Reusing Produced Water with 100,000 mg/L of Chloride as a Base Fluid for Fracturing
By Mark Stanley, President, RecyClean Services and Rajendra Ghimire, Ph.D. Technical Officer, PFP Technology
Hydraulic fracturing and horizontal drilling have not only galvanized the US energy industry but have also raised lots of scientific, environmental and public concerns. Water, a natural resource, is not only the basis of life, but also a key resource for industrial applications, agriculture, recreation, etc. But, this natural resource is in high demand as the need for water is constantly increasing due to population growth, lack of pure drinking water, industrial need/uses, oil and gas market need/demand.
During the hydraulic fracturing process, six to eight barrels of water are consumed for every barrel of oil produced. In a fracturing operation a typical well may require, half a million to 6 million gallons of water, or more. Most of the water used in fracturing comes from ground water or from fresh water. There are other sources such as brackish water, industrial waste, municipal waste etc. which can be used after treatment. 40 – 75% of this water is returned back to the surface from the formation during the production stage. This returned water falls into the category of produced water which is further classified as, flow back or frac water, and, formation water.
On average, in the United States alone, 21 billion barrels of produced water is generated per year, or 58 million barrels per day. The quality of the produced water varies from well to well. In general, the quality/characteristics of the produced water depends upon:
a) Type of hydrocarbon produced
b) Shale/rock formations where the wells are located
c) Method of production used (including formulations of fracturing fluids used)
Since the produced water contains various impurities, such as suspended solids, total dissolved solids, microbial contents, oil and grease, residual polymers, surfactants, biocides, corrosion inhibitors, hydrogen sulfide etc., the generated produced water is/was mostly disposed of at deep well injection facilities. This water management practice creates a negative water balance which may not bring about an effect immediately where there is enough ground water/fresh water available. But in a certain regions, such as Permian Basin in west Texas where fresh water is limited and drought is frequent, a sustainable water management approach is necessary. So, alternative sources of fresh water such as industrial waste, municipal waste and brackish water are also used for fracturing operations. In the Midland-Odessa region where water reservoirs are 95 % empty, operators are forced to be creative and are finding new water sources for fracturing. Initially, operators were blending fresh water with brackish water due to the salinity concern, but now, more and more operators are pushing towards 100% brackish water. The fracturing operation only consumes 1 % of the total water usage in Texas, but the continuous growth of drilling operations has increased the water demand so that more and more operators are moving towards using 100 % brackish water. Besides brackish water, operators are also utilizing municipal waste water and paper industry waste water for fracturing. Also, the trend of reusing produced water, industrial waste water and municipal waste after treatment for fracturing operations is becoming the new normal. This is becoming possible due to cost-effective innovative treatment technology, better understanding of the produced water quality, and the advancement in fracturing chemicals that are compatible with the produced water and reservoir formations.
So what does make a good fracturing fluid?
A: Water Quality
B: Fluid Compatibility
One of the characteristics of produced water is, it contains high amount of dissolved salts. But, due to the high salinity (higher concentration of dissolved solids also known as Total Dissolved Solids (TDS), operators and pumping services were reluctant to use the produced water.
Their major concerns were that high TDS levels would impact the fluid compatibility (hydration, linear and cross-linking gel viscosity), with stimulation fluids and mess up their formation (hygiene of their well), their initial production (IP) and that their Estimated Ultimate Recovery (EUR) from the formation would be lower. There were serious concerns about their asset – its overall management, such as valuation and deterioration due to high salinity water. It is safe to say the operators and pumping services (service companies) didn’t have enough information as to how the salinity would affect the formation, production, equipment etc. So, the industry thought that the best way to reuse produced water was desalination (RO, evaporation, crystallization, ion-exchange etc.). The cost benefit analysis of disposing produced water (storing, transporting/trucking/piping produced water, disposal fee, cost of fresh water, transportation of fresh water, storage of fresh water) vs recycling/reusing produced water by removing TDS was not favorable. Also, the produced water, considered a hazardous waste, created logistic and regulatory hassles pertaining to potential spills and storing it – further adding to the cost for reusing it.
But the demand for water keeps rising, and the lack of availability of fresh water, environmental concerns over disposal, transportation costs and managing the continuously generated produced water is forcing operators to take a closer look at what happens when high TDS water is used as a base fracturing fluid.
Does TDS really have a major impact?
What other impurities present in the produced water will have an adverse effect on gel hydration, cross-linking, breaking, hygiene of the formation, production capabilities and the assets? The major impurities identified (regardless of shale formation, geology or geography) in the produced and flow back water are:
