Report Apr. 3, 2018
Upstream operations: Americas
Our Americas portfolio includes unconventional oil and natural gas, deepwater developments, conventional fields, and oil sands projects. Operations in the Americas accounted for 36 percent of our global net oil and natural gas production.
Report Apr. 3, 2018
Upstream operations: Americas
- Started up the 150 Kbd Hebron project
- More than tripled our unconventional resource in the Permian Basin
- Final investment decision to proceed with Liza Phase 1
- Expanded Upstream position in Brazil via exploration and discovered resource captures
With a focus on technological improvements, operational efficiency, and high-quality drilling programs, we are enhancing the profitability of our producing fields. In addition, we continue to grow our position in tight-oil plays, including the Permian and Bakken, where we have more than 10 billion oil-equivalent barrels of combined resource.
ExxonMobil is a leading producer and leaseholder across the Permian, with strong positions in the Midland Basin, Central Basin Platform, and most recently, the Delaware Basin. At year-end 2017, we operated 21 drilling rigs in the Permian, up from 10 the previous year. Net Permian production averaged 129,000 barrels of liquids per day and 200 million cubic feet of natural gas per day, an increase of more than 20 percent since 2016.
Several strategic transactions in 2017 added approximately 275,000 net acres across the Permian Basin, largely in the Delaware Basin, growing our overall Permian position to nearly 1.8 million net acres across the prolific stack of multiple formations. This extensive and highly contiguous position gives us decades of low-risk resource to produce and the ability to optimize development.
In the Permian, since early 2014, we have successfully doubled our footage drilled per day on horizontal wells. During that same period, we have reduced our per-foot drilling costs by about 70 percent. Longer-lateral wells, made possible by our contiguous acreage position, and larger completions will enable us to increase ultimate recoveries and reduce development cost per barrel.
Our goal for the Permian is to create a flagship development with premier profitability, safety, and environmental performance. Concurrent with increasing drilling, completion, and production activity, we are expanding midstream infrastructure to avoid logistical bottlenecks that other operators may encounter and to feed our manufacturing sites along the U.S. Gulf Coast.
The Bakken remains one of our most active unconventional programs, with net production volumes averaging 80,000 barrels of liquids per day and more than 90 million cubic feet of natural gas per day.
We hold approximately 570,000 net acres of high-quality resource in the Bakken and brought more than 90 wells online in 2017. We successfully drilled and completed four 3-mile-lateral wells in 2017, reducing the cost per lateral foot drilled by 19 percent. Best practices are being incorporated elsewhere in the Bakken – as well as in the Permian – to increase recovery and profitability.
Other unconventional liquids plays
ExxonMobil has attractive positions in other U.S. liquids plays, including the Ardmore and Marietta of Oklahoma, and the Eagle Ford of Texas. ExxonMobil brought more than 20 wells online in these areas in 2017, producing approximately 30,000 net barrels of liquids per day in total.
Unconventional gas plays
We have a diverse portfolio across most major U.S. unconventional gas plays, with strong positions in low-cost-of-supply plays like the Haynesville in East Texas and the Utica and Marcellus in Pennsylvania and Ohio. Combined average net production from the Utica, Marcellus, and Haynesville was more than 675 million cubic feet of natural gas per day in 2017, an increase of approximately 20 percent since 2015.
In 2017, ExxonMobil established a strong Upstream position in Brazil, through the addition of discovered resources and high-quality exploration acreage, including opportunities in the pre-salt play.
We significantly increased our exploration position in Brazil’s Round 14, winning 10 of 13 offshore blocks. We also reached an agreement to acquire equity interest and operatorship in two additional blocks in the same area.
In October, along with our partners, we captured the North Carcara block, containing a portion of the Carcara pre-salt field, with an estimated full-field recoverable resource of more than 2 billion high-quality oil-equivalent barrels. Concurrently, we completed a farm-in agreement to purchase interest in the BM-S-8 block, containing the remainder of the discovered, undeveloped Carcara field. The farm-in to BM-S-8 is expected to close in the first half of 2018 and, with the North Carcara block, provides a material position in a large, deepwater oil development.
We continued our exploration success in Guyana, adding further value to our growing portfolio in the country. We made our sixth significant offshore oil discovery, testing a new play concept for the Stabroek block with the Ranger-1 well. This discovery adds to previous world-class discoveries at Liza, Payara, Snoek, Liza Deep, and Turbot, which are estimated to total more than 3.2 billion recoverable oil-equivalent barrels. Additional exploration drilling is planned on the Stabroek block for 2018, including additional drilling at the Ranger and Turbot discoveries.
