The following document provide a fictitious example that will help to provide the reader with an understanding of the term "Back out" and "Best Well Produces". (Note: "Best Well Produces" is sometimes called "Best Player Plays").

However prior to presenting this example, consider the following.

Your team is down by 10 points, so you put your best players back on the field to try to win. Similarly, if your oil production is below capacity because you are constrained by your gas or water handling capacity, you alter the line up of your wells to produce your best performing wells i.e. those wells that produce the most oil and the least water or gas ("best well produces").

However, when your best players go on the field, other players have to leave - you are only allowed some many players on the fields at any one time. Similarly with the best wells in play, some of the poorer performing wells have to be removed or cutback "back-out'. If the wells are all part of the same aligned field i.e. all have the same ownership, this is not normally an issue, but if the wells have different owners, who wants to be "backed out"?

While the above analogy is not exact, it hopefully provides a simple introduction to these concepts.

Example (For illustrative purposes only)

All facilities are designed for certain limits. In Figure 1 below, the separation vessel can handle 100 barrels of oil per day (bbls/day) and 10 Million cubic feet of gas per day (MMscf/day).

The owner of the separator has three wells that provide oil and gas to it. Initially these wells produced at maximum oil capacity (combined total of 100 bbls/day) with only limited use of the available gas capacity (5 MMscf/day). Individual well performance was:

Well 1 flows at 40 bbls of oil and 2 million cubic feet of gas per day.
Well 2 flows at 20 bbls of oil and 1 million cubic feet of gas per day.
Well 3 flows at 40 bbls of oil and 2 million cubic feet of gas per day.

However, in time, with the breakthrough of gas, well performance has dropped and the maximum oil production is limited by available gas capacity. As can be seen in Figure 1, separator is now operating at maximum gas capacity of 10 MMscfpd, but only 90 bbls/day out of a maximum 100 bbls/day of possible oil production. Individual well performance is:

Well 1 flows at 50 bbls of oil and 5 million cubic feet of gas per day.
Well 2 flows at 20 bbls of oil and 1.5 million cubic feet of gas per day.
Well 3 flows at 20 bbls of oil and 3.5 million cubic feet of gas per day.

Figure 1.


A different nearby owner has a small hydrocarbon discovery that cannot be economically developed on a standalone basis and contacts the separator owner to discuss the possibility of sharing his facility. This new development has one well. This well can flow at 10 bbls/day of oil and 1 mmscf/day.

There is spare oil capacity in the separator, but unfortunately no gas capacity. However, the owner of the facility (and the State) would like to maximize use of his facility and is willing to discuss the sharing of the facility provided that he is kept whole and not negatively impacted by this arrangement.

The owner then looks at all four wells and estimates the ratio of gas production to oil production (gas-oil-ratio or GOR). Well GORs are given below:

Well 1: 5 MMscf/50 bbls = 0.1 MMscf/bbl
Well 2: 1.5 MMscf/20 bbls = 0.075 MMscf/bbl
Well 3: 3.5 MMscf/20 bbls = 0.175 MMscf/bbl
Well 4: 1 MMscf/10 bbls = 0.1 MMscf/bbl

Well 3 produces the most gas per barrel of oil. By reducing oil production from this well, total gas production can be reduced allowing Well 4 to be developed. Well 3's oil production needs to be reduced so that its' associated gas production is reduced by 1 MMscf/day.

The wells gas to oil ratio is 0.175 MMscf/bbl. To reduce gas production by 1MMscf/day, well 3's oil production must be reduced by:

1 MMscf/0.175 = 5.7 bbls

Wells 3 production will now be 20 - 5.7 = 14.3 bbls/day. The new development is shown below.

Figure 2.


As can be seen total oil production from the separator has now increased to more than 94 bbls/day before the gas capacity constraint is again reached.

This methodology is an example of "best well produces". Wells 1,2 and 4 had better well performance (lower gas oil ratios) and therefore were produced in preference to well 3 to maximize overall oil performance.

However, although total oil performance has increased, the combined production from separator owner's wells (Wells 1, 2 & 3) has decreased as a result of well 4 coming onstream, the separator. Prior to Well 4 coming into the separator owner's combined production from wells 1, 2 & 3 was 90 bbls/day. Post Well 4 coming onstream, combined production from wells 1, 2 & 3 is 84.3 bbls/day. In other words the owner of Wells 1, 2 & 3 have had 5.7 bbls of production deferred and potentially lost from a value perspective depending on how long before it is possible to produce these barrels. This loss or deferment is called "backout" and Well 4's owners compensates the Well 3's owners for this loss or deferment of value.

In the example above the separator was oil and gas only. However, in existing facilities, production vessel capacity constraints could also include produced water or total liquids. Regardless of the constraint this methodology would apply.

In the Prudhoe Bay Unit and Kuparuk River Unit, facilities can have hundreds of wells flowing to them. Many of these wells now flow at low oil rates, but high produced water and associated gas rates. If facilities are gas or water limited, reducing production from these wells can enable better performing wells to be produced. Significant increases can be seen with little "backout" of existing production.

For example, when the Borealis Field came on production, Greater Prudhoe Area production was increased by approximately 30,000 bbls/day of low gas GOR oil for a "backout" at the GC2 facility of only around 1,000 bbls/day of high GOR oil.