GENERAL INTEREST Quick Takes
India extends fifth oil, gas bid round
India’s Directorate General of Hydrocarbons has moved the bid closing date for Round V of its open acreage licensing policy (OALP-V) to Apr. 16 from Mar. 18. Round V features 11 blocks: eight onshore, two shallow-water, and one ultradeepwater. OALP-V opened Jan. 14 and includes a total of 19,800 sq km.
OALP I-IV have awarded 94 blocks in 16 sedimentary basins covering 136,800 sq km over the past 2.5 years. Cumulative exploratory work commitment after four rounds of OALP comprise 29,270 line-km of 2D seismic survey; 43,272 sq km of 3D seismic survey; 369 exploratory wells, and 290 core analyses to establish shale resources.
Shell-ExxonMobil JV takes step toward exploration and development offshore Somalia
A joint venture of Shell and ExxonMobil has reached an agreement with the Ministry of Petroleum and Mineral Resources of the Federal Republic of Somalia on an initial roadmap for exploration and development of certain hydrocarbon blocks offshore Somalia.
The roadmap enables the conversion of prior agreed concessions into production sharing agreements under the provisions of the petroleum law, building on an agreement signed in June 2019 after which the Shell-ExxonMobil JV paid $1.7 million for surface rentals and other incurred obligations on offshore blocks, the ministry said. In adherence to the Revenue Sharing Agreement, this payment was re-distributed among Somalia’s Member States for independent allocation.
The Ministry said it is “committed to creating an attractive fiscal and regulatory environment for Independent and International oil companies to enter offshore Somalia.”
Details on timing or next steps were not reported.
Lukoil, Turkmenistan talk of joint effort in Caspian Sea
Turkmenistan President Gurbanguly Berdimuhammedov and head of Russian oil and gas company Lukoil Vagit Alekperov discussed the possibility of implementing joint projects to develop hydrocarbon resources in Turkmenistan.
A government release Feb. 6 said the parties discussed key aspects of Turkmenistan’s energy strategy, such as diversification of energy supplies to world markets, capacity building in the mining and processing segment, development of the gas and petrochemical industry, and production of high-tech products.
At the meeting, held in Ashgabat, the parties also discussed possible joint activities in the Turkmen sector of the Caspian Sea. According to the release, Lukoil’s Alekperov noted the favorable investment climate and legal framework “make it possible to invest effectively in the development of oil and gas fields and the construction of infrastructure.” In turn, the President of Turkmenistan advised the parties could work out existing proposals together with the State concerns Türkmennebit and Türkmengaz and submit them for consideration.
Exploration & Development Quick Takes
Vintage books 2C contingent resources for Vali gas field
Vintage Energy Ltd. has made its first Cooper basin gas 2C contingent resource booking in the sparsely explored southern flank of the Nappamerri Trough in southwest Queensland.
The company said an independently certified figure of 37.7 bcf has been made by ERC Equipoise Pte Ltd. for Vali field discovery in permit ATP 2021.
The Vali-1 STI well discovered 80 m of net gas pay in a well-defined four-way structural closure in the Patchawarra formation reservoir. Vintage plans to stimulate and flow test the reservoir before mid-year to gather more information on gas volume and flow rates.
The find is close to existing infrastructure, which increases its commercial standing. Vintage expects to fast-track toward production and first cash flow from the basin.
Vintage is operator and holds a 50% interest in a joint venture with Metgasco Ltd. (25%) and Bridgeport (Cooper Basin) Pty Ltd (25%). The company has brought the project from farm-in to discovery and resource assessment in 9 months.
Wintershall reduces Balderbra resource estimates following appraisal
Wintershall Dea Norge AS, operator of production license 894, has reduced resource estimates of the Balderbra gas discovery in the northern Norwegian Sea and will plug well 6604/5-2 S after the appraisal well was determined to be dry. New resource estimates for the discovery are 3-8 billion standard cu m (scm) of recoverable gas and 0.2-1 million scm of recoverable condensate. Prior to drilling the appraisal well, the operator estimated resources of 7-19 billion scm of recoverable gas and 1-3 million scm of recoverable condensate.
