Report April 2, 2019
Global Upstream portfolio
We aim to highgrade our diverse portfolio of opportunities, selectively invest in the most advantaged projects, and execute projects with the highest standards of excellence. This approach enables us to meet the world’s growing demand for energy, while also creating value for resource owners and shareholders. These principles have delivered the most attractive Upstream opportunities since the Exxon and Mobil merger, with assets that have an industry-competitive cost of supply, positioning us to perform competitively in a wide range of price environments. We have an Upstream presence in 41 countries and the World Oil and Gas Council named ExxonMobil “Explorer of the Year” for the second year in a row in 2018.
Report April 2, 2019
Global Upstream portfolio
Global net production by region
(percent, oil-equivalent barrels)
We produced 3.8 million net oil-equivalent barrels per day in 2018, with 59 percent liquids and 41 percent natural gas.
We successfully added new production volumes to our portfolio in 2018, while maintaining a focus on producing the most profitable barrels. Successful ramp-up of the Odoptu Stage 2 project in Russia contributed to a record level of production output from Sakhalin-1. Rig count in the United States doubled during the year, contributing to an increase in liquids production across U.S. unconventional plays of more than 70,000 barrels per day, primarily from the Permian. In Canada, the Kearl asset achieved a record average production level of 206,000 barrels per day gross, and the Hebron platform, which started up in late 2017 offshore Eastern Canada, continued to ramp up, reaching nearly 100,000 barrels per day of gross production at year end. The first of two FPSO vessels at the Kaombo project in Angola Block 32 began production during the year, with the second FPSO vessel expected to start up in 2019.
Liquids growth of more than 3 percent
(Excluding impact of entitlements and divestments.)
Upstream investments are focused on producing low-cost, high-return supplies of hydrocarbons that result in earnings and cash-flow growth across a range of price environments. We also continue to capture and test exploration acreage, pursue acquisitions and divestments, and sanction developments to highgrade our portfolio and create a pipeline of growth opportunities.
The Americas represent the largest component of our Upstream portfolio by resource base and production. The region includes assets across multiple resource types, including unconventional oil and natural gas, oil sands, deepwater, and conventional. Exploration activity in 2018 led to multiple attractive acreage captures in the region, including in Brazil, Canada, Suriname, and the U.S. Gulf of Mexico.
In addition to the Permian, we remain active in other opportunity-rich areas across the United States. For example, we more than doubled operated rig count outside of the Permian to 24 rigs and spud more than 225 wells during the year.
The Bakken is a key growth area for tight oil, with net production volumes in 2018 averaging more than 80,000 barrels of liquids per day and more than 105 million cubic feet of natural gas per day.
Our Bakken rig count increased from three at year-end 2017 to six at year-end 2018. Construction started on a facility expansion at our gas plant in Tioga, North Dakota, which will triple gas processing capacity. We also continue to optimize well and completion designs and test the optimal limits on horizontal lateral length, drilling eight 3-mile lateral wells in 2018.
U.S. net production
>6,600 operated horizontal wells in the United States
Other unconventional plays
ExxonMobil holds active positions in other major U.S. unconventional plays, including the liquids-rich Eagle Ford of Texas, and Ardmore and Marietta basins of Oklahoma, where we are actively testing the potential of multiple new targets. Additionally, we selectively invest in unconventional gas plays such as the Haynesville Shale, Freestone Trend, Utica Shale, and the Marcellus Shale. These other active unconventional assets produced more than 180,000 oil-equivalent barrels per day net in 2018.
In early 2019, we and our partner Qatar Petroleum made a final investment decision to proceed with development of the Golden Pass export project located in Sabine Pass, Texas. Construction will begin in the first quarter of 2019, and LNG operations are expected to start up in 2024. The extensive project and technology experience of ExxonMobil and Qatar Petroleum will provide the expertise, resources, and financial strength to construct and operate the facility successfully. Golden Pass will take advantage of an existing terminal and infrastructure to deliver low-cost LNG and secure a competitive position in the market. The $10 billion, three-train liquefaction project will have capacity to produce about 16 million tons of LNG per year. Golden Pass will help meet rapidly growing demand around the world, and will provide an additional and strategic LNG supply point with access to an abundance of U.S. shale gas supply to complement ExxonMobil and Qatar Petroleum’s existing LNG investments.
Unconventional development plan optimization
Proprietary reservoir modeling and simulation platforms, using high-performance computing, enable us to evaluate thousands of potential reservoir development options covering a range of well spacing, fracture geometry, and geologic settings to determine the optimal development plan. Combined with physical experiments and direct field observations, this technology improves development decision making. For example, recent field observation and modeling work in the Bakken has the potential to reduce well count up to 40 percent without any impact to recovery rates. The integration of automated physics-based modeling with rapid experimentation and field surveillance provides a significant technology advantage.
