GENERAL INTERESTQuick Takes
Rystad: US shale producers cut budgets, boost output
US shale companies expect to deliver an average of 15% growth in oil production in 2019 vs. 2018. At the same time, operators say they will cut capital spending by 5% this year.
Rystad Energy has analyzed the recently released earnings reports for the fourth quarter of 2018 from 45 US operators, which also included their guidance for production and capital expenditure in the year ahead.
“Earnings and guidance confirm that most US shale operators aim to moderate drilling and completion activity this year, prioritizing cost discipline over aggressive growth,” said Artem Abramov, Rystad Energy partner.
The numbers look different if planned 2019 oil production is compared to the reported oil rate in fourth-quarter 2018. On average, yearend 2018 production rates for US onshore-focused firms was markedly higher than average for the whole year.
“On average only 5% growth in oil volumes is expected throughout 2019, as just a handful of shale operators anticipate double-digit oil production additions vs. the last quarter of 2018. In fact, a number of shale players estimate a decrease in oil output versus the fourth quarter of 2018,” Abramov said.
Still, 5% growth for full year 2019 vs. the fourth quarter of 2018 means 10% growth between the fourth quarter of 2018 and the fourth quarter of 2019.
“If this growth rate is representative for the entire 9.5 million b/d oil output currently achieved in the Lower 48 states excluding [the] Gulf of Mexico, we are then talking about nearly 1 million b/d of oil production growth from the US,” Abramov said.
BP’s full-year production highest since 2010
BP PLC reported profits for the fourth quarter and full year 2018 of $766 million and $9.38 million, respectively, compared with $27 million and $3.39 million for the same respective periods in 2017. Including amounts relating to the Gulf of Mexico oil spill, operating cash flow for the fourth quarter and full year was $6.8 billion and $22.9 billion, respectively, compared with $5.9 billion and $18.9 billion for the same periods in 2017.
For the full year, production—excluding Rosneft—was 2.54 million boe/d, 3% higher than 2017 and the highest since 2010. Upstream production for the fourth quarter was 2.63 million boe/d, 1.8% higher than a year earlier.
The Clair Ridge project, west of Shetland in the North Sea, was the company’s sixth major upstream project to come on stream in 2018, following earlier start-ups in Egypt, Russia, Azerbaijan, the Gulf of Mexico, and Australia.
API joins coalition to get Congress to approve USMCA
The American Petroleum Institute announced that it has joined the newly launched USMCA Coalition to get Congress to approve the US-Mexico-Canada Agreement, the nation’s largest oil and gas association said. The coalition is backed by more than 200 companies across a wide range of industries, it noted.
“This isn’t just about the potential impact to the US energy industry—but also to small businesses, manufacturers, and US jobs. We call on Congress to put working families first and pass the USMCA to ensure the free flow of goods and energy between US, Canada, and Mexico,” said Kyle Isakower, API’s vice-president of regulatory and economic policy.
“In terms of the unique impact to the US energy industry, North American energy markets are deeply integrated and interconnected, and the free flow of energy products across our borders is essential for continued American energy leadership and economic growth,” Isakower said.
California’s injection rules take effect Apr. 1
California’s new underground injection requirements will affect some 55,000 underground injection control (UIC) wells when they go into effect on Apr. 1, the state’s Department of Conservation (DOC) reported. It said the new rules affect wells that inject water or steam for enhanced oil recovery, along with wells that return produced water back to its source.
DOC said that key elements in the UIC regulations include:
• Stronger testing requirements to identify potential leaks.
• Increased data requirements to assure proposed projects are fully evaluated.
• Continuous well pressure monitoring.
• Requirements to automatically cease injection when there is a risk to safety or the environment.
• Monitoring for seismic activity.
• Requirements to disclose chemical additives.
A third category of UIC wells—those used for underground gas storage—is covered by separate regulations, DOC said.
