Surfactant-Alternating-Gas

Surfactant-alternating-gas (SAG) injection is an enhanced oil recovery (EOR) and mobility control technique in which slugs of surfactant solution and gas (typically nitrogen, carbon dioxide, or lean hydrocarbon gas) are injected alternately into a reservoir to generate foam in-situ within the porous medium, reducing the effective gas mobility by one to three orders of magnitude through trapping of gas in liquid lamellae and thereby mitigating the gravity override, viscous fingering, and channeling instabilities that cause gas-only injection projects to sweep only a small fraction of the reservoir pore volume before gas breakthrough; the foam generated by SAG injection acts as a high apparent viscosity blocking agent that diverts subsequent injected fluids into unswept low-permeability zones and untouched areas of the reservoir, improving volumetric sweep efficiency from the typical 30 to 50 percent achieved by straight gas injection toward 60 to 80 percent or higher in favorable reservoir geometries; SAG injection is particularly effective in high-permeability-contrast or highly layered reservoirs (where gas without foam would channel through the highest-permeability streaks and leave low-permeability layers unswept) and in thick reservoirs with significant vertical relief where gravity override would otherwise cause the gas to migrate immediately to the top of the formation and produce through the highest-elevation wells without sweeping the middle and lower reservoir sections.

Key Takeaways

Foam mobility reduction factor (MRF) is the key performance parameter for SAG injection and quantifies how much the effective gas mobility is reduced by foam formation in the porous medium — MRF is defined as the effective gas mobility without foam divided by the effective gas mobility with foam, and values of 100 to 10,000 are achievable in laboratory core floods and field pilots depending on the foam quality (gas volume fraction), surfactant type and concentration, and rock wettability; high-MRF foam generated in the pore network physically traps gas bubbles between liquid lamellae (thin films stabilized by the surfactant), reducing the gas mobility from its drainage value (which may be 10 to 1,000 times higher than the oil or water mobility, creating severe channeling) to a value comparable to or lower than the resident oil mobility, forcing the injected fluid front to advance on a more uniform basis through all permeability layers; foams generated by alpha-olefin sulfonates (AOS) or internal olefin sulfonates (IOS) at concentrations of 0.1 to 1 weight percent in brine can achieve MRF greater than 1,000 in consolidated sandstone cores with permeabilities of 100 to 1,000 mD, but MRF drops significantly in the presence of residual oil (which destabilizes foam lamellae through oil-foam interaction mechanisms), and the in-situ MRF under reservoir conditions with residual oil present must be measured specifically for the target formation.
SAG slug design parameters — slug size, gas-to-surfactant alternation ratio, and injection rate — determine the balance between foam generation efficiency and injectivity during the surfactant half-cycle; injection of surfactant solution into a formation that contains trapped gas from the previous gas slug generates foam immediately at the injection face, creating a high apparent viscosity zone (sometimes called a foam bank) that propagates through the formation ahead of the injected fluid; if the surfactant slug is too small (less than 0.01 pore volumes), the surfactant is diluted below the critical micelle concentration (CMC) and foam generation is insufficient; if the surfactant slug is too large, the project economics deteriorate because surfactant costs ($2 to $10 per kilogram for typical AOS or IOS surfactants) are the dominant variable cost in SAG injection; typical SAG slug sizes range from 0.01 to 0.10 pore volumes of surfactant solution alternating with 0.05 to 0.30 pore volumes of gas, with the alternation continuing for 1 to 5 cycles before evaluating the response; the injection pressure during the gas half-cycle can increase by 2 to 10 times above the pre-SAG injection pressure as the foam block builds up, providing a direct surface indication that foam is being generated and acting as the primary real-time diagnostic for SAG performance.
Gravity override mitigation is the most compelling application of SAG injection in thick reservoirs with high vertical permeability — in a gas injection project without foam, the low gas density (typically 0.1 to 0.3 g/cc at reservoir conditions) versus the resident oil density (0.7 to 0.9 g/cc) creates a buoyancy pressure gradient that drives the gas upward through the reservoir toward the highest-elevation structural position and then along the crest to the producing wells; in a 100-foot net pay reservoir with gravity override, the effective swept zone may be only the top 10 to 30 feet (10 to 30 percent of the gross interval) with the remainder swept only by whatever crossflow occurs across the vertical permeability gradient; SAG injection at the injection wells generates foam preferentially in the high-permeability flow paths at the top of the reservoir (where the gas first tries to go), creating a diversion of subsequent gas injection into the middle and lower pay sections; quantitative estimates of the improvement in sweep efficiency from SAG over straight gas injection in gravity-dominated reservoirs (based on reservoir simulation studies calibrated to field data) typically show 15 to 30 percentage point improvements in the fraction of oil in place recovered at a given injection volume, which translates to large incremental recoveries in fields with significant oil in place at risk of gravity override loss.
CO2-SAG for combined mobility control and carbon sequestration is an active area of development driven by the dual objectives of improving CO2-EOR project economics through better sweep efficiency while also maximizing the volume of CO2 retained in the reservoir for permanent geological storage; CO2 is a particularly challenging gas for conventional injection because its low viscosity (approximately 0.05 to 0.1 cP at reservoir conditions near the critical point) relative to reservoir oil and water results in extreme channeling that causes early breakthrough and low displacement efficiency; CO2-SAG using IOS-based surfactants that remain effective in the presence of CO2 (which is mildly acidic, reducing pH to 3 to 4 in saline brine, and requires acid-stable surfactants) has been tested at pilot scale in Weyburn (Saskatchewan) and in several Gulf Coast CO2-EOR projects, with results showing improved injectivity distribution and delayed CO2 breakthrough compared to straight CO2 injection; in CO2 geological storage projects without EOR objectives, SAG or foam injection in the injection well near-wellbore region is used to prevent CO2 override during early injection before pressure buildup distributes the CO2 across the full perforation interval.
Surfactant stability and adsorption loss are the primary technical challenges for economically viable SAG injection — surfactant adsorption onto rock surfaces (particularly on clays and carbonates where the electrostatic interaction between the anionic surfactant and positively charged mineral surfaces is strong) removes surfactant from the injected solution, depleting the foam-generating capability before the surfactant slug reaches the target reservoir zone; adsorption losses of 0.1 to 1 mg surfactant per gram of rock are typical for anionic sulfonates on mixed-wet carbonate formations, and these losses require increased surfactant concentration (or injection slug size) to ensure sufficient active surfactant reaches the inter-well region to generate effective foam; pre-flushing the formation with sacrificial agents (sodium carbonate or sodium tripolyphosphate) that preferentially adsorb on the high-adsorption mineral sites before the surfactant injection can reduce effective adsorption losses by 30 to 60 percent; at reservoir temperatures above 90 to 100°C, thermal stability of the surfactant molecule (hydrolysis of the ester linkage in ether sulfates, desulfonation in linear alkyl sulfonates) must be evaluated, and IOS or AOS surfactants with better thermal stability are preferred over the less stable alcohol ethoxy sulfates for high-temperature SAG applications.