Through our wholly owned affiliate, ExxonMobil Canada, and majority-owned affiliate, Imperial Oil Limited (IOL, ExxonMobil interest, 69.6 percent), we have one of the largest resource positions in Canada and an attractive set of major projects, both onshore and offshore. ExxonMobil Canada strengthened this portfolio in 2018 by capturing an additional exploration block offshore Eastern Canada.
The ExxonMobil-operated Hebron development, located on the Grand Banks of Newfoundland and Labrador, continued to ramp up production by adding six wells in 2018, including a 1,489-meter, world-record gravel pack using our Internal Shunt Alternate Path Technology (ISAPT). Oil production averaged 62,000 barrels per day in 2018, with uptime of approximately 95 percent. Hebron is expected to produce more than 700 million barrels of oil. A fiber optic cable connects the 750,000-tonne platform to an onshore support center 210 miles away, enabling a technical support team to enhance operational performance.
Western Canada Unconventional
We operate in the unconventional Montney and Duvernay shale plays of Western Canada. Development of the Pass Creek Duvernay acreage continued in 2018, as 26 wells spud, and construction began on facilities to support further Duvernay development.
Kearl achieved record production levels in 2018
Kearl-mined bitumen reached record levels in 2018, averaging 206,000 gross barrels per day versus 178,000 gross barrels per day in 2017, reflecting strong progress on our improvement plans for the asset. Higher production resulted from improved reliability associated with ore preparation and improved feed management. Production is forecast to increase to 240,000 gross barrels per day in 2020 through the installation of additional crushing capacity and continued reliability enhancements. The combination of increasing production along with focused cost management is driving down unit cash operating costs toward a target of $20 per barrel. Testing of autonomous haul trucks and reduced diluent blend ratios are further examples of our ongoing focus to deploy advanced technologies to improve performance today and into the future.
Heavy oil: in-situ resources
The Cold Lake heavy-oil field is one of the largest in-situ, heavy-oil projects in the world with 147,000 barrels per day of production. We received approval in 2018 from the Alberta Energy Regulator for the Aspen and Cold Lake Expansion developments. The Aspen development has the potential to produce approximately 75,000 barrels of bitumen per day using the first major commercial application of next-generation SA-SAGD oil sands recovery technology.
Oil sands in-situ efficiency
Our next-generation, advanced in-situ oil recovery technology is designed to lower greenhouse gas emissions intensity and water use, while improving development economics. With current technology, steam is used to mobilize bitumen located underground so it can be produced to the surface. Our solvent-assisted, steam-assisted gravity drainage (SA-SAGD) technology enhances the mobilization of the bitumen by adding a light hydrocarbon fluid to the steam. Application of this technology in our operations is estimated to reduce greenhouse gas intensity and water use intensity by up to 25 percent, compared with traditional steam-assisted gravity drainage technology. In addition, the latest application of digital technologies such as automation and machine learning for steam flood and production optimization enable efficient recovery across our in-situ operations.
Development of our prolific acreage position in the Vaca Muerta continued in 2018. This included completion of an agreement with Qatar Petroleum, providing them with a 30-percent equity interest in our unconventional developments in Argentina. Additionally, along with our partners, we gained a new unconventional exploitation concession in the Sierra Chata block. In 2018, we operated two of the most productive wells in the basin, and we set a record for drilling the longest lateral well in the Vaca Muerta at nearly 11,000 feet.
Asia / Middle East
ExxonMobil is pursuing multiple development and expansion projects in Asia and the Middle East. These projects involve some of the world’s largest oil and natural gas fields, with activities including testing the optimal limits of horizontal drilling, increasing development capacity, debottlenecking, and bringing on new resources. Exploration also continues in the region with the capture of new deepwater acreage offshore Pakistan and completion of a large 3D seismic program offshore Malaysia.
ExxonMobil is now the leading crude oil producer in Indonesia, with the Banyu Urip Central Processing Facility (CPF) continuing to demonstrate exceptional operating performance.
The original planned production rate of 165,000 oil-equivalent barrels per day has steadily increased and reached 220,000 oil-equivalent barrels per day by the end of 2018 with targeted debottlenecking.
Additionally, reliability in 2017 and 2018 remained steady at an impressive 99 percent, a result of good reservoir management, plant optimization, and equipment reliability strategies.