Shareholders approve Encana, Newfield merger
Encana Corp. and Newfield Exploration Co. closed on a deal to combine on Feb. 13 following approval of necessary proposals at special shareholder meetings held Feb. 12 (OGJ Online, Nov. 1, 2018). Before the merger, Encana shareholders owned 63.5% of the combined company; Newfield stockholders owned 36.5%. The deal gave Newfield stockholders 2.6719 Encana common shares for each share of Newfield common stock.
US Senate confirms nomination of Wheeler to lead EPA
The US Senate confirmed President Donald Trump’s nomination of Andrew Wheeler as the US Environmental Protection Agency’s administrator by a 52-47 vote on Feb. 27. Trump nominated Wheeler earlier this year (OGJ Online, Jan. 9, 2019).
Wheeler has been EPA’s acting administrator since July 5, 2018, following E. Scott Pruitt’s resignation. The Senate confirmed him earlier in 2018 as the federal environmental regulatory agency’s acting administrator.
Exploration & DevelopmentQuick Takes
India opens third open-acreage bid round
India has launched the third bid round under its Open Acreage Licensing Policy, offering 23 onshore and offshore blocks covering more than 31,000 sq km for exploration. Dharmendra Pradhan, minister of petroleum and natural gas, announced OALP-3 at the Petrotech conference in Noida, outside Delhi.
The Ministry of Petroleum and Natural Gas opened OALP-2 on Jan. 7, offering 30,000 sq km (OGJ Online, Jan. 7, 2019).
The Directorate General of Hydrocarbons takes bids electronically but hasn’t published third-round details. Terms are revenue-sharing.
Bahrain discussing discovery with US firms
Bahrain is discussing development of an offshore oil and gas discovery it disclosed last year with US oil companies, Reuters reports. Oil Minister Mohammed bin Khalifa Al Khalifa told the news service, “Maybe towards the end of this year we might be in a position to have an interested company, we hope.”
The focus is on US companies because of their experience with shale and other low-permeability reservoirs, he said.
A Bahrain Petroleum Co. geologist last April said the discovery, in shallow water off western Bahrain, encountered “a layer with moderate conventional reservoir properties on top of an organic-rich source rock (OGJ Online, Apr. 4, 2018).”
Other than a median oil-in-place estimate of 80 billion bbl, little has been disclosed about the discovery.
Al Khalifa said drilling has begun of a test well.
Sarta development advances in Kurdistan
Sarta Phase 1A development in the Kurdistan region of Iraq will proceed, reports Genel Energy PLC, London, a new block partner.
Genel acquired a 30% interest in the Sarta production-sharing contract from operator Chevron Corp., which retains 50%. Genel also acquired a 40% interest from Chevron in the Qara Dagh block, which it will operate through a carry arrangement with Chevron retaining 40%. The Kurdistan Regional Government holds 20% interests in the blocks.
Genel acquired the Sarta stake by agreeing to pay 50% of field development costs until achievement of a production target plus a success fee based on a production milestone.
In Phase 1A, the final investment decision for which was made in February, the companies will recomplete the Sarta-2 well, place the Sarta-3 well on production, and build a central processing facility with capacity of 20,000 b/d of oil. Both wells flowed about 7,500 b/d of oil on test. The main reservoir is Lower Jurassic Mus-Adayah.
Drilling of a third well is expected to begin within 12 months of the start of production, expected in 2020. Production capacity can be increased.
Genel booked a net 10 million bbl of proved and probable reserves based on the preliminary Sarta development phase.
On the Qara Dagh block, siting is under study for the Qara Dagh-2 well to be drilled in 2020, Genel said. The Qara Dagh-1 well, completed in 2011, tested oil in two zones of the Upper Cretaceous Shiranish formation.
Drilling & ProductionQuick Takes
ADNOC lets Ghasha construction contract
Abu Dhabi National Oil Co. has let a construction contract that shows the extent of its offshore Ghasha sour gas development project (OGJ Online, Dec. 19, 2018).
