The salt water disposal well has long been thought of as the backbone for produced water management. Recently, the explosion of the unconventional oil and gas development has greatly increased the number of wells used for managing produced water. The misconception is most of the produced water is managed in a disposal well.
In general, there are two types of wells for management of produced water: injection wells and disposal wells. Injection wells are typically used for enhancing oil production. This type of injection is also referred to as enhanced oil recovery. EOR techniques include steam injection, water or waterfloods, and gas injection. Carbon dioxide is the most popular gas used in EOR and, due to the role CO2 plays in the climate change discussion, currently an area of significant interest.
Regarding the produced water world, our focus is strictly on water flooding.
Overall, there were 54,700 permitted injection and disposal wells on record in 2015. About 34,200 of these wells were active with 26,100 used for injection and only 8,100 wells for disposal. This means approximately 76 percent of wells in Texas are used for EOR and not for disposal. This ratio is consistent with the EPA national database. According to the EPA's Underground Injection Control inventory, there are 143,587 injection or EOR wells and 36,757 disposal wells, making the national average about 80 percent EOR wells.
Enhanced Oil Recovery
Oil and gas history tells us waterflood EOR became popular for produced water management in the 1930s as conventional drilling grew in Texas and Oklahoma, but there is evidence of waterflooding in Pennsylvania dating
back to 1865. Due to a lack of available records, it is unclear whether early waterfloods used surface waters or produced water.
When we talk about produced water management, it is hard to ignore the impact of EOR injection wells. EOR has been claimed to increase production by as much as 30 to 60 percent. Chevron, on their website, stated that EOR has taken normal production decline rates from 14 percent to below 2 percent. When the economic impacts of EOR or waterflooding are considered, it becomes clear why this option is so popular. And, if the ratio
of wells favors EOR injection, it can be assumed most produced water is managed this way as well.
The American Petroleum Institute conducted surveys in 1985 and 1995 and the results showed 62 percent of produced water was injected for EOR and 30 percent was disposed of. The 1995 API survey showed an increase in EOR up to 71 percent with 21 percent for disposal. A separate survey conducted in 2007 showed EOR at 59 percent and disposal at 39 percent. From this data, it appears the average EOR well is smaller that the average disposal well since the percent of produced water managed on a well basis is below the ratios discussed earlier. Another observation is that EOR is shrinking slightly, but this makes sense.
Most new operators do not have the producing well inventory to justify the use of EOR. As the well inventory grows, operators should begin planning an enhanced oil recovery program.
From the rapid growth in unconventional oil and gas wells, both in terms of number of wells and number of operators, we can expect to see the ratio of disposal wells to injection wells swing to more new disposal wells.
I do not expect to see a trend where EOR injection continues to decline but eventually, as operators develop their fields, most will transition from disposal to injection wells. Why would we assume this? The economic benefits of stable or increased production from existing wells are hard to ignore. With their focus on production, operators will look at EOR as early as practical.
Why is this distinction between EOR injection and disposal wells so important? Many market studies tend to lump disposal into a single category when there are really two types of wells. Also, it is important to answer the question: is EOR recycling?
An alternative to produced water is to use surface water, steam or gas for EOR. I really believe EOR for produced water is recycling.
Significant efforts have been made to find a beneficial reuse for large volumes of waste products from other industries. For example, coal ash from power generation has been blended into construction products and called recycling. If that is a legitimate recycling option, why is it not to use produced water to enhance oil production?
There is a strong case to be made for EOR as recycling. This would provide an incentive to track EOR and disposal as two separate activities from a market perspective. From a permitting perspective, injection and disposal are already treated as two different activities and two different types of permits. There are other reasons to treat them separately as well.
As noted above, waterflooding in the oilpatch took off in the 1930s, but this also coincided with other practices that led regulators to take a serious look at how to protect water resources. In 1948, the federal government enacted the Water Pollution Protection Act which was reorganized and expanded in 1972 to become the Clean Water Act. After that came the Safe Drinking Water Act in 1974 and it was under SDWA that Underground Injection Control regulations were developed. UIC regulates disposal and injection wells and includes well construction standards, inspections and reporting requirements.
Under the Clean Water Act, discharge standards were created for various types of discharges and industries. For example, in 1974 effluent standards were written for discharges from offshore platforms, primarily aimed at oil and grease.
