Secondary Production
Secondary production (also called secondary recovery) is the phase of oil and gas field development that follows primary production (the initial exploitation of reservoir energy by natural drive mechanisms) and employs an injected fluid -- typically water (waterflood) or gas (pressure maintenance by gas injection or gas cap expansion) -- to supplement the depleted reservoir energy, maintain or restore reservoir pressure, and physically displace additional hydrocarbons from the pore space toward the producing wells, recovering oil and gas volumes that would remain unproduced under primary depletion alone; secondary production typically begins when the primary production rate has declined to an economically unacceptable level due to pressure depletion (as the solution gas comes out of solution and the gas-oil ratio rises above the optimal range, reducing oil relative permeability) or when a reservoir engineering analysis indicates that the ultimate recovery from primary drive alone will be significantly less than the estimated maximum recoverable resource that a waterflood or pressure maintenance project could achieve; the most common secondary recovery method globally is water injection (waterflooding), in which water sourced from an aquifer, produced water recycling, or seawater treatment is injected through dedicated injection wells to maintain reservoir pressure and sweep oil toward the producing wells, improving recovery factors from the 20 to 30 percent of original oil in place (OOIP) typical of primary recovery to 35 to 50 percent of OOIP in favorable reservoir conditions; secondary gas injection (either into the gas cap to maintain gas cap pressure and prevent gas cap shrinkage, or into the oil column to maintain pressure above the bubble point and prevent solution gas liberation) is used in reservoirs where water injection is not practical (due to formation water sensitivity, water sourcing challenges, or reservoir geometry) or where the gas has economic value as an injectant that can be stored and later produced.
Key Takeaways
- Waterflood design requires selection of the injection-production pattern (the geometric arrangement of injection and producing wells that determines the sweep efficiency and the distribution of injected water through the reservoir), with common patterns including the five-spot (four producing wells at the corners of a square pattern with one injection well at the center), the nine-spot (eight producing wells surrounding a central injection well), the line drive (rows of injection wells alternating with rows of producing wells), and the peripheral injection (injection wells arranged around the perimeter of the reservoir to push oil toward the interior producing wells); the choice between pattern types depends on the reservoir's areal heterogeneity (highly heterogeneous reservoirs benefit from closer well spacing to prevent channeling of injected water through high-permeability streaks that bypass the lower-permeability matrix), the viscosity ratio between oil and water (unfavorable mobility ratios, where the injected water is more mobile than the oil it is displacing, cause early water breakthrough and poor sweep efficiency), and the reservoir geometry (elongated or fault-bounded reservoirs favor line drive patterns that align with the long axis of the reservoir); the five-spot pattern has been the industry standard for conventional sandstone waterfloods since the 1950s because it provides reasonable sweep efficiency and well spacing flexibility, with the mobility ratio being the single most important parameter governing ultimate waterflood recovery.
- Voidage replacement ratio (VRR) is the operational control parameter for waterflood pressure maintenance, defined as the ratio of the volume of injected fluid (at reservoir conditions) to the volume of produced fluid (oil, water, and gas, all at reservoir conditions) from the pattern; a VRR of 1.0 (voidage balanced) means that the injected volume exactly replaces the produced volume, maintaining reservoir pressure at the pre-waterflood level; a VRR greater than 1.0 (overfilling) increases reservoir pressure above the pre-waterflood level, potentially causing surface breakthrough of injected water through geological conduits or inducing formation fractures; a VRR less than 1.0 (underfilling) allows reservoir pressure to decline below the bubble point, causing solution gas liberation, increased gas-oil ratio, and a reduction in oil relative permeability that increases residual oil saturation and reduces waterflood efficiency; maintaining VRR near 1.0 requires continuous monitoring of injection rates, production rates, GOR trends, and wellhead pressures, with injection well capacity management (acid stimulation, injection well recompletions, and workover programs) ensuring that the injection capacity meets the VRR requirement as producing wells age and water cut increases.
