Dr. Johannes Alvarez serves as the enhanced oil recovery manager in the shale & tight business at Chevron Upstream. With over 23 years of experience as a senior reservoir and production engineer, he has contributed significantly to both industry practices and research and development. He is a forum chair for the 25th WPC Energy Congress. Here he talks about technical progress in the oil industry and the future of unconventional resources. All views are expressed in a personal capacity and are not the views of Chevron Corporation.
How much room do you see for US unconventional production growth over the next five to ten years, given capital discipline and investor expectations?
Over the next five to ten years, US unconventional oil production is expected to experience moderate growth, shaped by capital discipline, geological constraints, investor priorities and global market factors. The Permian Basin remains a primary contributor and two-thirds of US oil output still comes from unconventional sources. According to the US Energy Information Administration’s Annual Energy Outlook 2025, domestic crude oil production may reach 14m b/d by 2027-28, with the potential to climb to 18m b/d in the early 2030s under favorable conditions such as higher oil prices and enhanced recovery rates.
Conversely, in less advantageous circumstances—including lower pricing or diminished well productivity—industry output could decline post-2030, particularly as domestic demand falls and closer well spacing impacts efficiency.
Capital discipline is a principal factor moderating sector growth. The industry has shifted from prioritising volume expansion at all costs toward greater financial prudence, with publicly traded producers now focused on maximising shareholder returns. Consequently, investors have reoriented expectations toward dividends, share buybacks and debt reduction instead of aggressive drilling campaigns. From a geological and operational standpoint, development of premium acreage is largely complete, prompting operators to explore tier 2 zones that tend to be less productive and carry higher development costs. Unconventional wells also demonstrate steep decline rates—often up to 75% within two years—necessitating ongoing reinvestment to sustain output.
Global market dynamics are another variable. Robust export demand, particularly for LNG and refined products, supports continued US production growth. However, there is potential for global supply to outpace demand in the near term, which could exert downward pressure on prices. Sustained price weakness may reduce incentives for further investment and restrict incremental growth.
What role are technological improvements—like enhanced recovery, digital optimisation, or longer laterals—playing in sustaining these productivity gains in the US?
US production growth is largely due to technological advances. Laterals are now much longer, with more proppant mass, higher fluid volumes, tighter fracture clusters, higher stage counts and greater pump rates all contributing to more efficient production rates. These innovations over the past 15 years have cut average well costs by 40%, boosted initial oil production by 140% and reduced average cost per barrel by 80%.
Despite that, recovery remains low at just 8-12% of oil in place. This is where enhanced oil recovery (EOR) can help. Good completion methods paired with EOR technologies can increase recovery and slow decline rates. Chemical EOR enhances rock–fluid interactions and mobilises more hydrocarbons, while gas EOR uses hydrocarbon injection to recover otherwise unrecoverable oil. But key challenges remain, including economics, repeatability, standardisation and understanding first principles.
Digital optimisation is also transforming well operations. It helps with well design, completion design and hydraulic fracturing. AI-assisted drilling reduces flat time and improves directional control in long laterals. Additionally, predictive maintenance powered by AI anticipates equipment failures, streamlining operations, reducing downtime and enhancing safety.
What are the potential areas of growth for unconventional production outside the US?
Argentina’s Vaca Muerta leads the pack with an ambitious goal of reaching 1m b/d by 2030, supported by major local and global operators, although infrastructure remains a key hurdle. China is scaling up shale gas development in some basins, leveraging its large domestic operators. Geological and water-related challenges persist, but efforts are underway to overcome them. Saudi Arabia is exploring tight gas plays to support a 60% increase in gas output, with local operators driving innovation. Mexico’s Agua Nueva formation shows potential for up to 2.5bcf/d of gas, but regulatory and supply chain issues persist. Meanwhile, Canada’s unconventional plays continue steady growth, benefiting from established infrastructure and experienced operators, despite environmental and cost concerns. Each region’s success will depend on its ability to overcome technical and policy challenges while leveraging advanced technologies and strategic investment.
Staying outside the US, can you talk about the relative economics of shale, oil sands and deepwater production compared to conventional production? Will all these types of production need to be developed going forward, or will only the most economic survive?
These economics are influenced by cost, risk and strategic value compared to conventional oil. Middle Eastern conventional oil is the most economical, with development costs ranging from $8-27/b. Shale and tight oil development costs are in the $45-58/b range, but have rapid payback periods with internal rates of return close to 35%, making them appealing in regions such as Argentina and Canada.
Deepwater developments offshore Brazil and West Africa have also become more competitive, in the range of $43-50/b thanks to new technology. These projects offer large-scale assets with internal rates of return of around 25-30%, though they carry risks such as spills and high upfront investment. Oil sands, chiefly in Canada, are the least economical at $57-75/b and have high carbon intensity, likely limiting development to existing sites unless prices rise or carbon capture technology improves.
Not all resources will be developed. Conventional will remain dominant for now, while deepwater and shale could expand depending on location. Oil sands and Arctic projects may stagnate due to costs and environmental concerns unless justified by national strategies or technological innovation. Ultimately, economics, carbon intensity and geopolitics will dictate which production types persist. Infrastructure limitations could also hamper the growth of unconventional resources outside the US.
How is the push toward decarbonization shaping unconventional production development strategies, and is this less of an issue than it was five years ago?
The global push toward decarbonisation is significantly shaping unconventional oil and gas development strategies, more so now than five years ago. Methane regulation, carbon intensity targets and ESG scrutiny are no longer optional considerations—in many cases they are central to project viability. Producers are investing in technologies like leak detection, electrification and carbon capture to meet increasingly stringent standards. Regulatory frameworks are driving commitments to near-zero methane emissions and zero routine flaring by 2030.
These measures are not only environmental imperatives but also economic ones. Carbon intensity is now a competitive metric, with lower-emission producers gaining access to premium markets and favorable financing. Unconventional resources like shale and deepwater remain viable due to improving economics and relatively lower emissions, whereas oil sands and Arctic oil face mounting pressure from high carbon footprints and environmental risks. In this landscape, decarbonisation is not just a constraint—it is a strategic filter determining which projects move forward and which are left behind.
Comments