Under the $1.36-billion contract, National Marine Dredging Co. of Abu Dhabi will build 10 artificial islands and two causeways and expand Al Ghaf island, ADNOC said.
The work, expected to take 38 months, follows what ADNOC called one of the largest marine environmental baseline surveys in United Arab Emirates history. It includes dredging, land reclamation, and marine construction and covers first-phase development of the Ghasha Concession, encompassing Hail, Ghasha, and Dalma sour gas fields.
The artificial islands will be named for pearl-diving sites in the area: Ghanem, Sawalem, Chananiz, Mudaifena, Reeah, Seebeh, Seemeh, Shalhah, Jzool, and Duroob.
ADNOC said drilling with land rigs on the islands will be cheaper than the alternative, jack ups in shallow water, and precludes the need to dredge more than 100 locations. It also provides greater flexibility for extended-reach drilling.
ADNOC’s partners in the project are Eni, 25%; Wintershall, 10%; and OMV, 5%.
DNO plans 20 Kurdistan wells, acquires Faroe
DNO ASA, Oslo, plans to drill as many as 20 exploration and production wells in the Kurdistan region of Iraq this year as it expands in Norway through acquisition.
Spending more than 40% above the 2018 level of $300 million, the company will drill 14 wells in Kurdistan’s Tawke field, 4 at Peshkabir, and 2 on the Baeshiqa license. The company also plans 5 wells in Norway.
Much of the 2018 spending, which was up from the prior year, was for Peshkabir development and Tawke drilling.
DNO planned to start production from the Peshkabir-9 and Tawke-52 wells last month. On the Baeshiqa license, testing of the first exploration well was delayed by rain but was expected to begin in February. Most of the company’s 128,000 b/d of operated oil production, 90,000 b/d net to its working interest, is in Kurdistan. The rest is in Oman.
DNO said it is completing its unsolicited takeover of Faroe Petroleum PLC, bringing its Norwegian holdings to 90 licenses, 22 operated. It said it has acquired 96% of Faroe shares and has begun compulsory acquisition of remaining shares.
Origin signs gas offtake deal for Golden Beach field
Origin Energy Ltd., Sydney, has signed an agreement with private Australian developer and producer GB Energy to purchase all the natural gas to be produced from GB Energy’s Golden Beach gas field about 3 km off Gippsland in eastern Victoria.
GB Energy estimates the field, in retention permit Vic/RL1 (V) in Victorian state waters, will produce 50 petajoules of gas over a 3-year period. The gas will be sold to Origin at an undisclosed fixed price.
GB Energy plans to develop the field via a pipeline coming ashore near the township of Golden Beach and transporting the gas to a new processing plant near the ExxonMobil-BHP facilities at Longford.
Pipeline construction is expected to begin late this year or early in 2020 and first gas is scheduled to come ashore in 2022. The Origin deal will underpin the field development and the gas will be sold into the domestic market.
Origin has also entered into a foundation storage contract with GB Energy when the company transitions the field reservoir into an underground storage facility at the end of the field’s natural productive life.
Golden Beach field was discovered in 1967 by Burmah Oil Co., but was considered marginal, particularly as the gas has only minor liquid content. Ownership has passed through a number of hands since then, including Woodside, OMV Australia, and Santos. GB Energy is the current owner.
PROCESSINGQuick Takes
ExxonMobil lets contract for Beaumont refinery work
ExxonMobil Corp. has let a contract to KBR Inc. to provide services related to the operator’s recently approved project to expand refining capacity by more than 65% at its 366,000-b/d integrated refining complex in Beaumont, Tex.
As part of the reimbursable contract, KBR will deliver detailed engineering, procurement, and construction services for offsites and interconnecting units included in the expansion project, the service provider said.
KBR disclosed no further details regarding its scope of work under the contract for the proposed project.
