarter 2016. The firm owns seven high-spec drillships.
Paul Reese, who recently succeeded Chris Beckett as chief executive officer, noted signs of an upturn. "Lately, we have received an increase in market inquiries for projects in several deepwater regions of the world starting sometime in 2018, which is promising," he said.
Twinza signs deal for Pasca A field development
Twinza Oil Ltd., Perth, has signed an agreement for the provision of support on its Pasca A gas-condensate field development in the Gulf of Papua. The agreement, signed with Baker Hughes, includes drilling services, wellheads, and pressure-control equipment for the coming fourth and final appraisal well in the field. The well will be drilled in the next 2 months and suspended as a future development well.
The final investment decision on the Pasca A project is expected in 2018. Once FID has been reached, Baker Hughes will provide an integrated gas processing solution from the wells through to point of export.
Called the first of its kind in the industry, the fullstream agreement includes a wide range of services. Apart from drilling, it comprises subsea equipment, gas processing topsides, gas compression and turbomachinery, as well as installation and commissioning.
Last month Twinza signed a contract with China Oilfield Services Ltd. for use of the COSL Seeker jack up rig to drill the appraisal well in Pasca A field.
The company submitted an environmental impact statement for the development program in August 2016 with a plan to initially strip condensate and LPG from the gas flow. The LPG and condensate is to be fed into two separate floating production, storage, and offloading vessels while the dry gas is to be reinjected into the reservoir for later redevelopment.
Twinza estimates Pasca A contains 19 million bbl of condensate and 20 million bbl of LPG. The propane component of the LPG will be sold into Papua New Guinea's domestic market while the condensate, butane, and excess propane will be exported. The liquids project is expected to have a 20-year lifespan with a development cost of $250-550 million.
The subsequent gas production options include installation of a floating LNG facility or a pipeline to shore.
Pasca is a carbonate pinnacle reef structure that lies in permit PPL328 in 93 m of water 85 km from the nearest point on the Gulf of Papua coast and 265 km west of Port Moresby.
Cairn-led JV makes oil discovery offshore Senegal
A Cairn Energy PLC-led joint venture has made an oil discovery offshore Senegal with its SNE North-1 wildcat well drilled in the Sirius prospect north of recently discovered SNE oil field.
SNE North-1 encountered oil in three separate intervals and it is possible a fourth reservoir zone also is present.
JV member FAR Ltd., Perth, reported that the intervals include an oil and gas column in the S520 zone that is the high-quality, lower reservoir in the SNE field. SNE North-1 encountered this reservoir deeper than SNE field oil-water contact.
The JV recovered samples of 35° gravity oil, which is lighter than the oil in SNE, as well as water and gas to surface.
SNE North-1 is in 900 m of water about 90 km offshore in the Sangomar Deep Offshore block and 15 km north of the SNE-1 discovery well.
The combine is now working to determine the extent of the hydrocarbon accumulation and integrate the results with block-wide data gathered so far. FAR believes the well result has positive implications for further exploration potential to the north along the structural trend containing SNE field.
FAR says the preliminary analysis indicates SNE North-1 has encountered in excess of 24 m of gross hydrocarbon column across at least three intervals. Of that, in excess of 16 m of net hydrocarbons are in high quality reservoirs.
The well has been plugged and abandoned as planned. It is the last well in the five-well 2017 drilling campaign and the rig Stella DrillMAX is being released.
The JV is reviewing the potential for further exploration drilling in 2018 within the Rufisque, Sangomar, and Sangomar Deep production-sharing contract area.
BP reports productive Mancos shale well test
BP PLC recorded an average 30-day initial production rate of 12.9 MMcfd of natural gas from its BU 602 Com 1H well in San Juan County, NM, part of the San Juan basin.
The well was drilled with a 10,000-ft lateral in an area known as the Northeast Blanco Unit (NEBU), a section of federal lands in San Juan and Rio Arriba counties of New Mexico where BP has had a presence since the 1920s.
The well test took place on assets BP acquired from Devon Energy Corp. in late 2015, which expanded BP's existing position in the San Juan basin and provided better access to the Mancos shale.
"This result supports our strategic view that significant resource potential exists in the San Juan basin and gives us confidence to pursue additional development of the Mancos shale, which we believe could become one of the leading shale plays in the US," commented Dave Lawler, chief executive officer of BP's US Lower 48 onshore business.
BP's Lower 48 unit operates 3,900 wells in the San Juan basin of New Mexico and Colorado. It expects to open a new headquarters office in Denver in 2018 that will be closer to the majority of its operated assets in the Rocky Mountain region.
Drilling & Production — Quick TakesEngie starts gas flow from Cygnus Bravo
Engie E&P UK Ltd. has started natural gas production from Cygnus Bravo, the satellite wellhead platform in the firm's operated Cygnus development in the southern North Sea.