ExxonMobil returned to Pakistan after 27 years, opening an office in Islamabad. We progressed several commercial agreements with key Pakistani natural gas entities to support LNG supply to the country, and acquired interest in Block G, located 143 miles offshore Pakistan, where we are participating in an exploration well in early 2019.
Capacity of 1 million barrels of oil per day targeted at Upper Zakum
United Arab Emirates (U.A.E.)
Upper Zakum in the U.A.E is one of the world’s largest oil fields, covering more than 1,150 square kilometers. In association with our joint venture partners, including Abu Dhabi National Oil Company (ADNOC), we are applying advanced reservoir simulation and extended-reach drilling technology to develop the field. Seven drilling rigs are currently operating from four artificial islands. Front-end engineering and design (FEED) will commence in 2019 to increase production capacity to 1 million barrels per day by 2024.
Ca Voi Xanh (Blue Whale)
The Blue Whale development is a potential domestic gas-to-power project that will provide secure and competitive energy to fuel the country’s economic growth. The development is supported by the largest known natural gas field in Vietnam, which we discovered in 2011. Significant progress on commercial agreements occurred during the year, and FEED commenced in early 2019.
Qatar produces more than one-fifth of the world’s LNG. Qatar’s North Field is part of the world’s largest non-associated natural gas field. Among IOCs, we hold the largest stake in Qatar’s upstream developments, with participation in the Ras Laffan and Qatargas LNG joint ventures, as well as natural gas projects Al Khaleej and Barzan. We have the largest equity share of the IOCs and participate in 12 of the 14 Qatari LNG trains.
In addition to existing partnerships with Qatar Petroleum (QP) in Qatar, the United States, the United Kingdom, and Italy, we expanded international cooperation with QP in 2018, most notably in Argentina, Brazil, Cyprus, and Mozambique.
As a participant in the North Caspian Sea Production Sharing Agreement (PSA), we are working with our partners to advance a multi-phased development of the Kashagan field, located in the Caspian Sea. Ramp-up activities in 2018 resulted in record production levels above 340,000 barrels of oil per day, an increase of 17 percent over 2017.
We participate in the Tengizchevroil joint venture, which includes a production license area encompassing the Tengiz field, the nearby Korolev field, and associated facilities.
The Tengiz Expansion Project, currently under construction, will increase overall capacity by as much as 260,000 barrels of oil per day. Site civil work is well advanced, and fabrication of more than 250,000 tonnes of process and utility modules is under way at yards in Kazakhstan, South Korea, and Italy. Infrastructure for module transportation through the Russian Inland Waterway System to the Caspian Sea is operational, with the first process modules reaching the site in 2018.
Exxon Neftegas Limited (ENL) operates the Sakhalin-1 project, which comprises the Chayvo, Odoptu, and Arkutun-Dagi blocks. The Arkutun-Dagi and Odoptu blocks achieved record production in 2018, which along with continued strong performance from the Chayvo field, set a record level of annual production from Sakhalin-1. Year-on-year production increased through the Chayvo Onshore Processing Facility, with the daily production rate at times reaching 300,000 barrels per day. ENL achieved strong reliability performance in 2018 of more than 95 percent.
ENL leverages technology to maximize the production of profitable volumes. Specifically, ENL continues to test the limits of extended-reach drilling at the Orlan platform to capture additional reserves from the eastern flank of the Chayvo reservoir. Furthermore, application of new multilateral technology allowed us to reach these new zones at costs significantly lower than drilling new wells.
Development drilling from the Berkut platform at the Arkutun-Dagi field continued, with seven wells drilled in 2018 and a new industry completion technology employed to control sand production. ENL successfully drilled six wells at Odoptu and implemented new smart completion technology to help achieve a new Odoptu block production record of more than 70,000 oil-equivalent barrels per day.
We continue to comply with all sanctions applicable to our affiliates’ investments in the Russian Federation.
ExxonMobil progressed multiple exploration activities and development projects in Europe in 2018. Geoscience collaboration efforts resulted in significant acreage captures off the coast of Ireland in the Porcupine Basin.
In April 2017, we signed an exploration and production sharing contract with the Government of Cyprus for offshore Block 10. Along with our partner, Qatar Petroleum, we began exploration drilling in November 2018. The first well, at the Delphyne prospect, did not encounter commercial quantities of hydrocarbons. The Stena IceMAX drillship then moved to the Glaucus prospect, where we made a gas discovery. Evaluation of the discovery is now under way.