The licensees will assess the discovery together with other discoveries in the area for further follow-up.
The appraisal well was drilled about 113 km southwest of Aasta Hansteen field by Saipem’s Scarabeo 8 semisubmersible drilling rig to a vertical depth of 3,816 m and a measured depth of 4,121 m subsea in water depth of 1,207 m. It was terminated in the Springar formation in the Upper Cretaceous.
The 6604/5-1 gas discovery was proven in Upper Cretaceous reservoir rocks (the Springar formation) in 2018.
The well encountered the Springar formation in three intervals totaling 210 m, with a total of about 140 m of sandstone with poor reservoir quality. Only traces of gas were encountered, and pressure communication with the discovery well has not been confirmed.
Extensive volumes of data have been collected and samples have been taken.
The exploration well is the third in the license. Wintershall is operator with 40% interest. Partners are Equinor Energy AS, 40%; and Petoro AS, 20%.
Scarbeo 8 will now drill wildcat well 6406/3-10 in production license 836 S in the Norwegian Sea, where Wintershall is operator.
Saudi Aramco to develop Jafurah field
Saudi Aramco approved development of Jafurah unconventional gas field in the Eastern Province. With a length of 170 km and a width of 100 km, it is the largest unconventional non-associated gas field in the Kingdom. Resource estimate is 200 tcf.
Production is expected to begin in 2024 and reach 2.2 billion scfd of sales gas and 425 MMscfd of ethane by 2036, representing 40% of current production. The field also is expected to produce about 550,000 b/d of gas liquids and condensates.
Saudi Arabia plans to invest 412 billion riyals ($110 billion) to develop the field.
Chevron awards contract for Anchor development
Chevron has awarded engineering design services to Wood for the Anchor deepwater development in the Gulf of Mexico—the industry’s first deepwater high-pressure development to achieve a final investment decision (OGJ Online, Dec. 19, 2019).
The scope of the project included the preliminary, front end engineering and design (pre-FEED), FEED, and now entails detailed design of Anchor, a wet tree development that will employ a semi-submersible floating production unit (semi-FPU).
The project will be led by Wood’s engineering teams in Houston, Tex., with the contract awarded under an existing 10-year master services agreement (MSA) with Chevron.
Under the scope of work, Wood is delivering a unique, fully integrated design for the topsides and subsea system, incorporating risers, production flowlines, export pipelines, and flow assurance analysis.
The Anchor discovery lies in Block 807 of the Green Canyon area about 225 km off the coast of Louisiana in more than 1,500 m of water. With an operating pressure of 20,000 psi, it’s one of the first ultrahigh-pressure projects in the world. The semi-FPU has a production capacity of 75,000 b/d of oil and 28 MMcf/d of gas, with the potential for future expansion.
Drilling & Production Quick Takes
Eni drills Agogo-3 appraisal, raises estimated oil in place
Eni SPA has increased the estimated oil in place of Agogo field by about 40% to 1 billion bbl with further upside to be tested in the northern sector of the field after drilling Agogo-3, the second appraisal well of the discovery in Block 15/06, offshore Angola (OGJ Online, July 26, 2019).
Data from the well, drilled 1.5 km northwest of the Agogo-2 (appraisal) and 4.5 km northwest of Agogo-1 (discovery) wells, confirmed communication with Agogo-2 reservoirs and further extension of the Agogo discovery to the north. The well’s estimated production capacity is in excess of 15,000 b/d. The field lies about 180 km from the coast in water depth of 1,700 m.
Agogo-3 was drilled by the Libongos drillship as a highly deviated well to 4,321 m total measured depth to reach sequences below the thick blanket of salt, leveraging Eni’s seismic imaging technologies and confirming an oil-charged and connected reservoir in the subsalt sector of the Agogo megastructure. It encountered up to 120 m of net pay of light oil (31°API) in sandstones of Miocene and Oligocene age with excellent petrophysical properties.
