GENERAL INTERESTQuick Takes
Moody’s: Permian line constraints to limit production
A lack of pipelines to carry oil and natural gas out of the Permian basin in West Texas and southeastern New Mexico will limit exploration and production and weaken realized prices until late 2019, when new pipeline capacity comes online, Moody’s Investors Service said in a recent report. The surge in Permian development over the past 2 years has constrained labor resources, proppant supplies, infrastructure, and pipeline takeaway capacity for oil, natural gas liquids, and gas.
Pipeline takeaway capacity for oil and gas to outside the Permian is likely to be insufficient for the region’s oil and gas production growth for much of 2019, the report said. New pipelines will likely go into service at various times in second-half 2019, alleviating the bottleneck, but until then capacity constraints will limit producers’ activities.
Some E&P companies in the Permian lack firm direct transportation contracts with pipelines, raising their risk of capacity shortfalls, and leaving them vulnerable to any price drop, the report says. Pioneer Natural Resources Co., Concho Resources Inc., and Diamondback Energy Inc. all hold contracts that cover all or most of their anticipated production for 2019, but smaller Permian-focused producers Laredo Petroleum Inc., Jagged Peak Energy LLC, and Endeavor Energy Resources LP have only limited transportation contracts in hand for 2019.
Though they can still sell their products through other means and hedge the basis differentials, a lack of contracted capacity can leave producers vulnerable to capacity shortfalls, as anticipated in 2019, or any stress on realized prices. The potential shortfall in takeaway capacity from the Permian, however, will not have significant negative credit implications for most of the rated E&P companies operating there, said Moody’s.
Murphy Oil, Petrobras form deepwater gulf combine
Murphy Exploration & Production Co.-USA and Petrobras America Inc. (PAI) have formed a joint venture comprised of all the current producing Gulf of Mexico assets from Murphy and PAI. Murphy, which will oversee operations, will own 80% of the combine and PAI will own 20%.
The deal adds 41,000 net boe/d to Murphy’s gulf production, 97% of which is oil. Post-closing, total Murphy gulf production is expected to be 60,000 net boe/d. The company’s corporate oil-weighted production is expected to increase to 61%.
The combine excludes exploration blocks from both companies, except for PAI’s blocks that hold deep exploration rights.
Murphy will pay $900 million to PAI, and PAI will earn an additional consideration up to $150 million if certain price and production thresholds are exceeded beginning in 2019 through 2025. Murphy also will carry $50 million of PAI costs in St. Malo field if certain enhanced oil recovery projects are undertaken.
DOE’s FEO intends to fund EOR research
The US Department of Energy’s Fossil Energy Office reported on Oct. 10 that it intends to fund cost-shared research and development projects that reduce risks associated with enhanced oil recovery and expand the application of EOR methods. The solicitation closes on Jan. 31, 2019.
The objective is to competitively solicit and award R&D projects that focus mainly on developing enhanced recovery technologies in conventional and unconventional reservoirs, FEO said in its Notice of Intent. Projects also should aid in the development of unconventional fossil energy resources as well as improve the understanding of reservoirs and low-recovery factors from unconventional oil wells, FEO said.
FEO said in its funding opportunity announcement that its National Energy Technology Laboratory will manage the selected projects, which will focus on two interest areas: EOR technologies for onshore conventional oil reservoirs and EOR technologies for unconventional reservoirs.
Exploration & DevelopmentQuick Takes
Shell, partners to invest in Arran field
Shell UK Ltd., with partners Rockrose Energy and Dyas UK Ltd., reported reaching a final investment decision to develop Arran gas and condensate field in the UK North Sea. Shell has become the operator of the Arran project.
The FID remains subject to approval of the field development plan by the Oil & Gas Authority. Arran field lies 240 km east of Aberdeen on Blocks P359a/b, P1051, and P1720. The field was discovered in 1985. At peak, Arran is expected to produce 100 MMscfd of gas and 4,000 b/d of condensate, which combined to 21,000 boe/d. Four development wells will be drilled. The natural gas and liquids will be transported via a newly installed subsea pipeline to the Shearwater platform.
