Absolute Open Flow Potential

The absolute open flow potential (AOFP) is the maximum theoretical flow rate a gas well could produce if the flowing wellhead pressure were reduced to atmospheric pressure (zero gauge pressure), with no mechanical restrictions in the wellbore. It is determined from deliverability tests that measure actual well performance at two or more stabilized flow rates, then extrapolate the performance curve to zero flowing bottomhole pressure. AOFP is used to characterize gas well deliverability, size surface facilities and compression requirements, negotiate gas sales contracts, compare wells across a field, and allocate production in multi-well pads. Because producing a well at AOFP would require zero backpressure on the reservoir (not achievable in practice due to surface facilities, pipeline pressures, and equipment limits), AOFP is a theoretical maximum rather than an achievable operating rate. A well's actual contracted or facility-constrained rate is typically 20 to 50 percent of AOFP in Alberta's Montney and Deep Basin gas plays.

Key Takeaways

AOFP is determined using backpressure deliverability tests. In the simplified (empirical) backpressure equation, the flow rate Q is related to reservoir pressure Pr and flowing bottomhole pressure Pwf by: Q = C × (Pr² - Pwf²)^n, where C is the deliverability coefficient and n is the backpressure exponent (ranging from 0.5 for fully turbulent flow to 1.0 for fully laminar Darcy flow). Setting Pwf = 0 (atmospheric) and Pr = current reservoir pressure in the equation gives the AOFP. Real tests measure two or more flow rates and their associated flowing bottomhole pressures to determine C and n, then extrapolate to zero Pwf.
The isochronal test is the standard deliverability test method in Alberta and British Columbia, required by the AER for gas wells in most formations. In an isochronal test, the well is flowed at two to four different rates for equal time periods (typically 2 to 4 hours each) and then shut in between each flow period to allow reservoir pressure to recover toward the initial value before the next flow period. This method gives transient data points that can be extended to stabilized deliverability by combining the isochronal data with a single extended flow period. The modified isochronal test skips the full pressure recovery between flow periods and instead uses shut-in pressures (which haven't fully recovered) as reference pressures, significantly reducing test time from weeks to days.
Turbulence (non-Darcy skin) reduces a gas well's deliverability below what Darcy's law would predict at high flow rates. In tight gas wells (Montney, Spirit River), the flow velocities near the wellbore and in the fractures can be high enough that inertial forces become significant alongside viscous forces, causing an additional pressure drop proportional to the square of the flow rate. This turbulence term, characterized by the Forchheimer parameter D, effectively reduces the deliverability exponent n below 1.0. High-productivity wells with long fractures (high n approaching 1.0 at low rates) show n decreasing at higher rates as turbulence becomes dominant near the wellbore. Neglecting turbulence overestimates AOFP for high-rate wells.
Alberta Energy Regulator (AER) Directive 040 (Pressure and Deliverability Tests for Oil and Gas Wells) governs deliverability testing requirements in Alberta. For new wells in many formations, at least one deliverability test is required before or shortly after production commences, and the AOFP is reported to the AER as part of the well's production scheme. The test result is used in the AER's maximum production rate calculations and determines the maximum rate a well is permitted to produce without re-testing. Operators who exceed the permitted rate based on AOFP face regulatory scrutiny and may be required to re-test.
In Montney horizontal wells in northeast British Columbia, AOFP values from multi-rate deliverability tests typically range from 100 to 1,000 thousand cubic metres per day (Mcm/d) for wells with 2,000 to 3,000-metre laterals and 20 to 40 fracture stages. Actual contracted sales rates are typically 50 to 150 Mcm/d, representing 10 to 50 percent of AOFP. The large gap between AOFP and actual production rate reflects the backpressure applied by gathering system compression, sales pipeline delivery pressure, and facility throughput constraints, not insufficient reservoir deliverability.

What AOFP Tells You About a Gas Well

Think of AOFP as the top speed of a car measured on a flat road with no speed limits. The car can theoretically reach 200 kilometres per hour, but on real roads with traffic, curves, and speed limits, it operates at 80 to 120 kilometres per hour. AOFP is the reservoir's theoretical maximum deliverability. The actual production rate is set by the practical constraints of the surface facilities and pipeline system.

The ratio of contracted rate to AOFP (called the deliverability ratio or production ratio) tells the operator how much capacity margin exists. A well producing at 30 percent of AOFP has room to increase production if the gathering system can take more gas. A well producing at 90 percent of AOFP is essentially at its deliverability limit: it cannot produce significantly more regardless of facility changes. Understanding this ratio helps the operator plan compression, gathering system capacity, and future well drilling programs.

