As the upstream industry enters 2026, the industry continues to sharpen its performance on every front. Drilling technologies for ultralong laterals have pushed acreage acquisitions and M&A to the stratosphere, while producers and well fracturing service companies continue to home in on game-changing completion technologies that will continue to boost estimated ultimate recovery rates going forward.

There has been an incredible amount of scientific progress and technical achievement in recent years. So many more promising technologies are being tested in the field today, while unbridled imagination has engineers and geoscientists testing new concepts that will become the standard-setting tools of tomorrow.

With high-rate precision horizontal drilling setting new records by the day, hydraulic fracturing at scale, and multiwell pad development yielding high-rate production rates, technological innovations are keeping workflows moving at seemingly warp speed. What is in store for America’s oil and gas operators, who now produce by far the most crude oil and natural gas in the world and who continue to grow daily energy export volumes?

One does not have to go further than the industry’s technical society events, producer/operator conventions, and specialized conferences to see the continued pace of new ideas and processes ramping up. From practical concepts and processes to science projects only now on the drawing boards, the ingenuity and technical proficiency of the U.S. energy industry will continue to astound.

One certain strategy will prevail in 2026: winners likely will not be the companies that “try everything.” Instead, they will pick the exact right innovations aligned with their acreage, talent, and available capital and execute all along the decision-making chain of command while operating with discipline, efficiency, and safety.

While operational achievements will earn bottom-line boosts from ever-improving supply chain and logistics capabilities, emissions control, and water management technologies, I see several areas of innovation worth investigating. With the industry becoming highly proficient at drilling ultralong laterals piloted to multiple stacked pay zones, operators are turning to reservoir modeling technology to tie all the data together. Meantime, a new era of specialty completion techniques are being proven at the same time proppant additives are proving that minor upfront costs can yield higher long-range production rates that vastly outweigh smart front-end investments.

Reservoir Modeling

Exponential advancements in reservoir modeling software make integrated modeling more accessible to both in-house scientists and consultants at lower cost levels, providing new levels of understanding of subsurface characteristics and reservoir conditions. The results range from quicker and safer drilling to new completion programs that sync chemistry with specialty proppants that are true game changers, whether considering initial production rates, long-range uplift from primary completions, or potential for future enhanced recovery operations.

Reservoir teams will never get a perfect “look-at-it-with-your-own-eyes” view of what is happening below the surface. That is why reservoir simulators and earth models matter. The latest solution are enabling operators to turn previously disparate datasets into seamless models that incorporate all available data, from seismic to logs, cores, tests, and production histories to drive improved decision making.

In simple terms, subsurface modeling has two parts:

• Static modeling, or what the rock looks like with respect to structure, faults, and reservoir properties; and
• Dynamic simulation, or how it will perform in terms of forecasted rates, pressures, and recovery factors under different development scenarios.

For years, the term integrated asset modeling sounded like something only majors could afford. That has changed quickly. Faster simulation, better coupling between subsurface and surface constraints, and more interactive workflows are bringing serious modeling capability within reach of all sizes of operators, whether they are operating in unconventional plays or conventional geology and legacy fields. This technology can help answer critical reservoir and field development questions with high degrees of accuracy, including:

• Should more wells, or automated artificial lift techniques and equipment, and even compression changes, be added first?
• Are any barrels being left behind because of backpressure and gathering constraints?
• What is the best development timing when facilities and drilling schedules do not perfectly line up?

The shift in 2026 is that operators are increasingly treating the reservoir, wells, and surface system as a single interconnected ecosystem, and using integrated modeling to iterate faster decisions with more confidence.

Rock Flow Dynamics’ tNavigator™ is one example of a platform positioned around this shift: taking multi-disciplinary workflows (reservoir, wells, and surface networks) and solving them in a way that reflects how the system actually behaves. One of the key ideas highlighted in advanced reservoir simulators is moving beyond “uncoupled” workflows, where the reservoir forecast is built separately from the surface network model. Coupling previously unconnected workflows enables operators to account for backpressure impacts from surface equipment and pipeline systems on well performance and tubing head pressure, rather than treating the surface and subsurface as separate environments.

Striving For Optimization

That matters because small to midsize producers, as well as companies that integrate upstream and midstream assets, are increasingly striving for optimization to increase returns. When the task is to squeeze new value out of existing lease positions, small constraint-driven gains add up. That is especially true when a model can help avoid the expensive mistake of optimizing one part of the system only to inadvertently bottleneck another.

Computing power is everything. Whether implementing proprietary artificial intelligence tools, visualizing data, or modeling reservoir performance, computational efficiencies and user interfaces are increasingly tied to graphics processing units. Workflows that required specialized and complex computing infrastructure can now be run on a high-end GPU workstation, a gaming-class laptop, or the cloud, producing decision-impacting results in minutes or hours instead of days and weeks.

