All oil and gas bearing reservoirs contain naturally-accumulated water. The water is in either or both of two forms: i) connate water that is homogeneously dispersed in the reservoir rock formation, generally in individual pore spaces; and/or: ii) as an aquifer or mostly water-saturated interval that can and often does co-exist with the hydrocarbons (oil or gas) in the same reservoir.
In such latter cases, gravity has done its work over time, and so the oil or gas is in the upper part of the formation and the water zone (referred to as: "the water leg") is in the lower part of the same formation because the water has the higher specific gravity. It may make sense to you that since natural gas has the lowest specific gravity, oil has the next-higher gravity and water the highest, then in some formations there exists complete gravity separation of these three mediums, gas-oil-water in that sequence, much like the layered liquor in a Zombie cocktail. The top gas layer is often referred to as: "the gas cap".
Consequently, the oil & gas producer has to deal with water to a greater or lesser extent depending upon: i) the stage of life of the project; ii) the propensity of the reservoir to produce water in the first place; or: iii) the ability of the producing formation (reservoir) to expel its water via natural flow, thereby eliminating the cost of lifting such water to the surface by mechanical means. For example, a natural gas well that has a flow rate in excess of 150,000 cubic feet per day can usually "lift" 10 - 30 barrels of water per day through the tubing in the well along with the gas, whether such water is connate water or water that begins to show during the later life of a gas well, as the "water leg" gets closer to the wellbore in the producing formation.
In oil production, it is often the case that no water leg or natural aquifer co-exists with the oil. In such instances, the reservoir energy is limited to natural gas in solution with the oil (as in C02 in beer). As the oil comes out of the reservoir and up the tubing in a well, the gas comes out of solution and the resulting "artesian well" effect drives the oil into a tank at the surface. But when that solution gas is gone, then much remaining oil is left as "dead" oil in place in the producing zone, unless water is injected at the surface to re-pressure the reservoir. Such activity is known as a "water flood", which is required to adequately drain this type of limited-water formation. Water floods are inherently expensive because of: i) sourcing large amounts of clean water that won't contaminate a formation by reacting with minerals or clays contained in the reservoir rock; ii) burning energy to pump the water into the formation; iii) pumping the water out and processing the total fluids at the surface.
Three desirable aspects characterize the oil in our Wilcox Basin project: i) the oil has commercial amounts of solution gas dissolved in the oil; ii) there is a defined "water leg" in contact with the oil that acts as a natural water-drive; and: iii) the formation water is not harmful to most other formations in that basin, thereby simplifying the disposal of such fluid in the immediate area of the oil production. As a consequence of the two "drive" mechanisms of solution gas and the water leg, the Wilcox formations that we produce from do not require water flooding and so the oil is swept from the reservoir more completely over time, with the least amount of production expense. Also, the solution gas is a handy source of energy to use in production operations at the wellsite, because it is used as fuel to run the engine of an oil pumping unit and to use in any oil-treating or flow line pumping facilities at the surface.
Economics - Since the most common aspect of oil production is how to deal with the water that comes along with it, keep in mind that oil wells produce both fluids in ratios varying in a continuum from 99% oil, 1% water; to: 99% water, 1% oil. These ratios vary depending upon the well, exactly where in the producing zone the well has penetrated in relation to the oil-water leg contact, the age of the well, the permeability of the reservoir rock, or combinations of all of the foregoing.
In the Wilcox Basin, the reservoir rock is generally very permeable and the water drive is strong. Therefore, water generally shows up early. What the oil-water ratio is at any given time can vary widely on a well-by-well or zone-by-zone basis. There are some wells that flow naturally for many weeks or months without the assistance of a pumping unit ("pump jack"). One of the wells near our fields has flowed for more than two years, although this is the exception. What is certain is that water production, to a greater or lesser extent, characterizes the major part of the life of an oil well. A look at the economics and the decision-making involved in how we deal with that water is shown below.
Discovery well - Flows naturally at 65 barrels per day ("BOPD") of oil (e.g.) for the first week, at an oil-water ratio of 90% oil. Total fluid: 72 BPD. Water in this mix: 7 barrels ("BWPD"). Too small a fraction to justify drilling a well solely for the purpose of disposing of the water. Therefore, accumulate the water in the surface facilities and haul it away in a truck provided by a service company for such purpose. In one month's time, the producer has accumulated about 210 barrels. Cost of disposing of this relatively small amount: about $1 per barrel. Disposal cost: $210/month.
Depending upon any change in the oil water ratio in the first well, or the drilling program dictated by the scope of the discovery (i.e., several pays, extent of the discovered zone, etc.) more water will be produced until a cost "crossover" is reached, whereby it is cheaper to drill a salt-water disposal well into one of many aquifers in the Basin and to pump or flow by gravity any water that has been produced by the oil into such water-disposal well. Driving this decision is the rate at which the water in the formation increases as the well matures. In the example above, the $210/month can go to $420/month if the oil water ratio in the discovery well goes to 80/20, or if a delineation well or development well exhibits the same 90/10 oil water ratio.
An indispensable strategy we use after making a discovery (remember that our "track record" of discovery wells in the Basin hovers at about 50% thus far, over a two-year span) is to then drill a "delineation well" in an attempt to ascertain the extent of the discovered reservoir. The risk level of this activity is termed: "delineation risk" and it makes sense that wells of this type are more often successful than initial test wells. They are however more risky than a "development well" that is drilled smack in the middle of two wells that produce from that same continuous formation.
While delineating a new field, inevitably a dry hole will be drilled when the limit of the reservoir is exceeded. It is usually at this time that the producer elects to convert that "dry hole" into a salt-water disposal well, because he has already paid the price of drilling and logging the borehole.
Assuming a Wilcox oil well has a producing life of twenty years and that water disposal to some extent is necessary over 90% of the life of such well, and the water ratio changes with time from (e.g.) ten percent to 95%, then an average of water production over that time is 38 BWPD, or an average disposal cost by truck of $1,200 per month, per well. If there are two wells, that cost is double. It is triple for three wells, and so on. Most of the fields we participate in are at least two well fields and therefore it is inevitable that a salt-water disposal well becomes economically justifiable at their approximate cost of $180K to drill and complete. Remember that in most instances, the borehole of such well had an oil reservoir exploratory or delineation purpose to begin with.
Assuming the usual incremental cost of completing a salt water disposal well (a cased & perforated exploratory or delineation borehole) is $100K. Assume further that the well should recover its capital cost in 36 months and serve 2.5 wells (a statistical midpoint) with 20-year averaged water production per well of 35 BWPD. Add to that a monthly operating expense of $250 for the well. The disposal cost in this iteration is about $1.15 per barrel for the first three years, but drops to about 10 cents per barrel after that for the remaining life of the production.