- Waterflood efficiency is the product of displacement efficiency (the fraction of the oil in the swept pore volume that is displaced by the advancing waterfront, governed by the relative permeability curves, the mobility ratio, and the capillary pressure) and sweep efficiency (the fraction of the total reservoir pore volume that is contacted by the injected water before the producing wells reach their economic limit); displacement efficiency for a water-wet sandstone is typically 60 to 80 percent (because water preferentially enters the smaller pore throats and displaces oil from the larger pores, leaving only residual oil saturation Sor in the swept zone), while displacement efficiency for a mixed-wet or oil-wet reservoir is lower (30 to 60 percent, because oil films on pore walls are not displaced by water in an oil-wet system); sweep efficiency is typically 50 to 80 percent for well-designed patterns in laterally continuous reservoirs, reduced by geological heterogeneity (high-permeability channels that the water preferentially follows, bypassing lower-permeability oil-bearing intervals), the unfavorable mobility ratio (water mobility/oil mobility greater than 1.0, causing the water to finger through the oil rather than advancing as a piston), and reservoir layering (where thief zones in high-permeability layers take most of the injected water, leaving oil stranded in low-permeability layers); chemical EOR methods (polymer flooding, surfactant flooding, alkaline-surfactant-polymer ASP flooding) address these limitations by improving displacement efficiency (surfactant reduces interfacial tension, releasing capillary-trapped residual oil) and sweep efficiency (polymer increases water viscosity to improve mobility ratio, reducing fingering).
- Secondary gas production (the gas produced from a reservoir as an incidental consequence of water injection) includes solution gas that comes out of solution when reservoir pressure falls below the bubble point despite water injection (because VRR management is imperfect or because certain reservoir compartments are not adequately supported by the injection), and gas cap gas that migrates down-dip as the gas-oil contact falls in response to oil production from below the gas cap; in reservoirs with significant gas caps, the secondary production plan must address whether to produce the gas cap gas immediately (blowdown), recycle it by injecting it back into the gas cap to maintain pressure (gas cap reinjection), or sell it to a gas market; gas cap reinjection (where the produced gas is compressed and reinjected into the gas cap through dedicated gas injection wells) maintains the gas-oil contact position, prevents the gas cap from expanding down into the oil zone and causing gas coning at producing wells, and preserves the gas reserves for later production at higher gas prices -- a strategy used extensively in the Middle East (particularly in Kuwait's Burgan field and Abu Dhabi's Zakum field) where gas reserves are maintained in the reservoir as pressure support while oil production is the primary economic objective.
- Water-alternating-gas (WAG) injection is a secondary and tertiary recovery technique that alternates cycles of water injection with cycles of gas injection (typically CO2, natural gas, or nitrogen) through the same injection wells, providing both the pressure maintenance benefits of water injection and the oil swelling, viscosity reduction, and minimum miscibility pressure (MMP) flooding benefits of gas injection; during the gas injection phase, the gas sweeps the upper part of the reservoir (taking advantage of gravity override to flood the top of the interval where waterflood has been least efficient), reduces the residual oil saturation in the gas-contacted zone, and improves displacement efficiency; during the water injection phase, the water sweeps the lower portion of the reservoir and prevents the gas from completely overriding the structure by providing gravity stabilization of the gas-water-oil system; the alternation frequency (from weeks to months per cycle), the WAG ratio (the volume of water per volume of gas injected per cycle), and the injection rate optimization are the key operating parameters of a WAG project, with simulation studies used to optimize these parameters for the specific reservoir geometry and fluid system; WAG injection has been successfully applied in the Rangely field (Colorado), West Pembina Cardium pool (Alberta), and Ekofisk field (Norway).
Fast Facts
The first systematic waterflood for secondary recovery was conducted in the Bradford oilfield of Pennsylvania in the 1880s and 1890s, where operators observed that water intrusion from the surface into shallow oil wells (a problem initially considered a nuisance) was actually re-pressurizing the reservoir and recovering additional oil that had not been produced during the primary depletion phase. These accidental waterflood observations led to deliberate peripheral and pattern water injection experiments in the Pennsylvania and West Virginia oil fields in the 1920s and 1930s, establishing the technical basis for the waterflood that became the dominant secondary recovery method of the 20th century. The API's first comprehensive study of waterflood results (1959) compiled data from hundreds of US waterflood projects and established the statistical relationships between reservoir properties, flood pattern, and ultimate recovery that guided waterflood design for the following two decades. Today, waterfloods produce the majority of the world's oil -- estimates suggest that more than 50 percent of current global daily oil production comes from waterflooded reservoirs, with primary production having contributed less than 30 percent of the cumulative oil produced from these fields.
What Is Secondary Production?
Secondary production is the phase of reservoir development that supplements depleted natural reservoir energy with an injected fluid -- primarily water (waterflooding) or gas (pressure maintenance injection) -- to maintain reservoir pressure, displace additional hydrocarbons toward producing wells, and improve recovery beyond what primary depletion achieves. Waterflooding is the most common secondary recovery method, typically improving recovery factors from 20-30 percent of OOIP to 35-50 percent in favorable conditions. Secondary gas injection maintains gas cap pressure or pressure above the bubble point. Voidage replacement ratio management is the primary operational control parameter for secondary recovery projects.