Gas from Bravo was exported 7 km southeast to Cygnus Alpha, which itself has been producing at a plateau of 250 MMcfd since December. Combined output then travels from the Alpha processing unit, 150 km offshore Lincolnshire, UK, via a 55-km link to the Esmond Transmission System that ultimately lands at the Bacton gas terminal in Norfolk.
The overall Cygnus complex comprises four platforms and two subsea structures, serving a field size of 250 sq km.
Bravo gas flowed from Well B5 in one of the platform's 10-well slots out of 20 across the Cygnus complex. A further three Bravo wells are expected to come online in August with a total of five available in 2018 after drilling of Well B1 is completed.
Cygnus has estimated 2P reserves of 110 million boe and an expected production life of more than 20 years. In addition to output from the complex itself, the partners are evaluating further opportunities in the Greater Cygnus area with the aim of bringing additional volumes through Cygnus when capacity becomes available.
Cygnus was discovered in 1988 and sanctioned in 2012 following the UK government's decision to introduce a field allowance for new large gas fields in shallow water.
Engie E&P UK has 38.75% interest in Cygnus. Partners Centrica PLC and Bayerngas GMBH have 48.75% and 12.5%, respectively. An agreement to merge Centrica's European oil and gas exploration and production business and Bayerngas Norge AS was struck last month.
Hangingstone project expansion brought online
CNOOC Ltd., owner of Nexen Energy ULC, said the Hangingstone expansion commercial project in Canada has come on stream. Japan Canada Oil Sands Ltd. (JACOS) is the operator with 75% working interest.
Nexen has 25% working interest in Hangingstone, an oil sands steam-assisted gravity drainage (SAGD) project about 20 km southwest of Fort McMurray, Alta.
The Alberta project involves steam-generating equipment, well pads, 32 well pairs, water treatment, and bitumen flowlines. The project is expected to reach its peak production of 20,000 b/d of bitumen in 2018.
JACOS and its partners experimented with a cyclic steam stimulation pilot project on the Hangingstone pilot during the 1980s and 1990s. JAPEX participated in experiments at the underground test facility before committing to SAGD technology at Hangingstone.
Rosneft posts production increases in first half
Rosneft PJSC said first-half hydrocarbon production averaged 5.74 million boe/d, up 10.2% vs. first-half 2016. The company cited acquisitions and new projects development.
First-half liquids production increased 11.4% while natural gas production increased 2.9%.
Rosneft said liquids production declined 1.2% in the second quarter vs. the first quarter due to limitations for Russian oil producers related to agreements with the Organization of Petroleum Exporting Countries.
Capital expenditures of 407 billion rubles in the first half were up by 32.1% vs. the first half of 2016. Development drilling in km was up 21.9%.
Acquisition of 3D seismic in sq km was up 16.5% in the first half while acquisition of 2D seismic in km was more than four times greater than a year earlier.
Refining throughput in the first half increased 24.3%.
Rosneft's first-half financial performance included a 23.2% revenue increase in rubles, while revenues in US dollar terms increased by 48.7%.
PROCESSING — Quick TakesNeste enters home stretch of refinery integration
Neste Corp. will begin a 2-month planned maintenance turnaround starting in mid-August at its 3 million-tonne/year refinery in Naantali, Finland, that, once executed, will complete the previously announced investment plan to integrate operations of its two Finnish refineries under uniform management.
The major turnaround-the most extensive ever carried out at the refinery and its first since 2012-will cost a total of €90-million, the sum of which consists of routine-turnaround investments, associated maintenance investments, and the value of lost production during the shutdown period, Neste said.
The scheduled maintenance follows more than 700 days of work related to the change of the refinery's production structure already completed during normal operations at the site.
First announced in October 2014, Neste's €500-million project to integrate the Naantali refinery with its 10.5 million-tpy Porvoo refinery into a single Finnish refining system comes as part of the company's plan to improve the competitiveness of its overall refining operations.
Following its reconfiguration, the Naantali will continue to produce diesel and specialty products, including solvents and bitumen, and maintain an important role in producing feedstocks, such as vacuum gas oil, for production lines in Porvoo.
Additionally, gasoline components produced at Naantali will be refined into finished products at Porvoo, with Naantali's terminal capacity to be used for distributing Porvoo's gasoline production.
Consolidation of the two Finnish refineries also will enable Neste to increase diesel output alongside a simultaneous reduction in heavy fuel oil production from the integrated unit.
Matti Lehmus, Neste's executive vice-president of oil products, said the company is targeting an additional margin of at least $5.50/bbl once the new Naantali-Porvoo operating model becomes operational.
Shell's Rheinland refinery considers revamp
Management of Royal Dutch Shell PLC subsidiary Shell Deutschland Oil GMBH is evaluating the potential expansion of residual processing capacity at the 140,000-b/d refinery at Wesseling, Germany, which together with the former Godorf refinery near Cologne-Godorf, form its 325,000-b/d integrated Rheinland refinery, Germany's largest.