This is Shell’s fourth FID announcement in the UK North Sea this year, following the decision to redevelop Penguins field in the northern North Sea, Alligin field West of Shetland, and Fram field in the central North Sea.
Steve Phimister, Shell vice-president for upstream in the UK and Ireland, called Arran “an important addition to Shell’s portfolio as we seek to strategically grow our central North Sea production around the Shearwater hub.”
Shell has 44.57% interest in Arran while Rockrose has 30.43% and Dyas has 25%.
Andy Samuel, OGA chief executive, said Arran field’s development called for “real adaptability and tenacity.” He said Arran field “has been on our radar for quite some time as a key component of our Central Graben Area Plan.”
Previously, Arran was operated by Dana Petroleum, which sold its interest to Rockrose. In July, Serica Energy PLC, London, said it expects gross production of as much as 40 MMcfd of gas and 1,150 b/d of condensate from Columbus field in the central UK North Sea, development of which is contingent on development of larger Arran gas-condensate field.
Aker BP plans King Lear satellite development
Aker BP has agreed to acquire Equinor Energy’s 77.8% interest in the King Lear gas-condensate discovery in the Norwegian North Sea for $250 million with plans to develop it as a satellite to Ula field. Net recoverable resources in the King Lear discovery, 50 km south of Ula field on Blocks PL146 and PL333, are estimated at 77 million boe, according to data from the Norwegian Petroleum Directorate. The King Lear discovery was made in 1989 in the Ekofisk area of the Norwegian Continental Shelf.
Including the increased oil recovery potential from Ula, Aker BP estimates a total resource addition of more than 100 million boe net to the company. Total E&P Norge holds the remaining 22.2% interest.
Cost-cutting trims Equinor outlay off Norway
Drilling-efficiency improvement and other cost-cutting measures have trimmed investment need for oil and gas fields Equinor is developing on the Norwegian continental shelf by 30 billion kroner ($4 billion) from original estimates.
The reduction is part of the government’s national budget proposal for 2019. It’s based on investments projected in development plans submitted to authorities for fields Equinor operates.
“The improvements have been achieved in close collaboration with our partners and suppliers and are mainly a result of increased drilling efficiency, simplification, and high-quality project implementation,” said Margareth Ovrum, executive vice-president for technology, projects, and drilling.
“These figures also include the market effect we have achieved by countercyclical investments.”
Chances rise for Goddard gas development
Chances for development of the Goddard natural gas discovery in the UK North Sea have risen to 75% after third-party confirmation of the resource estimate, reports Independent Oil & Gas PLC (IOG), London.
ERC Equipoise Ltd. estimated gross midpoint contingent resources at 108 bcf for the main Goddard structure and at 73 bcf for two adjacent structures directly east of the discovery, in line with IOG estimates.
Goddard, previously known as Glein, is a 1994 ARCO discovery on Blocks 48/11c and 48/12b of the PL2438 license, in which IOG acquired 100% interest in a round last May.
Discovery well 48/11a-12 encountered 478 ft of gas pay in Permian Leman sandstone with gas down to 10,081 ft TVD subsea. One of the adjoining fault blocks has been penetrated by a well that was not tested.
The license commits IOG to drill an appraisal well and reprocess 175 sq km of 3D seismic data with prestack depth migration within 3 years.
CEO Andrew Hockey said the appraisal well will test the southeastern extent of the Goddard discovery and the adjoining structures. He said the newly confirmed midpoint continent-resource estimate would make the discovery economic to develop but added, “It is important to delineate the full size of this discovery with the appraisal well so that the development plan can be optimized.”