The regulatory process that has been repeatedly developed and enacted in the years since likely means these changes will continue down a regular path. Already, the EPA has started a new study of produced water. In 2018, EPA held public meetings and wrote updates. According to news reports, EPA is expected to issue a final report later this year.
It is about time our industry became proactive and developed our own standards before a government agency does it for us.
Already, standards for reuse of produced water as a completion fluid are starting to converge. That means the standards that operators are writing for their own use are becoming more similar. I see the various operator standards converging on zero hydrogen sulfide, iron under 5 ppm, and bacteria under 100 CFU/mL. In general, other operator standards vary by component, but these three are consistent.
The problem comes when we consider disposal and injection standards mostly because there are not any, unlike for recycling and reuse of produced water as a completion fluid. For salt water disposal wells, many operators do little but collect oil from the stream while other operators worry about injectivity and the life of their disposal well. This means sometimes there are no standards and sometimes there are.
Many EOR injection well operators rely on specific water quality standards, but these are not necessarily the same as for disposal wells. For some disposal well operators, the goal is protection of surface equipment and gathering systems. They look to prevent plugging, fouling, corrosion and generation of H2S, but then ignore downhole considerations or injectivity.
When considering fluids used in hydraulic fracturing, we pay attention to formation damage. As a result, our focus is on total suspended solids, iron, bacteria, H2S, and scaling. Fortunately, with the use of blends and scale inhibitors, scaling has become less of an issue.
For both disposal and injection wells, we think of TSS, iron, bacteria, H2S and scaling as equally important, but we should add oil to the mix.
Suspended solids are probably the easiest component to manage, but parts per million standards alone do not tell the whole story. We need to look at size distribution and particle size. A good rule of thumb says suspended particles should be one-third the pore opening. Fines migration and swelling should also be considered, but because produced water acts as a natural clay stabilizer, I do not expect this to be much of an issue.
Iron causes formation damage and can act as a coagulant. Even with suspended solids smaller than the pore opening, they will stick together and bridge which can lead to plugging. Bacteria can also cause fouling and plugging. Then there is scaling and compatibility. Injected fluid can react with existing fluid in the reservoir and precipitate solids and cause damage. Finally, oil in the fluid can cause damage. Unfortunately, these parameters are rarely addressed with any accuracy at most SWDs.
Given all this, how do we manage these issues and develop a standard? The injectivity/core flow study.
Injectivity/Core Flow Study
Although this seems straightforward, many of the conditions being evaluated in an injectivity/core flow study can change. Several tests may be needed to define the range of performance required. Some studies recommend TSS standards as low as 3-5ppm while others recommend 50 ppm. One study conducted in Prudhoe Bay showed TSS levels as high as 2,000 ppm with no impact to injectivity. This was attributed to fractures in Prudhoe Bay.
The key is to look at sensitivity to all the factors mentioned, specific to each core sample, and determine how TSS, bacteria, iron, oil and the total dissolved solids compatibility effect injectivity. Once data points are recorded, graph the results to determine sensitivities and look for the water treatment program that has the greatest effect on injectivity. Remember to consider “good enough,” and keep a cost perspective in the mix.
Every regulatory change has a trigger event, something that drew enough attention to cause the government to step in and draw-up regulations. For our industry, induced seismicity is the trigger event and the concerns of the public seem to justify it. Many operators have taken notice and are looking to reduce dependence on SWDs.
The Texas Railroad Commission has already announced it is making changes to the parts of its UIC program that covers SWDs. We hear reports of SWD operators taking steps to improve injectivity by lowering surface pressure, which means reduced impact to seismicity. I believe injectivity can be considered a solution to seismicity. In other words, there is a correlation between water quality and injectivity, and injectivity and seismicity.
As an industry, we must look at EOR injection and SWD disposal as separate activities. Developing water quality standards will be different for each of these activities. Also, we need to consider which standards are most important and which can be considered as guidelines. Consistent operating standards can improve injectivity and extend the life of an injection or disposal well.
Better injectivity lowers surface pressure which means more volume downhole and better well economics. More importantly, if the industry does not develop standards that make sense, we may be forced into standards we don’t like.
Authored by Mark Patton
Mark Patton is president of Hydrozonix. He has more than 25 years’ experience in the development, design, implementation and operation of treatment technologies. Mr. Patton’s oil and gas background includes treatment systems for waters, wastewaters, drilling muds, tank bottoms and process residuals. He holds one produced-water patent with two additional patents pending.
Mr. Patton earned his B.S. in chemical engineering from the University of Southern California in 1985.