This latest contract follows ExxonMobil’s earlier award to TechnipFMC PLC to provide EPC for four new units to be added as part of the project, including an atmospheric pipe still, kerosine hydrotreater, diesel hydrotreater, and benzene recovery unit. Already under construction, the expansion project will add a third crude unit within the refinery’s existing footprint that will increase light crude refining capacity at the site by 250,000 b/d, supported by increased production in the Permian basin, ExxonMobil said.
Part of the operator’s 10-year, $20-billion “Growing the Gulf” investment initiative, the crude unit is scheduled for startup by 2022.
ExxonMobil previously announced plans to build and expand manufacturing facilities in the US Gulf region as part of its Growing the Gulf initiative. Growing the Gulf projects include expansion of Beaumont’s polyethylene capacity by 65%, a new selective cat-naphtha hydrofining (SCANfining) unit to increase production of ultralow-sulfur fuels by 45,000 b/d at Beaumont, and a new 1.5 million-tonne/year ethane cracker at the company’s integrated chemical and refining complex in Baytown, Tex. (OGJ Online, July 26, 2018).
ExxonMobil and SABIC have also created a new joint venture to advance development of the Gulf Coast Growth Ventures project, a 1.8 million-tpy ethane cracker currently planned for construction in San Patricio County, Tex. (OGJ Online, May 7, 2018).
Borouge lets contract for cracker at Ruwais complex
Abu Dhabi Polymers Co. Ltd. (Borouge), a joint venture of Abu Dhabi National Oil Co. (ADNOC) and Borealis AG, has let a contract to a subsidiary of Maire Tecnimont SPA for work related to another project designed to expand production capacities at Borouge’s integrated polyolefins complex in Ruwais, about 250 km west of Abu Dhabi City, UAE (OGJ Online, July 18, 2017).
Tecnimont SPA will deliver front-end engineering and design services for the fourth expansion phase of Borouge’s Ruwais complex, which will include a mixed-feed cracker with an ethylene production capacity of 1.8 million tonnes/year.
The cracker—which, once completed, will become the complex’s fourth—also will be associated with several other unidentified processing units, utilities, and off sites.
Maire Tecnimont said it expects to complete its scope of work under the FEED contract—valued at $45 million on a reimbursable basis—sometime in 2020.
This latest contract follows Borouge’s previous award to Tecnimont to deliver engineering, procurement, and construction services for a fifth polypropylene plant (PP5) at the site that will have a maximum production capacity of 480,000 tpy (OGJ Online, July 13, 2018).
In late 2018, Borouge broke ground on construction of the PP5, which upon completion in third-quarter 2021, will expand the operator’s polypropylene production capacity by more than 25% to 2.24 million tpy, Borouge said.
TRANSPORTATIONQuick Takes
Judge’s latest order still blocks Keystone XL
US District Judge Brian Morris issued a ruling allowing TransCanada Corp. to build and use pipe storage and container yards for the proposed Keystone XL crude oil pipeline. But the Feb. 15 order reportedly continues to block construction of worker camps, effectively keeping work from beginning on the project. TransCanada is sponsoring the proposed 830,000-b/d, 36-in. heavy crude system from Hardisty, Alta., to Steele City, Neb.
Morris previously vacated a Mar. 23, 2017, US Department of State Record of Decision authorizing Keystone XL’s construction and ordered further environmental reviews (OGJ Online, Nov. 9, 2018). TransCanada said at the time that it remains committed to the project. Officials from the Association of Oil Pipe Lines and American Petroleum Institute separately criticized Morris’s order.
EPP begins service on Shin Oak NGL mainline
Enterprise Products Partners LP (EPP) has placed into service its Shin Oak natural gas liquids mainline from Orla in Reeves County, Tex., to its NGL fractionation and storage complex at the Mont Belvieu hub (OGJ Online, Apr. 10, 2017). The 24-in. pipeline has an initial capacity of 250,000 b/d and provides takeaway for increasing NGL production from multiple basins, including the Permian, where NGL volumes are forecast to nearly double within the next 3 years, the company said.