Production from Block 15/06 is tied back to the N’Goma floating production, storage, and offloading vessel about 15 km from the field (OGJ Online, Jan 17, 2020). Eni and partners are contemplating a third production hub and targeting a final investment decision in 2021.
Eni Angola operates the block with a 36.8421% interest. Sonangol has 36.8421% and SSI Fifteen Ltd. has 26.3158%.
In addition to Block 15/06, Eni currently operates Block Cabinda Norte, onshore Angola, and will increase its operated areas adding Blocks 1/14 (offshore Lower Congo Basin), Cabinda Centro (onshore) and Block 28 in the offshore Namibe Basin. Eni currently accounts for about 140,000 boe/d equity production in Angola.
Vaalco increases production, reserves offshore Gabon
Vaalco Energy Inc., Houston, has increased production in the Etame Marin permit area offshore Gabon with the recently drilled Etame 9H and Etame 11H development wells and two wells brought back online following a subsea repair on Etame 4H appraisal well and a workover on Etame 10H (OGJ Online, Oct. 21, 2019).
The South East Etame 4P appraisal well was drilled to a total depth of 6,311 ft from the Vaalco-operated South East Etame North Tchibala (SEENT) platform and encountered 20 ft of good-quality Gamba formation oil sands with similar reservoir quality found in South East Etame 2H.
Vaalco plans to drill South East Etame 4H, a third development well, which will target 1-2 million bbl of gross prospective resources, down from the initial predrill estimate of 4.2 million bbl which was based on an anticipated thicker oil column than was encountered. Initial gross expected production rates are 1,200-2,500 b/d. Following completion of the well, the drilling rig will perform additional workovers to preemptively replace electrical submersible pumps (ESPs) that are operating near the end of their design life.
Vaalco is operator of Etame with 33.6% interest (31.1% working interest). Addax (Sinopec) has 33.9%, Sasol has 30%, and PetroEnergy has 2.5%. Tullow is a 7.7% working interest owner but not a joint interest owner.
Skogul startup gets green light
The start-up of Skogul field in Block 25/1 in the central part of the North Sea has been approved by the Norwegian Petroleum Directorate.
Aker BP ASA plans start up in March, in line with the plan for development and operation, which was approved in early 2018. The field is developed with a seabed template tied in to the Alvheim FPSO via Vilje field.
Proven in 2010 through well 25/1-11 R, recoverable resources, as noted in the PDO, are estimated at 1.5 million standard cu m of oil (9.4 million bbl), making Slogul one of the smallest fields on the Norwegian shelf. The reservoir contains oil with a minor gas cap in sandstone of Eocene age and has excellent properties. It lies at a depth of 2,100 m.
At the time the PDO was submitted, development costs were estimated at 1.5 billion kroner.
Aker BP is operator of license 460 with 65%. PGNiG Upstream Norway AS holds the remainder.
88 Energy spuds Charlie-1 appraisal in Alaska
Perth-based 88 Energy Ltd. has spudded the Charlie-1 appraisal in Project Icewine acreage on the North Slope of Alaska.
The well is a step-out from a previous discovery, Malguk-1, drilled in 1991 by BP. Mulguk encountered oil shows with elevated resistivity and mud gas readings over multiple horizons during drilling. The well was not tested because of downhole drilling complications resulting in a lack of time before the close of the winter drilling season.
88 Energy moved into the area in 2016, first acquiring 2D seismic and then reprocessing legacy 2D seismic in 2017. A modern 3D seismic program was run in 2018 to determine the extent of BP’s discovery.
The company said that Charlie-1 will intersect seven stacked prospects, four of which are interpreted as oil-bearing in Mulguk-1. The seven stacked reservoirs have a potential to hold 1.6 billion bbl of oil on a gross mean prospective resource basis.