In early August, refinery management began holding initial talks with representatives from local government and environmental associations to present preliminary plans for a potential investment project that would expand capacity of Wesseling's residue processing plant as part of a series of measures aimed enabling production of fuels that will conform to the International Maritime Organization's (IMO) more stringent maximum-permitted sulfur levels for marine fuels taking effect on Jan. 1, 2020, Shell Deutschland said.
Still early in the process, the operator does not plan to formally submit the project for approval or release further details regarding the proposed expansion until it has received adequate feedback from government and environmental stakeholders in the region, said Jorg Dehmel, head of technology at the Rheinland refinery.
Shell Deutschland, which confirmed plans to continue talks with interested parties about the modernization project, did not disclose a definitive timeframe for when it might make a decision regarding the possible expansion.
The investment at Wesseling follows an October 2016 vote by the IMO's Marine Environment Protection Committee to implement a 0.5% global sulfur cap on marine fuel starting in 2020.
Oman-Kuwait JV lets contract for DRPIC integration
Duqm Refinery & Petrochemical Industries Co. LLC (DRPIC), Muscat, a joint venture of state-owned Oman Oil Co. and Kuwait Petroleum Corp. subsidiary Kuwait Petroleum International Ltd., has awarded the first of three main packages for engineering, procurement, and construction of its long-planned 230,000-b/d refinery and petchem complex to be built in the Duqm Special Economic Zone in Duqm, Al Wusta Governate.
DRPIC has let a contract to a consortium of Petrofac International Ltd. and Samsung Engineering Co. Ltd. for EPC Package 2, which covers all utilities and offsites for the project.
As part of the $2-billion contract, the Petrofac-Samsung partnership will deliver EPC as well as commissioning, training, and other services for the refinery's utilities and offsites.
The consortium's scope of work under the 47-month contract is scheduled to begin shortly, Petrofac said.
While it has confirmed site preparation for the project is now completed, DRPIC has yet to announce which of its prequalified bidders will receive the contract award for EPC Package 1, which alongside commissioning and additional startup work, includes EPC services for all equipment and structures required for the integrated complex's main processing units.
DRPIC also is awaiting responses from a separate group of prequalified bidders to determine award of the project's EPC Package 3, according to the operator's web site.
The winner of the EPC Package 3 contract will provide EPC, commissioning, and operation services for associated offsite facilities, including a product storage and export terminal in Duqm, crude storage tanks in Ras Markaz, and an 80-km crude oil pipeline from Ras Markaz to the refinery complex.
TRANSPORTATION — Quick TakesGas pipeline inaugurated in northern Iran
National Iranian Gas Co. said a natural gas pipeline able to lower reliance on former supplier Turkmenistan has been inaugurated in northern Iran.
Oil Minister Bijan Namdar Zanganeh opened a 160-km, 42-in. pipeline that will carry gas from a connection at Damghan through Kiasar and Sari to Neka on the Caspian Sea. The gas will come from supergiant South Pars field in the Persian Gulf.
The pipeline's capacity, according to Iranian Gas Engineering & Development Co., is 10 million cu m/day.
The pipeline will deliver gas to the Iranian provinces of Golestan, Mazandaran, and Gilan, which suffered last winter when Turkmenistan halted deliveries.
The Turkmen foreign ministry said it suspended sales to force Iran to repay debt. NIGC called the move a violation of the countries' agreement and complained the supplier had hiked the price. Iran received as much as 10 billion cu m/year of gas from Turkmenistan after its imports from the country started in 1997. The Turkmen government has been hurt by declining gas prices and sales.
Gazprom stopped buying Turkmen gas early in 2016 because of a price dispute. And Chinese purchases of Turkmen gas via three pipelines transiting Kazakhstan and Uzbekistan have fallen below the government's expectations.
Plans for a fourth line between Turkmenistan and China, transiting Uzbekistan and Kyrgyzstan, were suspended.
TransCanada to expand Canadian Mainline capacity
TransCanada Corp. will apply to Canada's National Energy Board (NEB) to expand the capacity of its 14,114-km Canadian Mainline System through its Maple Compressor Station near Vaughan, Ont. The $160-million project is underpinned by 15-year contracts and will increase capacity to southern Ontario plus delivery to Atlantic Canada via the Trans Quebec & Maritimes Pipeline and Portland Natural Gas Transmission systems.
The proposed project will add incremental compression and associated facilities on the Canadian Mainline to move an additional 80 MMcfd of gas.
Once TransCanada has completed its tariff process for capacity additions, an application to approve the associated facilities is expected to be filed with the NEB in early 2018, to meet a Nov. 1, 2019, in-service date. The investment is part of a $500-million program to support additional transportation of Canadian and US gas along the Canadian mainline system.