Completion of the related 20-in. Waha lateral is scheduled for this year’s second quarter. Supported by long-term customer commitments, the Shin Oak project will ultimately provide as much as 550,000 b/d of capacity, which is expected to be available in this year’s fourth quarter.
Once the pipeline is complete, NGLs for Shin Oak will be sourced primarily from EPP’s Orla gas processing complex, which began operations in 2018, as well as dedicated acreage from the Alpine High development (OGJ Online, May 7, 2018). A third train at Orla is expected to begin service in this year’s second quarter, followed by EPP’s Mentone gas processing plant, expected to begin service in first-quarter 2020. The facilities will give EPP more than 1.6 bcfd of gas processing capacity and more than 250,000 b/d of NGL production capabilities in the Permian basin.
Complementing EPP’s Permian basin assets is the addition of NGL fractionation capacity at its Gulf Coast facilities. The projects are expected to raise the partnership’s systemwide fractionation capacity to 1.5 million b/d by second-quarter 2020.
Operators to link Conway-Mont Belvieu NGL markets
Williams Cos. Inc. and Targa Resources Corp. have entered into agreements to expand key systems that will link the Conway, Kan., and Mont Belvieu, Tex., NGL markets.
As part of the agreements, Williams will build the 188-mile Bluestem NGL pipeline from its Conway fractionator and the southern terminus of the Overland Pass Pipeline (OPPL) to an interconnect with Targa’s Grand Prix NGL pipeline in Kingfisher County, Okla., while Targa will build a 110-mile extension of Grand Prix from southern Oklahoma into the STACK region of central Oklahoma where it will connect with Williams’ new Bluestem pipeline, the companies said.
Williams also has committed an unidentified volume of NGLs to Targa for transport on Grand Prix and fractionation at Targa’s Mont Belvieu operations. Per the agreement, Williams will have an initial option to purchase a 20% equity interest in one of Targa’s planned new fractionation Trains 7 or 8 in Mont Belvieu.
At an estimated cost of about $200 million, Targa’s Grand Prix extension will have an initial capacity of about 120,000 b/d (OGJ Online, Mar. 28, 2018).
Targa and Williams are targeting an in-service date of first-quarter 2021 for both the Grand Prix extension and the new Bluestem pipeline, respectively. As part of the project, Williams also plans to expand the DJ Lateral of the OPPL and make improvements at its Conway NGL storage site (OGJ Online, July 30, 2018).
Williams said it expects to invest $350-400 million in the NGL logistics projects.
The proposed agreements will enable both Williams and Targa to capture synergies from growing NGL volumes currently produced from Wamsutter and DJ basin operations, the companies said.
API releases updated liquid pipeline integrity standard
The American Petroleum Institute released the third edition of API Recommended Practice 1160, “Managing System Integrity for Hazardous Liquid Pipelines,” on Feb. 27. It said RP 1160 provides a process for establishing safe pipeline operations, including robust assessments of potential risks and establishment of systems to safely and sustainably manage them throughout day-to-day operations.
“A strong and reliable infrastructure system that prioritizes safety is not only in the best interest of our industry, but also for the environment and the consumers we serve,” said Debra Phillips, API’s vice-president of global industry services. “The update of RP 1160 advances our shared goal of a safe and sustainable oil and gas industry that meets the energy needs of American consumers.”
API said RP 1160’s third edition incorporates recent industry experience about pipeline mechanics while embracing a rigorous, proactive approach to safe pipeline operation (API RP 1173). This will help pipeline operators build a safe, contemporary, and comprehensive integrity management system, it noted.
The latest updated RP also contains references to leading industry publications, such as pipeline leak detection (API RP 1175), assessment and management of cracking in pipelines (API RP 1176), integrity data management and integration (API RP 1178), and hydrotechnical hazards for pipelines located onshore or within coastal areas (API RP 1133).