Charlie-1 will be funded up to $23 million by 60% farminee Premier Oil Plc and testing is anticipated to be concluded in April. 88 Energy retains 20% interest, while Burgundy Xploration Plc has the remaining 10%.
PROCESSING Quick Takes
Waltersmith nears startup of Nigerian modular refinery
Waltersmith Petroman Oil Ltd. subsidiary Waltersmith Refining & Petrochemical Ltd. has started precommissioning activities for the first 5,000-b/d phase of its previously announced 30,000-b/d modular refinery at Ibigwe oil field, in the Ohaji Egbema Local Government Area, Imo state, Nigeria (OGJ Online, June 19, 2018).
With precommissioning at the site now under way, Waltersmith is on track to deliver the project ahead of its initially planned 18-month construction schedule, said Chikezie Nwosu, Waltersmith’s chief executive officer, in a series of recent posts to his official LinkedIn account.
Initially scheduled for commissioning during second-half 2020, the refinery’s first phase—which will produce about 271 million l./year of refined products, including diesel, naphtha, high-pour fuel oil, and kerosine—is scheduled to start up in May, according to a separate release from the Nigerian Content Development & Monitoring Board (NCDMB), which holds a 30% interest in the project (OGJ Online, July 9, 2018).
A groundbreaking ceremony for the project’s second phase—which will include a 25,000-b/d crude and condensate refinery designed to produce gasoline, diesel, LPG, kerosine, and aviation fuel—also is planned in May, according to a Dec. 23, 2019, release from the African Energy Chamber.
The proposed project comes as one of many in the wake of the Nigerian Department of Petroleum Resources’ previous licensing awards to private investors to establish refineries in Nigeria as part of the federal government’s strategy to expand the country’s existing refining capacity through use of modularly constructed refineries (OGJ Online, Jan. 11, 2018).
The new refinery initially will process Nigerian crude from 7,000-b/d Ibigwe onshore field in eastern Niger Delta—also operated by Waltersmith—into marketable fuel products for the domestic market.
PKN Orlen approves new unit for Plock refining complex
Polski Koncern Naftowy SA (PKN Orlen) has approved a previously proposed project to add a new visbreaking unit at its 327,300-b/d integrated refining and petrochemical complex in Plock, Poland (OGJ Online, Dec. 2, 2019).
Designed to increase the yield of light products such as gasoline and diesel oil, the new visbreaking unit will be equipped with an unidentified visbreaking technology jointly licensed by Royal Dutch Shell PLC and McDermott International Inc., PKN Orlen said in a release.
The operator additionally confirmed that it has awarded a 750 million-zloty contract for design, procurement, construction, installation, commissioning, and start-up services for the new unit to a consortium of KTI Poland SA and IDS-BUD SA.
PKN Orlen also said it has awarded additional contracts in the amount of about 200 million zloty for works related to supporting infrastructure for the project. Details of these associated contracts were not disclosed.
The new visbbreaking unit comes as part of the operator’s plan to improve crude feedstock flexibility and efficiency by increasing the yield of high-margin products via in-depth conversion of vacuum residue from the refinery’s crude distillation unit.
PKN Orlen said it expects the 1 billion-zloty visbreaking project—scheduled to enter commercial operation by yearend 2022—will add up to 415 million zloty to the company’s annual EBITDA.
While PKN Orlen did not reveal the specific Shell-McDermott technology to be implemented at the new unit, OGJ research based on information available from both Shell and McDermott’s websites indicates the only historical, jointly licensed visbreaking technology offered by the companies was the Shell Soaker Visbreaking technology (OGJ Online, July 1, 2014).
McDermott, however, confirmed to OGJ on Feb. 26 that the visbreaking technology licensing partnership with Shell was terminated in March 2019.
Another project under way at Płock is an upgrade of the refinery’s hydrocracking unit that, once completed, will increase diesel oil production by 100,000 tpy, PKN Orlen said.