IOG’s current development plan is for three hydraulically stimulated horizontal wells in 82 ft of water, completed subsea or from an unstaffed platform with production delivered through a 28-mile line to IOG’s Blythe hub under development to the south. The Blythe hub is to be linked with a recommissioned Thames line to deliver gas to the Bacton Terminal.
Drilling & ProductionQuick Takes
QP to operate Idd El-Shargi North Dome field
Qatar Petroleum will become operator of offshore Idd El-Shargi North Dome oil field when its development and production sharing agreement with Occidental Petroleum of Qatar Ltd. expires in October 2019. Discovered in 1960, the field is 85 km off Doha (OGJ Online, July 16, 2013).
Oxy reported net production from Idd El-Shargi North Dome field, in which it has a 100% working interest, at 53,000 boe/d in 2017. Oxy also has a 100% working interest in Idd El-Shargi South Dome field, where net production in 2017 was 4,000 boe/d. The company said gross combined production from the Idd El-Shargi fields last year was about 91,000 boe/d.
The development and production sharing agreement for the southern field expires in December 2022.
Shell, QGC to drill 250 gas wells in Queensland
A group led by Royal Dutch Shell PLC that includes Queensland Gas Co. (QGC) plans to drill 250 coal seam gas wells during 2019-20 as part of its program in the Western Downs region of Queensland. The wells will be connected to the existing QGC gas processing plants and produce about 930 petajoules of gas over the next 30 years.
The program has been called Project Goog-a-binge, a name gifted by the Iman traditional owners of the region. Goog-a-binge is the Iman word for scrub turkey, which is an important totem for this Aboriginal group.
Shell Australia Chairman Zoe Yujnovich said the project, which is subject to satisfying federal and state government regulatory approvals, will provide a boost to Queensland’s regional economy through the creation of as many as 350 jobs and the generation of business opportunities for local suppliers. It also will deliver more gas to the Australian East Coast market as well as export LNG customers via the Gladstone CSG-LNG facilities on Curtis Island.
Shell currently supplies about 60% of Queensland’s domestic gas demand through its Arrow Energy and QGC units.
Test lifts hope for southern England field
Angus Energy PLC said a 7-day flow test of its Balcombe-2z horizontal well indicates commercial production is possible from Balcombe oil field on PEDL 244 in southern England.
After cleaning and priming with coiled tubing and nitrogen, the well flowed naturally at 853 b/d of oil, not including 22.5% water. During a second flow period, the well flowed naturally at 1,587 b/d of oil, not including 6.6% water.
Production was from a single micrite layer in the Jurassic Kimmeridge formation of the Weald basin well, which was drilled to a vertical depth of 2,200 ft with a horizontal section of 1,714 ft. During the initial flow period, the well slugged at up to 3,000 b/d, which exceeded separator capacity.
The produced water was unexpected. Angus believes the horizontal section cut a high-pressure water zone that can be isolated. A production logging string was run to identify the water zone, but the coiled tubing equipment on which it was run failed. Oil produced during the test was about 34° gravity, although light hydrocarbons might have been removed by the nitrogen used in the test.
Angus said it believes oil quality might be similar to that of oil produced from Kimmeridge at its Lidsey field on the edge of Weald basin, where the lowest quality crude is 38.5° gravity.
Angus operates the Balcombe license in partnership with Cuadrilla Balcombe Ltd. and Lucas Bolney Ltd.
Devon restores operations at Jackfish 1 complex
Devon Energy Corp., Oklahoma City, completed additional facilities work at its Jackfish 1 heavy oil project in the southern Athabasca oil sands region of Alberta, and full-scale operations have been restored. The work was related to minor facility repairs identified during turnaround startup activities.
Third-quarter net production in Canada is estimated to be 104,000 boe/d because of the maintenance at Jackfish 1. The temporary curtailment of Jackfish volumes represents less than 1% of total expected company-wide production for the year. Production at the Jackfish 2 and Jackfish 3 projects were at nameplate capacity for the entire third quarter.