The takeaway is that one does not need to build a monster full-field model for future operations. A full menu of “what if” scenarios that characterize alternative development planning, debottlenecking, schedule sequencing, and surface/subsurface constraint testing can be done on the fly, making integrated modeling far more usable in the real tempo of operations.

As a best practice, operators are using integrated modeling for the areas where they most often encounter uncertainty or hurdles, such as development timing, facility constraints, gathering system backpressure, or compression and stimulation planning. Even a basic model that helps spot surface constraints or identify when facilities might be oversized can support better decisions and avoid costly missteps.

Extended-Reach Drilling

Moving on to drilling and better completions, extended-reach and U-turn well architectures are no longer merely a talking point, but a design pathway that is increasingly visible in the well data. API’s analysis of horizontal well length trends in the Permian’s Midland sub-basin notes that that more than half of Midland Basin wells completed in 2025 exceeded 10,500 feet laterally.

That does not mean every operator should chase “four-mile” lateral designs. It does mean that directional drilling capability, bit technology, mud systems and execution methods are continuing to expand the practical envelope.

While these super long laterals are exciting, they beg the question of whether all the additional footage along the extended borehole path will be effectively stimulated, and whether stages will remain productive over time. Industry literature includes cases where production per foot can go down 10-20% in three-mile laterals. In 2026, the industry will continue to decipher data to determine if extending the reach to win on a cost-per-foot basis could lower initial production gains and long-term EUR through a drop off in completion effectiveness at the toe sections of laterals.

The good news is that the same operational progress that enables long laterals is also compressing cycle times. Faster drilling is not just a headline, but what makes long laterals workable without blowing up well costs. The bottom-line evaluation has to do with the learning curve for evaluating longer laterals, with operators studying torque and drag limits, casing design, frac logistics, and the ability to optimize production from the toe to the heel.

Proppants And Additives

Of course, if it is all about the rock, then completion effectiveness is the holy grail and where the industry is hunting for durable, repeatable uplift. In 2026, three proppant-related ideas are among those drawing attention: refinery-sourced petroleum coke proppant, engineered microproppant, and neutrally buoyant proppant (NBP).

ExxonMobil has been scaling the use of petroleum coke sourced from its own refineries as a proppant additive blended with sand in Permian wells. In ExxonMobil’s shared documentation, it claims wells pumped with sand plus petcoke delivered 7-18% more first-year production than comparable offsets fractured with only sand, attributing the advantage to the coke’s light weight and buoyancy to reach parts of the fracture network that sand alone cannot.

Microproppant is another solution for more effective stimulation treatments using proppants on the order of 500 mesh blended with conventional sand to prop small fractures inaccessible to traditional 40/70 and 100 mesh sands.

According to Zeeospheres Ceramics, two-thirds or more of the created fracture network can remain unsupported using traditional proppant sizes, but microproppants such as the company’s Deeprop™ are small enough to enter into fractures as they propagate to leave more of the stimulated area around the wellbore propped. Consequently, all sizes of operators are now stocking microproppant to maximize stimulation treatment performance and improve long-term productivities and EURs.

Another weapon in the industry’s proppant arsenal is neutrally buoyant proppant such as OmniProp™, available from Sun Specialty Products. The idea is to carry sand and other proppant materials deeper and more uniformly so more of the created fracture network ends up propped and conductive.

The company notes that the NBP is designed specifically to blend with sand in slickwater completions to improve placement, preserve flow paths, and increase propped fracture coverage, with economic studies showing that the increased production far outweighs the cost of adding NBP. In fact, the company says initial case studies report incremental increases in first-year production as high as 25-35%.

The common denominator for evaluating these new proppants and additives is to think small to achieve completion outcomes and to measure success beyond the initial production rates to consider treating response, pressure behavior, and normalized cumulative production over time.

Empowering Demand

While hydraulic fracturing has always been an energy-dense operation, the new 800-pound gorilla in terms of increased natural gas production is growing artificial intelligence applications and the giant data center buildouts required to implement them.

In 2026, power consumption needed for data centers, along with the continued buildout of liquified natural gas export facilities, may well dovetail to create one of the most important prime movers for innovations and demand growth for America’s upstream oil and natural gas industry in more than a decade. It is already being recognized as a game changer, with enough clout to re-route capital, equipment, and change operations strategies.

The “power story” is becoming inseparable from the field completion strategies. As electricity markets tighten and turbine supply becomes harder to secure, operators should assume that power availability can become either a bottleneck or a competitive scheduling advantage. Whether the solution is e-frac where feasible, a microgrid, or field gas-fueled engines, the operators who manage the power supply chain will protect their frac calendars and, ultimately, their cash flows.

From all of the crew at The American Oil & Gas Reporter, we wish you good health and all of the best in the new year.