1. Total Dissolved Solids (TDS)
2. Suspended Solids (SS)
3. Hardness (includes multivalent salts such as Ca, Mg, Ba, Sr, etc.)
5. Bacteria: Sulfate Reducing Bacteria (SRB) and Acid Producing Bacteria (APB)
6. Total Oil and Grease
8. Dissolve Gases (H2S, CO2 etc.)
Most of the general water treatment processes and technologies can address numbers 2-8 in some way. Let’s remember, water treatment is a very vague term. Some people consider water treatment just as simple filtration/separation; some consider water treatment as just doing a disinfectant (reducing/removing bacteria). There are certain treatment processes that do a better job to address these impurities than others. But regardless, any treatment that reduces TDS and Boron is expensive. So, operators started to address impurities 2-8. In the case of boron, studies showed that the presence of boron hinders the boron cross-linkers ability to form a cross-linked gel. The effective removal of boron is expensive as either ion-exchange or reverse osmosis is needed to reduce/remove boron levels higher than 20 mg/L. So, produced water containing boron is often not re-used for fracing activities and today is mostly disposed of in disposal wells due to the economics of water treatment. That said, alternative uses of this treated water may be readily found upon examination of local water requirements. This could include makeup water for water-based drilling muds, dust suppressants for local lease roads, or blending stock for future fracing activities. Recent publications and communications generated by the big service providers such as Halliburton, Weatherford, Schlumberger, Baker Hughes etc. indicated that TDS have very little impact on gel viscosity and frac chemistry. Most fracturing fluid systems use guar, and in comparison to fresh water/deionized water vs salt water, the salt water gel showed similar higher viscosity in similar loadings. Also, there was little impact at the reservoir formation or in production, including equipment. Given that TDS appears to have generally minimal impact on frac chemistry, the impact of suspended solids, bacteria, residual organics (residual guar, polymers etc.) hydrogen sulfide, iron and hardness appears to be critical for the reuse of produced/flow back water. Let’s look at a closer look at these impurities.
2. Suspended Solids (SS): The size of SS vary (in general 1< micron to 100). These varying size solids can block the shale pores, causing scaling and corrosion, fouling at the formation and in the equipment, impact the formation pressure, increase emulsification and impact the cross-linking viscosity and breaker time as well. So, it is very critical to remove the SS from the produced water. 3. Hardness: The higher amount of divalent and trivalent salts present in the produced water of higher pH can cause scaling issues. Besides scaling issues, Ca was also found to hinder cross-linking ability. In general, hardness is considered as calcium and magnesium ions present. But other salts such as barium, strontium, etc. also add to the hardness.
4. Iron: Iron can impact hydration ability and formation of linear gel – more specifically cross-linking gel. Iron in the presence of sulfate-reducing bacteria generates iron sulfide, which causes both scaling, corrosion, slime and fouling problems.
5. Bacteria: Relates to iron. If both SRB’s and APB’s are present they can enhance the microbially-induced corrosion. It creates bio-films and fouling as well.
6. Oil and Grease: The residual hydrocarbon creates emulsification, fouling and slime at the formation and the equipment. It also hinders the hydration ability of the water which is critical to make a good linear and cross-link gel.
7. Dissolved Organics: Dissolved organics include residual guar or other base polymer used to make the high-viscosity slurries, water clarifiers, friction reducers, biocides, organic acids/buffers etc. will create a significant COD and BOD demand. They will also create problems similar to Oil and Grease.
8. Dissolved gases such as H2S and CO2: H2S is related to 4 and 5. Most importantly H2S is hazardous. CO2 contributes to the alkalinity of water and will also dictate the amount of salt that will precipitate at higher pH as most salts are carbonate salts.
9. Anions: Anions such as sulfate, phosphate, carbonates and bicarbonates contributes to the hardness, scale and corrosion problems in produced water. Most of the inorganics salts are precipitated out as carbonate or sulfate salts. Also produced water with bacteria such as SRB can enhance the scale and corrosion problem if the water contains sulfate and iron in it.
10. Boron: Most cross-linkers used to make cross-linking gel are boron based so it hinders it.
Why the Hydro-Pod?
The Hydro-Pod is the only technology that addresses 10+ impurities in one treatment in the most economical and environmentally-friendly way, by mitigating risks associated with reusing produced water. Though the Hydro-Pod is not designed to reduce TDS, both real-time operation data and test data have shown that the Hydro-Pod can reduce up to 25,000 mg/L of TDS. In addition to that, the Hydro-Pod is the only known technology that can treat boron without additional specialty treatments. The Hydro-Pod treatment will typically reduce boron at least 20%, along with other heavy metals of interest.
Most importantly, the Hydro-Pod, from RecyClean Services, addresses all the key impurities 2-10 (Suspended Solids, Hardness, Iron, Bacteria, Oil and Grease, Dissolved Organics, Dissolved gases, Anions) that are critical to remove/reduce to a level where the produced/flow back water can be used as a base fluid for fracturing.
Now, let’s look at the second component,
The second critical component for reusing produced water is the fluid compatibility. There needs to be the right combination of stimulation/fracturing reagents with the right chemistry to be compatible with the treated produced water. Most water treatment companies just do water treatment and are either unaware or uneducated about the quality of the water needed to make it compatible with the stimulation/fluid chemistry. Similarly, most stimulation chemical providers are not qualified enough to evaluate and adjust the produced water quality to fit their stimulation chemical compatibility. But PFP Industries has the products and the expertise to determine and deliver fluid compatibility.
This combination of the right treatment technology – the Hydro-Pod, with the expertise and stimulation chemicals from PFP Industries, makes almost all produced and flow back water reusable in a cost-effective manner, while still delivering high efficiency by mitigating the risks.
Dispelling the Myth
We can now say that high TDS water can indeed be used in fracturing and that it is now advantageous to not only evaluate new ideas, but to unlearn old ones that can limit productivity.
Produced water volumes and management practices in the United States
C.E.Clark & J.A.Veil – US Dept. of Energy 2009
Oil & Gas Produced Water Management and Beneficial Use in the Western United States
U.S. Department of the Interior, Bureau of Reclamation – Sept. 2011