ExxonMobil converted six License Options, initially awarded in 2016, into full Frontier Exploration Licenses (FEL) in the Porcupine Basin. Evaluation of the acreage is ongoing. Additionally, we acquired a 50-percent interest in FEL 3/18, with plans to drill an exploration well in 2019.
We completed front-end engineering and launched tenders for the Neptun Deep project. The proposed unstaffed platform in the Black Sea will leverage cMIST equipment utilizing ExxonMobil’s proprietary technology, which dehydrates natural gas inside pipes instead of in towers. ExxonMobil and our co-venturers continue to evaluate all aspects of the project.
Collaboration on the North Atlantic conjugate margin
ExxonMobil exploration teams in Calgary, St. John’s, and London are collaborating to appraise the resource potential in two offshore areas that were once adjacent, but which after 120 million years of plate tectonic activity, split apart to opposing shores in the North Atlantic. The area is known as the North Atlantic Conjugate Margin, and it encompasses offshore Canada on one side, and offshore United Kingdom and Ireland on the other.
Our collaboration combines learnings from multiple sources, including exploration activity in Canada and production activity in the Hebron and Hibernia areas, and recently acquired seismic data offshore Ireland (in particular within the Porcupine Basin, where ExxonMobil captured seven large blocks this year). These 2018 acreage captures strengthen an already attractive global deepwater portfolio.
ExxonMobil has an interest in 26 deepwater blocks in Africa, totaling more than 43 million gross acres, in addition to our attractive production and development portfolio. In 2018, we captured additional acreage offshore Mozambique, Namibia, and Equatorial Guinea, and commenced acquisition of a large 3D seismic survey offshore Mauritania.
The first of two FPSO vessels for the Block 32 Kaombo Split Hub project commenced production in 2018. The second FPSO vessel arrived on site in early 2019 and is expected to start up in the second quarter. Combined, the two vessels will recover approximately 600 million barrels of oil.
In 2017, ExxonMobil acquired interest in Mauritania blocks C-14, C-17, and C-22, which are located an average of 124 miles offshore. Together, they cover nearly 8.4 million acres in depths ranging from 3,300 to 11,500 feet. We initiated acquisition of ExxonMobil’s largest-ever proprietary seismic survey over these blocks in October 2018. The survey, which will include more than 6,500 kilometers of 2D and nearly 21,000 square kilometers of 3D seismic data, will continue into 2019 and is a critical component of block evaluations.
ExxonMobil continues to develop our interests in both the shallow-water and deepwater blocks in Nigeria, including Erha, Erha North, and Usan fields. Preparations are under way to recommence drilling in the shallow-water blocks in 2019, which produce at a daily rate of approximately 130,000 net oil-equivalent barrels. Two rigs are under contract and mobilized.
Africa net production
Australia / Oceania
ExxonMobil is one of the leading oil and natural gas producers in the Australia/Oceania region. We undertook exploration drilling in the region in 2018 and acquired a new exploration block in the Western Highlands of PNG.
Production reliability at the PNG LNG plant was 99% in the second half of 2018
Papua New Guinea (PNG)
Following the 7.5-magnitude earthquake that struck PNG in early 2018, the PNG LNG plant resumed operations ahead of schedule and produced LNG at rates above the facility’s original design with a high level of reliability. During the shutdown period, ExxonMobil accelerated maintenance previously scheduled for later in the year. The maintenance resulted in more efficient operations and slightly higher capacity following the outage. Production reliability averaged 99 percent for the second half of the year.
50+ years of production from the Gippsland Basin
ExxonMobil operates the Gippsland Basin Joint Venture and Kipper Unit Joint Venture, with 23 offshore installations and associated onshore plants in Victoria. ExxonMobil drilled two exploration wells in the VIC/PC70 block, which did not encounter commercial quantities of hydrocarbons. However, we continue exploration activities in an effort to help meet natural gas demand on Australia’s East Coast. In late 2018, we made the final investment decision to develop the West Barracouta gas field, bringing new supplies to this growing market.
All three LNG trains and domestic natural gas sales of the co-venturer-operated project transitioned to steady-state operations, with improved year-over-year reliability and volume throughput. The joint venture is transitioning to the next phases of investment. In 2018, the venture announced the final investment decision on Gorgon Stage 2, the first in a series of projects focused on additional drilling, compression, and satellite field development aimed at maintaining production rates.
ExxonMobil completed the sale of its 50-percent interest in WA-1-R, which contains the majority of the Scarborough gas field.
Digital Annual Reports Report • April 2, 2019
Digital Annual Reports Report • April 2, 2019
Digital Annual Reports Report • April 2, 2019
Digital Annual Reports Report • April 2, 2019