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In the heart of Vaca Muerta, home to Latin America’s most promising shale gas and oil reserves, a discreet yet transformative technology has reshaped the energy landscape: Managed Pressure Drilling, or MPD.
As Argentina accelerates its push toward energy self-sufficiency, with natural-gas exports that analysts say could rival Qatar’s by 2030, MPD has emerged not as a futuristic gadget but as the essential mechanism that has lowered costs, sped up operations and reduced risks in one of the most challenging geological formations in the world.
But what exactly is this tool that has shifted from an experiment to a standard practice in most development wells?
MPD: Precise control in an unpredictable Vaca Muerta well
Imagine drilling a well thousands of meters deep, where bottom-hole pressure (BHP) fluctuates between the fragile stability of porous rock and the constant risk of fracturing it. Under conventional drilling, this meant lost circulation, long nonproductive time and exorbitant costs — as much as $10 million per well in Vaca Muerta.
MPD changes the equation by treating the annulus between the drill bit and the wellbore as an adaptable pressure vessel. Developed in the 1990s by the global oilfield industry, MPD uses systems such as the Rotating Control Device (RCD) and automated digital monitoring to apply surface backpressure in real time. Methods like Constant Bottom Hole Pressure (CBHP) keep pressure steady, allowing drilling in a low-balanced or dynamic mode with lighter fluids and rate-of-penetration (ROP) improvements of up to 25 percent.
In essence, MPD is not static overbalanced drilling. It is a proactive process that anticipates and mitigates unplanned events such as influxes or formation collapses.
A technical report from the International Association of Drilling Contractors (IADC) defines MPD as “MPD is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.”
In Vaca Muerta, where that pressure window is notoriously tight, especially in formations such as Quintuco and Vaca Muerta itself, MPD has been crucial for drilling long sections in a single run and eliminating unnecessary intermediate casings.
From challenge to mass adoption: a decade of evolution
More than a decade ago, operators in Neuquén faced a dilemma. Vaca Muerta’s geology, with high pressures and extreme temperatures, made conventional drilling inefficient and risky. Pilot projects launched by YPF with Schlumberger (SLB) in blocks like Loma Campana and Añelo sparked the shift. One notable case, documented in a Society of Petroleum Engineers (SPE) paper, details how MPD in shale-gas wells enabled extended-reach drilling (ERD) and cut nonproductive time by 40 percent.
Today MPD is everywhere. Most development wells in the basin are planned with MPD technology, according to Weatherford and Halliburton, two of the leaders in local deployment.
Archer, following its 2024 acquisition of ADA Argentina, now operates three active MPD systems in Vaca Muerta for major clients such as YPF. Nabors Industries, using its integrated PACE-F rigs, reports operational savings that helped boost drilling activity from 20 wells per month in 2015 to more than 100 in 2025, alongside crude exports exceeding 300,000 barrels per day.
Official Argentine sources, including reports from the Secretariat of Energy, note that MPD has aligned Vaca Muerta with global standards and contributed to a 15 percent improvement in overall value-chain efficiency. In the United States, the Bureau of Safety and Environmental Enforcement (BSEE), part of the Department of the Interior, confirmed similar gains in a 2015 analysis, stating that MPD “offers the capability to detect very small influxes when compared to using conventional rig equipment. When the influx is detected, MPD allows the BHP to be adjusted rapidly to control and minimize the size of the influx.”
Quantifiable benefits: fewer risks, higher returns
The numbers are clear. A study by the University of Leoben in Austria, conducted with industry partners, estimates that MPD reduces well-control events by 30 to 50 percent, cutting operational hours and lowering the use of expensive drilling mud.
In Vaca Muerta, this translates into savings of up to $2 million per well, according to Halliburton, which deployed its Victus MPD system in Neuquén and reported 90 percent reductions in lost-circulation events.
From an academic perspective, a 2021 University of Texas paper on dynamic well-control systems using MPD highlights its role in mitigating environmental risks: fewer fluid losses mean lower impacts on local aquifers, a sensitive issue in Patagonia.
Another MIT analysis (2022) on numerical optimization for ERD projects found that integrating MPD with logging tools accelerates the development of unconventional reservoirs by 20 percent.
However, not all assessments are glowing. Critics, including a 2021 report from the Stockholm Environment Institute, warn about water-related impacts in basins such as the Neuquén River. MPD mitigates these risks, but does not eliminate them, by optimizing fluid use ahead of hydraulic fracturing.