Devon expects fourth-quarter net production in Canada, after the impact of higher sliding-scale royalties, to increase to an average of 115,000-120,000 boe/d.
The company estimates third-quarter net production in the US will be 418,000 boe/d. During the quarter, the company sold minor, noncore assets with an associated production impact of 2,000 boe/d. In the quarter, the company’s upstream capital spending was $523 million, 9% below the company’s midpoint guidance.
Lukoil advances V. Filanovsky development
Lukoil soon will start drilling the sixth production well in second-phase development of Vladimir Filanovsky oil field in the Caspian Sea as a recently completed fifth well holds total production at 6 million tonnes/year.
The fifth well, with a main wellbore of 2,956 m and a lateral of 1,735 m, produced at an initial rate exceeding 3,300 tonnes/day of oil, Lukoil said.
The field, in 7-11 m of water, has produced more than 10 million tonnes of oil since coming on stream in 2016.
The second development stage involves drilling of six production wells and two injection wells (OGJ Online, June 18, 2018).
Lukoil in August installed the substructure of a wellhead platform that will be part of the third development stage. Topsides assembly is 70% complete. The platform is to be commissioned next year.
PROCESSINGQuick Takes
Shell Nederland starts up unit at Pernis refinery
Shell Nederland Raffinaderij BV has commissioned a solvent deasphalter (SDA) unit at its 404,000-b/d Pernis refinery and integrated petrochemical production site in Rotterdam.
Designed to further enhance performance and competitiveness of the Pernis refinery, as well as reduce environmental impact of its product portfolio, the new unit enables the manufacturing site to process a larger proportion of its oil intake into cleaner transportation fuels.
The unit enables Pernis to process a larger proportion of its oil intake into cleaner transport fuels, including marine gas oil compliant with the International Maritime Organization’s confirmed reduction in sulfur content for marine bunker fuel to 0.5 wt % from a current 3.5 wt % by Jan. 1, 2020, Shell said.
The new, modularly constructed 10-story SDA unit processes heavy fuels to clean middle distillates and provides increased crude flexibility, allowing Pernis to adjust operations to meet market demands and capture higher margins, the operator said.
Egyptian refiner lets contract for hydrocracking complex
Assiut Oil Refining Co. (ASORC), a unit of Egyptian General Petroleum Corp., through a contractor, has let a 4-year contract to WorleyParsons to provide project management consultancy for the Assiut hydrocracking complex (AHC) in Upper Egypt.
As part of the contract—awarded by ASORC subsidiary Assiut National Oil Processing Co. (ANOPC)—WorleyParsons will oversee the basic engineering phase, open-book estimate, detailed design, procurement, construction, and commissioning of the AHC project, WorleyParsons said.
The complex will convert 2.5 million tonnes/year of heavy fuel oil into high-quality petroleum products such as diesel, LPG, naphtha, kerosine, and gasoline.
Announced by Egypt’s Ministry of Petroleum (MOP) in July, the £33-million AHC will thermally crack heavy oils (mazut) to produce 1.6 million tpy of low-sulfur, Euro 5-quality fuels, as well as 402,000 tpy of naphtha and 101,000 tpy of LPG.
ASORC, which operates the 4.5 million-tpy Assiut refinery in Asyut, awarded ANOPC a contract for construction of the complex in July, according to MOP and local media reports.
Petroecuador starts maintenance at Shushufindi refinery
Ecuador’s Petroecuador has initiated the scheduled shutdown of a crude unit for routine maintenance at its 20,000-b/d Shushufindi refinery in northeastern Ecuador.
An 18-day closure of the 10,000-b/d Crude Unit 1 (R1) began on Oct. 5 for planned maintenance of process equipment in the unit’s atmospheric distillation area, Petroecuador said.
Maintenance works to be carried out during the planned shutdown include calibration of measuring instruments; steam-leak corrections; maintenance of the aerocooler oven, heat exchangers, and distillation tower vessels; changeout of duct gases from the fractionation tower; and cleaning of equipment and containers.