In June, we announced the final investment decision for the first phase of the world-class Liza development, which includes a floating production, storage, and offloading (FPSO) vessel designed to produce up to 120,000 barrels of oil per day. Production is expected to begin by 2020, fewer than five years after discovery, which is four years faster than the industry average.
Development planning is progressing for subsequent phases in the greater Liza area. The regulatory process is under way for the Phase 2 FPSO vessel, with capacity up to 220,000 barrels per day and start-up in 2022. Phase 3 will follow closely. These first three phases will develop approximately 2 billion oil-equivalent barrels of the 3.2 billion oil-equivalent barrels discovered to date. Additional phases are being defined to develop the remaining resource.
Through our wholly owned affiliate, ExxonMobil Canada, and majority-owned affiliate, Imperial Oil Limited (IOL, ExxonMobil interest, 69.6 percent), ExxonMobil has one of the largest resource positions in Canada and a significant portfolio of major projects, both onshore and offshore.
The ExxonMobil-operated Hebron project, located on the Grand Banks of Newfoundland and Labrador, achieved first oil on schedule, in November 2017. The project is expected to produce more than 700 million gross barrels of oil, and initial production volumes are exceeding expectations. A fiber optic cable connects the 750,000-tonne platform to an onshore control center 430 miles away, enabling a cost-efficient, remote staffing model for operations and maintenance. We also see the potential for additional digital optimization opportunities over the life of the development.
In 2017, Kearl-mined bitumen averaged 178,000 barrels per day (ExxonMobil and IOL). Several known reliability issues have been addressed, which is expected to result in a production increase to approximately 200,000 barrels per day in 2018. Plans are progressing to increase annual production by an additional 40,000 barrels per day by 2020 through the installation of additional crushing capacity.
Heavy oil: in-situ resources
The Cold Lake heavy-oil field produced 132,000 net barrels of oil per day (ExxonMobil and IOL). Cold Lake is one of the largest thermal in-situ, heavy-oil projects in the world, with 1.5 billion barrels produced to date and more than 30 years of production remaining. Since the inception of the Cold Lake development, continuous improvements and advances in technology have more than doubled the expected recovery from the initial commercial development area. Experimental pilots in the Cold Lake field have proven the benefits of new technologies to enhance ultimate recovery and reduce greenhouse gas emissions. In 2017, we progressed regulatory filings for further expansion at Cold Lake using pilot-proven technology.
ExxonMobil and IOL continue to evaluate heavy-oil acreage in the Athabasca and Cold Lake regions, including Aspen, Clarke Creek, Corner, Cold Lake Expansion, and Clyden. In 2017, we progressed regulatory filings for Aspen with the Alberta Energy Regulator. The potential Aspen development would use Solvent-Assisted Steam-Assisted Gravity Drainage (SA-SAGD) technology that could be up to 25 percent more capital efficient, and cost-competitive in a low-cost environment. In addition, this technology drives about a 25 percent reduction in greenhouse gas emissions compared to traditional SAGD projects.
Technology: Maximizing profitable volumes
ExxonMobil strives to optimize every well, every facility, and every asset – every day. Continued developments in surveillance and optimization technologies help minimize downtime events and maximize profitable volumes. Our technologies help compare high-end reservoir predictions with real-time data to make better decisions. Surveillance workflows automatically alert operations engineers, recommending actions to improve production in real time. In one example, automated systems identified an opportunity for material uplift at our Cold Lake asset. In another, automated systems identified a 3 percent production uplift and eight workover opportunities at the Hoover field in the Gulf of Mexico.
Technology: Advanced modeling and simulation accelerate development
A key to maximizing the value of oil and natural gas developments is to model and accurately predict how hydrocarbon reservoirs will perform throughout their lifetimes. Reservoir models and simulations guide decisions on well placement, facility design, and operational strategies to minimize financial and environmental risk. More than 65 years after ExxonMobil researchers developed the industry’s first digital reservoir simulator, our advanced reservoir modeling and simulation technologies enable our geoscientists and engineers to more effectively assess multiple scenarios simultaneously and predict reservoir performance to make better investment decisions. In 2017, computational breakthroughs led to unprecedented capabilities. We have used these capabilities to optimize well placement and design at Arkutun-Dagi, reducing costs and increasing our return on investment. These technologies are also being used to accelerate unconventional resource developments.
Digital Annual Report Report • Apr. 3, 2018
Digital Annual Report Report • Apr. 3, 2018