The operator said it is also executing a separate project to modernize a diesel hydrotreater at the refinery as part of a plan to boost diesel oil production by 150,000 tpy.
Scheduled to be completed in late 2020, the hydrocracking and hydrotreating projects are anticipated to add 200 million zloty to total annual EBITDA, the company said.
Dominican Republic refinery exports first IMO 2020-compliant fuel
Refinería Dominicana de Petróleo PDV SA (Refidomsa) has exported its first shipment of low-sulfur fuel oil that complies with the International Marine Organization’s (IMO) new regulations requiring ships to use marine fuels with a sulfur content below 0.5% from its 34,000-b/d refinery at Haina, in San Cristóbal, Dominican Republic.
Refidomsa exported two 50,000-b/d vessels of low-sulfur fuel oil bound for North America in late February to buyer Vitol Group, the operator said in a release.
With the first shipment now dispatched, the Dominican refinery anticipates exporting more than 100,000 bbl of the IMO 2020-compliant fuel oil monthly, said Félix Jiménez, president of Refidomsa’s board of directors.
Jiménez said the refinery’s production of the IMO 2020-compliant fuel oil results from a new crude oil research process developed by Refidomsa intended to raise product quality in conformance with international environmental protection standards.
The operator, however, did not reveal further details of the new process technology implemented at the refinery.
In a deal to pay off its oil debts to Venezuela, the Dominican Republic transferred 49% ownership interest in Refidomsa to state-owned Petróleos de Venezuela SA in late 2009 (OGJ Online, Nov. 3, 2009).
TRANSPORTATION Quick Takes
ArcLight, Rattler form Midland basin joint venture
Amarillo Midstream, an ArcLight Capital Partners portfolio company, and an affiliate of Rattler Midstream, a subsidiary of Diamondback Energy, have entered into a 50/50 joint venture to own, operate and expand a natural gas gathering and processing system in the Midland basin.
Amarillo Rattler, owned 50% by Amarillo Midstream and 50% by an affiliate of Rattler, currently owns and operates the 40-MMcfd Yellow Rose gas gathering and cryogenic processing system including over 84 miles of gathering and regional transportation pipelines in Dawson, Martin, and Andrews Counties, Tex.
The JV intends to construct and operate a new 60-MMcfd natural gas cryogenic processing plant in Martin County, Tex., as well as incremental gas gathering and regional transportation pipelines. Full commercial operations are expected in mid-2021. Diamondback has contracted for a portion of the new processing plant’s capacity.
Phillips 66 Partners acquires interest in Liberty Pipeline
Phillips 66 Partners LP agreed to acquire from Phillips 66 its 50% interest in the Liberty Pipeline project for $75 million.
In June 2019, Phillips 66 formed Liberty Pipeline LLC, a 50-50 joint venture with Bridger Pipeline LLC, to construct the 24-in. Liberty Pipeline to transport crude oil from the Rockies and Bakken production areas to Cushing (OGJ Online, June 10, 2019). From Cushing, shippers can access multiple Gulf Coast destinations, including Corpus Christi, Ingleside, and Houston, Tex.
The project is expected to cost $1.6 billion, or $800 million net to the partnership. Service on the pipeline, which is underpinned with long-term volume commitments, is targeted to begin in the first half of 2021.
Centrica cargo commissions first private LNG terminal in Brazil
Centrica plc and Centrais Elétricas de Sergipe SA (CELSE) together commissioned the first private LNG import terminal in Brazil.
On Feb. 4, the Centrica-chartered Singapore Energy delivered 95,000 cu m of LNG by a ship-to-ship operation to the Golar Nanook Floating Storage and Regasification Unit (FSRU) 8.5 km off the coast.
The FRSU is connected by pipeline to CELSE’s Usina Termoelétrica (UTE) Porto de Sergipe I combined-cycle gas-fired power plant, the largest in Latin America.