Fast Facts

The concept of injecting foam into reservoirs to improve sweep efficiency was first proposed by Bond and Holbrook at Shell Development Company in 1958, and the alternating-slug approach that defines SAG injection was developed and patented by Fried at Shell in 1961. The world's first major field-scale SAG injection project was the North Ward-Estes field in Ward County, Texas, where surfactant-alternating-CO2 injection was tested beginning in the late 1980s with results demonstrating improved CO2 distribution and delayed breakthrough compared to straight CO2 injection. Significant subsequent field implementations include the Snorre field (North Sea, Norway) where N2-SAG was used to control gas mobility in fractured chalk reservoirs beginning in the 1990s, and the Prudhoe Bay field (Alaska) where nitrogen-SAG was tested for gravity override control in the Sadlerochit Reservoir. The theoretical framework for SAG injection simulation was substantially advanced by work at Stanford University (Radke and Prausnitz on foam rheology, Kovscek and Radke on the mechanistic foam in porous media model) and Shell's research center in Amsterdam, producing the mechanistic foam simulation models now available in commercial reservoir simulators including CMG STARS, Schlumberger Eclipse 300, and Intersect.

What Is Surfactant-Alternating-Gas Injection?

Gas injection EOR works by reducing oil viscosity, maintaining reservoir pressure, and displacing oil toward producing wells — but it is limited by the fact that injected gas is far less viscous and less dense than the reservoir oil and water it is displacing. This creates two problems: the low-viscosity gas fingers through the highest-permeability paths in the rock, bypassing most of the reservoir volume (viscous fingering); and the low-density gas migrates to the top of the reservoir, overriding the oil in the middle and bottom of the formation (gravity override). The result is early gas breakthrough at producing wells while large fractions of the oil in place remain uncontacted.

SAG injection addresses both problems by generating foam in the pore network. Foam is not a separate phase injected into the reservoir — it is created in-situ when the injected gas and surfactant solution contact each other in the pore space and the surfactant stabilizes gas-liquid interfaces to form lamellae (thin liquid films) that trap gas bubbles in the pore throats. These foam lamellae act like very viscous plugs in the flow path, diverting subsequent gas into the unswept zones. The alternating injection pattern — surfactant slug, then gas slug, then surfactant slug, then gas slug — is designed to ensure that gas and surfactant are repeatedly brought into contact throughout the reservoir, maintaining active foam generation as the injection front advances toward the producing wells.

SAG Injection Design and Field Implementation

A SAG injection project begins with laboratory core flood studies that characterize foam generation efficiency, MRF, and surfactant adsorption for the specific rock and fluid system using candidate surfactants at target reservoir temperature and pressure. The core flood results are used to calibrate a mechanistic foam simulation model that accounts for foam generation, coalescence, and transport in heterogeneous porous media. Reservoir simulation then evaluates different SAG slug designs, injection rates, and well patterns to forecast the incremental oil recovery and the economic return on the surfactant investment. Field implementation typically begins with a single-well injection test or a small pilot pattern (one injector, one or two producers) to confirm that the laboratory foam behavior translates to field scale and to calibrate the reservoir simulation model against actual injection pressure and production response. The primary field observable confirming foam generation is a sustained increase in injection pressure during the gas half-cycle — a factor of 2 to 5 increase in injection pressure at constant rate, compared to the pre-SAG baseline pressure, confirms that a foam block has formed and is providing the mobility control needed to divert flow into unswept zones.