AOFP also declines as reservoir pressure depletes over the life of the field. If a Montney gas pool is at initial pressure of 35 megapascals and initial AOFP is 500 Mcm/d, after 10 years of production and pressure decline to 20 megapascals, the AOFP from the same deliverability equation drops to roughly 270 Mcm/d (because the available pressure drawdown has decreased). Surface facilities must be designed to remain useful at this lower future deliverability.

Fast Facts

The empirical backpressure equation Q = C × (Pr² - Pwf²)^n was introduced by Rawlins and Schellhardt of the US Bureau of Mines in 1935 and remains the basis for most gas well deliverability analysis in North America despite its empirical origins. The theoretical basis was provided by Houpeurt (1959) and Jones, Blount, and Glaze (1976) who derived the deliverability equation from first principles including Forchheimer's non-Darcy flow term, giving the turbulence-corrected deliverability equation that is now standard. In Alberta, the AER's requirements for deliverability testing were formalized in Directive 040 in the 1970s and have been updated periodically to account for new well types (horizontal wells, multistage-fractured wells) that require modified test procedures. For tight gas wells with very long transient periods, a single conventional multi-rate test may not achieve stabilized flow within a practical time frame, and modern rate transient analysis (RTA) techniques are sometimes used instead to estimate deliverability without a formal multi-rate test.

AOFP in Regulatory Compliance and Field Development Planning

In Alberta, the AER uses AOFP to set Maximum Production Allowables (MPAs) for gas wells. The MPA is the rate at which the AER permits a well to produce based on its reservoir characteristics and the need to protect reservoir integrity and correlative rights. For a pool with many wells drawing from a shared reservoir, the AOFP-based MPA for each well prevents any single operator from draining the pool faster than its productive capacity allows, protecting the rights of other lessors in the same pool.

For gas wells in the Foothills of Alberta (where reservoir pressures can exceed 70 megapascals), AOFP testing is also a critical safety step. Running a Foothills well wide open without knowing its AOFP risks exceeding the rated capacity of the surface safety valves, pressure vessels, and control systems. The test, done in controlled stages with progressively increasing flow rates and immediate shut-in capability if pressure limits are approached, gives the operator a safe upper bound before full-scale production begins.

AOFP is also called absolute open flow (AOF), maximum deliverability, or theoretical open flow potential. Related terms include deliverability test (a well test designed to measure the relationship between flow rate and pressure drawdown at a gas well; the multirate, isochronal, or modified isochronal test is the standard method for determining AOFP), backpressure (the pressure at the wellhead imposed by the gathering system, compressor suction, or sales pipeline; controls the actual producing rate relative to AOFP; reducing backpressure increases production rate toward AOFP), inflow performance relationship (IPR, the relationship between flowing bottomhole pressure and production rate for a well; the gas well IPR extends from zero rate at reservoir pressure to AOFP at atmospheric pressure), non-Darcy flow (flow regime at high velocity near the wellbore or in fractures where inertial forces cause pressure drop additional to the viscous Darcy term; reduces apparent deliverability at high rates and causes n to be less than 1 in the backpressure equation), and maximum production allowable (MPA, the AER-regulated maximum rate at which a well in Alberta is permitted to produce, typically based on AOFP and pool-wide conservation considerations).

How AOFP Testing Avoided an Undersized Compressor at a Duvernay Pad

An operator was preparing for first production from a four-well Duvernay gas condensate pad in the Kaybob area of west-central Alberta. The wells had been fractured and completed but not yet put on production. The surface facilities design called for a 6,000-horsepower compressor station to handle peak production from all four wells simultaneously. The facilities engineer had estimated peak well AOFP at 80 Mcm/d per well based on analogue wells in the area, giving a total pad AOFP of 320 Mcm/d and selecting the compressor to handle 300 Mcm/d with a 6 percent reserve margin.

The operator conducted modified isochronal tests on all four wells before commissioning the compressor station. The tests returned AOFP values of 115, 98, 87, and 102 Mcm/d for the four wells, a combined AOFP of 402 Mcm/d, 25 percent higher than the estimate used in the facilities design. The higher AOFP was attributed to more natural fracture development in this part of the Duvernay than the analogues used for the estimate.

With a combined AOFP of 402 Mcm/d, the 6,000-horsepower compressor would be the production bottleneck from day one of production, leaving the wells throttled to 75 percent of AOFP and deferring approximately 100 Mcm/d of daily production indefinitely. The operator added a parallel 3,000-horsepower compressor at a cost of CAD 4.2 million rather than the CAD 8.1 million full replacement that would have been required if the undersizing had gone undetected until first production. The AOFP tests, which cost CAD 280,000 in rig time and engineering, identified the facilities gap in time to correct it before the compressor station was locked in as permanent infrastructure.