Water Flooding: Just Add Water?
Flooding an oil field with extraneous water has been a widely accepted method for increasing a reservoir's recovery since the 1950's, but to the uninitiated it may seem odd. After all, water production is a bad thing; it increases lifting costs, puts more strain on equipment, and may even prevent flowing wells from flowing. Plus, the produced water must be dealt with in an environmentally sound way, which also adds to the operating costs.
So why add water? For two reasons: First, injecting anything into a reservoir will increase the reservoir pressure, and second, water and oil don't mix. This second reason may again seem odd, but because they don't mix water, under higher pressure, will displace the oil it contacts.
So what does this mean? First we need to understand that most oil reservoirs are solution gas drive reservoirs*. This means as the oil is produced the reservoir's pressure is reduced and the gas that was held in solution begins to breakout and expand, thus "driving" the oil towards the producing wells. This is a familiar process we see when opening a bottle of soda (Mentos added for emphasis).
The problem with a solution gas drive reservoir is when the gas breaks out of solution it is free to flow to the producing well and be produced, and once the gas is produced the reservoir's energy is lost. Typically a solution gas drive reservoir will only recover 5-20% of the reservoir's original volume of oil leaving a large portion behind.
By injecting water in a controlled manner, the loss of reservoir pressure can be controlled and reversed. Water is injected into dedicated injection wells strategically located throughout the reservoir, and the water itself can be used to displace the remaining oil towards the producing wells. If properly designed and operated, a water flood can double the reservoir's oil recovery.
Even with double the recovery (10-40%), we are leaving large volumes of oil behind in these solution gas drive reservoirs, and with the ever-growing oil-thirsty economies around the world we need to do better. This is where enhanced oil recovery (EOR) techniques come to play, but that discussion is for another day.
This all sounds great and water flooding has been used successfully for decades, however, it is important to take care to design and operate the flood appropriately, otherwise all the bad things we mentioned at the beginning may be all you get. There are may factors to consider when designing a successful water flood including:
- reservoir permeability (both absolute and relative)
- beginning and ending fluid saturations (oil, water and gas)
- reservoir heterogeneity
- oil gravity and viscosity
- water source and compatibility
- formation clay content
- depth and lifting costs
But if done right, a well run water flood will significantly improve oil recovery and produce attractive returns for many years.
*Most of the oil reservoirs considered for water flooding are solution gas drive; of course there are a great many oil reservoirs around the world that are not, but they are not the subject of this discussion.
Question:
1 Can the water produced from a solution gas drive reservoir be used to carry out a waterflooding operation
Good question. I think you are asking whether the water produced from a reservoir can be used to flood the same reservoir it was produced from. The answer is yes, and it is done all the time, but you will need additional water from a compatible outside source as well.
In a waterflood we are trying to "re-pressure" the reservoir and if we have produced some volume of oil, gas, and water, we will have to reinject more than just the produced water to achieve this. The concept is called "fill up" and the volume of water required to "fill up" the reservoir is equal to the volume of gas in the reservoir at the start of the flood. Before we can increase the pressure in the reservoir we have to get rid of the gas in the formation because gas is so much more compressible than oil and water.
Another way of approximating the volume of water necessary for "fill up" is to assume you will need to inject a volume of water equal to the volume of oil plus water that has been produced from the reservoir.
Mike
if i have more than 100 water flooding project and we want to evaluate these project in terms of the max. recovery from each project
what is the most adequate method to evaluate these projects?
Well, that's a challenging proposition. I guess it would depend on the maturity of the floods. Obviously the most appropriate methodology would be to evaluate each flood separately on its own merits; however, given the large number of floods you are tasked with evaluating this may not be practical.
If the floods are fairly mature I would recommend plotting each flood's producing water cut versus its cumulative oil production, and extrapolating the trend to an economic limit. The economic limit would depend on the lifting costs and water disposal costs, among other economic factors, but should be something you can get an idea of pretty quickly.
If the floods are not very mature, I would recommend gathering the OOIP and cumulative primary production for each flood, then calculate the primary recovery as a percent of OOIP. If the primary recovery is within "normal" ranges for a solution gas drive, then you can make an assumption about the Primary + Secondary recovery as a percent of OOIP.
I feel I must warn you that these are only "ball park" type estimations and there are many reasons they may not be accurate, but if you need to evaluate this many floods in a short period of time it may be "close enough."
Mike
When is it recommended to go for water flood project? Secondly, will you recommend a gas reservoir to undergo water flood?
Andy
Andy,
Thanks for the question. I have discussed the benefits of waterflooding and the reservoir characteristics that make for a good waterflood candidate, but I don’t believe I have discussed the “best time” to initiate a waterflood.
Usually the initiation of a flood is controlled by when the reservoir is identified as a candidate; that is to say after the field has been on production for a while and the reservoir characteristics have become known. This is often the case because the field’s production rates have dropped and the operator is looking for a way to restore production and add reserves; however, this is not necessarily the optimum time to start a waterflood.
Theory would say the optimal time to waterflood a reservoir is when the oil in the reservoir is at its bubble point. This represents the point where the oil is at its maximum volume and the solution gas has not yet begun to emerge from the oil. Once the gas breaks out of solution the oil begins to shrink (its viscosity will start to rise) and the gas begins to increase the reservoir gas saturation which can impair the flood. That being said, many reservoirs are discovered at, or near, their bubble point and quickly fall below, making flooding at the bubble point difficult to accomplish.
To answer the second part of your question, I can’t really think of a situation when I would recommend waterflooding a gas reservoir. Gas reservoirs are most optimally produced when the reservoir pressure is reduced to the lowest point possible (maximum gas recovery). Introducing water into a gas reservoir, whether natural (water drive) or artificially, most always reduces gas recovery.
Mike