Mobility Control

Key Takeaways

• The mobility ratio is the single number that predicts whether a displacement will be efficient or catastrophic, and understanding it before designing any injection program prevents the most expensive waterflooding mistakes — for a waterflood in a light oil reservoir (20-30 cp oil viscosity at reservoir conditions), the water-oil mobility ratio is often 5-10 (water is 5-10 times more mobile than oil), which produces highly unstable displacement with water fingering to the production wells rapidly while bypassing 50-70% of the oil; for a heavy oil reservoir (100-1,000 cp oil viscosity), the mobility ratio can reach 50-200, making conventional waterflood essentially ineffective as a recovery mechanism; the polymer flood solution adds HPAM at concentrations of 500-2,000 parts per million to the injection water, increasing its viscosity by 3-20 times and reducing its effective relative permeability through viscoelastic effects, bringing the mobility ratio to near 1 or below; the improvement in sweep efficiency from controlling mobility translates directly to incremental oil at the producing wells — wells that would have broken through to water within months of waterflood start can instead produce at high oil cut for years under polymer flood conditions; the incremental oil calculation for a polymer flood must account for both improved areal sweep (the polymer bank contacts more of the reservoir area before breaking through) and improved vertical conformance (the polymer preferentially enters high-permeability streaks and reduces their transmissibility, forcing subsequent injection into lower-permeability zones that contain more of the remaining oil).
• Polymer flooding is the most widely deployed mobility control technology and has been applied at commercial scale in reservoirs ranging from the Daqing field in China (the world's largest polymer flood) to North Sea chalk reservoirs to heavy oil fields in Canada, with lessons learned from each application improving the design of the next — HPAM polymer works by increasing the viscosity of the injection water through its long-chain molecular structure, and by reducing water relative permeability through adsorption onto pore surfaces and plugging of large pore throats (a mechanism called "resistance factor" reduction); polymer flood design requires selecting the polymer concentration that delivers the target mobility ratio without exceeding the injectivity loss that would make the flood economically marginal, the molecular weight that provides viscosity without unacceptable mechanical degradation through the injection pump and wellbore perforations, and the injection rate that maximizes oil recovery without inducing fractures in the formation that would short-circuit the flood; polymer is sensitive to salinity (high-salinity brines reduce viscosity), temperature (high temperature degrades HPAM), and hardness (divalent cations calcium and magnesium reduce effectiveness) — polymer flood design in a saline, high-temperature reservoir requires selecting a polymer formulation that retains its viscosity under those conditions, which may mean using sulfonated polyacrylamide or xanthan biopolymer rather than standard HPAM.
• Foam flooding uses surfactant-generated foam as the mobility control agent in gas injection projects, where the mobility ratio problem is even more severe than in waterfloods because injected gas is typically 100-1,000 times more mobile than reservoir oil — in CO2 EOR, nitrogen flooding, or steam flooding in heterogeneous reservoirs, the injected gas phase overrides (rises to the top of the reservoir due to buoyancy) and channels through high-permeability zones, bypassing the oil-saturated matrix almost entirely; foam generated by co-injecting a surfactant solution with the gas dramatically reduces the gas mobility by trapping gas in small bubbles surrounded by liquid lamellae, increasing the effective gas viscosity from near-zero to values of 10-100 cp at reservoir conditions; foam selectively plugs the high-permeability zones where gas mobility is highest (because foam is more stable in high-velocity flow through large pores) and diverts subsequent injection into the lower-permeability zones that contain more of the remaining oil; field applications of foam EOR have demonstrated incremental oil recovery of 5-20% over un-foamed gas injection in heterogeneous reservoirs, and recent offshore applications in the North Sea (the Snorre field, for example) have shown that foam can be delivered effectively in subsea injection systems at commercial scale.
• Reservoir heterogeneity determines how much mobility control can actually improve recovery, because a perfectly homogeneous reservoir with good mobility ratio already achieves excellent sweep and polymer or foam adds little incremental value — the value of mobility control increases with reservoir heterogeneity: the wider the permeability contrast between high and low-perm zones, the more injected fluid has bypassed the oil in those zones, and the more incremental oil can be recovered by improving sweep; screening criteria for mobility control candidates include a permeability variation coefficient above 0.6 (indicating significant heterogeneity), a viscosity ratio above 2 (indicating the need for mobility reduction), and sufficient remaining oil saturation in the bypassed zones to justify the treatment cost; reservoirs that have already been extensively waterflooded and have reached high water cut (above 90%) are sometimes excellent polymer flood candidates if the high water cut reflects poor sweep rather than actual depletion — in these cases, the water is cycling through the swept high-perm zones while the low-perm zones remain full of oil; a well-designed polymer flood can redirect injection through those bypassed zones and produce oil that a conventional waterflood would have left permanently in place.
• The economics of mobility control projects are determined by the incremental oil recovery divided by the polymer or surfactant cost, and the projects that fail economically almost always do so because the incremental recovery was overestimated or the chemical cost was underestimated — polymer costs $1-4 per pound, and a typical polymer flood at 1,000 ppm concentration injecting 0.5 pore volumes of polymer solution costs $5-15 per barrel of pore volume treated, which must be offset by incremental oil of at least 3-8% of pore volume to achieve a positive return at $60-80 oil; the incremental recovery prediction comes from reservoir simulation, which requires accurate characterization of the heterogeneity, the adsorption loss of polymer on the rock surface (which consumes polymer without providing mobility benefit), the polymer degradation rate at reservoir temperature, and the injectivity reduction from polymer viscosity; optimistic assumptions on any of these parameters produce an incremental recovery prediction that fails to materialize in the field, which is why polymer flood projects should be piloted in a pattern of injection and production wells before full-field deployment — a pattern pilot costs $5-20 million and provides the field-measured response data needed to calibrate the simulation and validate (or revise) the economic projection before committing $200-500 million to a full-field polymer flood.