One of the refinery’s two crude processing units, R1 produces base gasoline, Diesel 1 and 2, jet fuel, and reduced crude oil.
R1’s planned shutdown, which occurs every 2 years, comes as part of Petroecuador’s general maintenance program to ensure equipment and instruments that could become worn out during the unit’s scheduled run remain in working order.
TRANSPORTATIONQuick Takes
ADNOC to build sulfur line, expand Shah processing
Abu Dhabi National Oil Co. (ADNOC) Sour Gas, a subsidiary joint venture of ADNOC and Occidental Petroleum Corp., is set to build a pipeline to carry molten sulfur produced by its Shah field sour gas operations. The pipeline will carry the sulfur from ADNOC’s main processing plant to its granulation sulfur plant 11 km away, where it is granulated, stockpiled, and ultimately transported, via rail, to a sulfur-handling terminal at ADNOC’s Ruwais downstream hub.
Pipeline capacity will be expandable to allow for increased sulfur production. ADNOC says the pipeline, scheduled for commissioning in 2019, will create greater value from a main commodity of sour gas processing and increase flexibility around existing operations.
MMEC Mannesmann GMBH is conducting engineering, procurement, construction, and commissioning of the pipeline. Nearly 60% of the value of the EPC contract will flow back into the UAE economy as part of ADNOC’s in-country value program. ADNOC exports granulated sulfur to fertilizer manufacturers worldwide.
As part of its Oxy JV, ADNOC is advancing plans to increase sour gas processing by 50% of existing capacity. The expansion of Shah processing would make ADNOC one of the world’s largest producers of sulfur, the company says.
From the 1 bcfd of sour gas ADNOC currently processes, the Shah plant produces 500 MMcfd network gas, 4,400 tons/day of NGL, 33,000 b/d of petroleum condensates, and 10,000 tons/day of pure granulated sulfur.
TransCanada starts first WB Xpress phase
TransCanada Corp. has started service on the Western Build of its WB Xpress project to increase movement of Appalachian basin natural gas to the US Gulf Coast.
It plans to put the Eastern Build on stream later this year.
The Western Build can move 760 MMcfd of gas to a delivery point on the Tennessee Gas Pipeline Broad Run System. Construction included the Elk River Compressor Station at Clendinin, W.Va., and associated pipelines.
The $900-million WBX project upgrades TransCanada’s existing system with two new compressor stations, 30 miles of new pipeline, and modifications of seven existing pipelines, adding a total of 1.3 bcfd of capacity.
Aspen Midstream to build Austin Chalk line
Aspen Midstream LLC is building a large-diameter residue gas pipeline and both a lean and rich gas gathering system in the Austin Chalk play in Texas. Aspen’s Austin Chalk System is in Giddings field. The system is supported by a combined total of about 150,000 acres of long-term dedications from multiple producers. Aspen is engaged in discussions with other producers about additional dedications. The system is expected to be in service third-quarter 2019.
The initial system will consist of more than 90 miles of 10-in. to 20-in. gas gathering mainlines, treatment plants, a 200-MMcfd cryogenic processing plant, and a residue gas pipeline to the market hub at Katy, Tex.
Aspen Midstream expects to expand its Austin Chalk System by adding gathering, cryogenic processing and treatment infrastructure as necessary and is engaged in discussions with the area’s producers to determine future needs.
Producers drilling the Giddings field are developing multiple stacked pay zones, including the Austin Chalk and Eagle Ford shale formations. The Aspen Austin Chalk System spans the Giddings field, including Washington, Fayette and Burleson counties, along with portions of Austin, Brazos, Colorado and Waller counties, all in Texas.
EnerVest and TPG Pace Energy Holdings earlier in 2018 created a new company, Magnolia Oil & Gas Corp., with 345,000 net acres in Giddings field (OGJ Online, Mar. 20, 2018).