Oil & Gas

Background

The abundance of shale formations in the United States has completely changed our country’s domestic oil and gas production outlook over the past few years.  Much of the nation’s untapped reserves can only be effectively produced using hydraulic fracturing or other unconventional completion methods.  These techniques require massive volumes of water – on average, a typical frac uses 3 to 5 million gallons of water. However, because the industry currently relies upon costly outside laboratories and complicated and error-prone field kits, it does not have an effective means to quickly, reliably, and accurately test hydrochemistry in the field. Therefore, operators and service companies are unable to accurately screen and compensate for numerous interferences from various contaminants in the water and the formation itself. Additionally, because of the large volumes of water being used and the need to reduce the use of fresh waters, the industry is under extreme pressure to reuse/recycle the water from frac-to‐frac. Today, companies need to make real time decisions, on site, about whether it is more cost‐effective to treat and reuse the water or dispose of it.

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Likewise, during the drilling process, a fluid’s effectiveness must be adequately monitored (e.g., to maintain wellbore stability or prevent formation damage), as various constituents in the formation can interfere with or alter a fluid’s performance. Current methods only allow for testing a few times each day, despite the fact that drilling activities are ongoing virtually 24/7. Additionally, for some parameters, a good field test does not even exist.  Water Lens’ technology changes all that.

Hydraulic Fracturing Issues

While sand and water comprise 98%‐99% of fracturing fluids, the remaining portion involves complex chemistry and a wide array of additives. There are two major issues related to the chemical/water interaction:

1. Sub-Optimal Production – A tremendous amount of time and effort goes into planning and designing the stimulation of a well through hydraulic fracturing.  However, waters change on their own over a short period of time and also due to mixing of waters from different sources (a practice that is becoming more widespread with each passing day). Additionally, once the fracturing process begins on site, there is currently no way to monitor, in real time, the interaction of the stimulation chemicals with the minerals naturally present in the water and the formation; thus leading to increased costs, reduced production, and lower reservoir recovery. Furthermore, under the current testing methods, a tremendous amount of money is being wasted on logistics, labor, and excessive use of chemicals and additives because the water chemistry cannot be reliably tested in a timely manner at the well site. Having the right frac recipe for a given water is crucial to the optimal production of oil and gas, as is having the right drilling fluid chemistry.  The best and most cost-effective place to determine water or fluid quality is on site because the water supply (and quality itself) is no longer constant. Without knowing the correct chemistry, it is impossible to determine the correct amount of chemicals needed for a frac job. Additionally, the effectiveness of the chemicals that are used (such as friction reducers, biocides, and anti-scaling agents) are severely reduced (if not rendered ineffective), which wastes hundreds of thousands of dollars per frac. Additionally, one of the greatest risks associated with incorrect water chemistry is that ions can precipitate out and create massive amounts of scale.  This scale not only begins to close off the wellbore, but more importantly clogs the pores of the formation restricting and stopping the flow of oil and gas.  As a result, hundreds of thousands of dollars are spent trying to treat the well to remove this scale, but in many cases the affected sections/stages are lost forever.  In severe cases, the entire well can be lost, resulting in $5-$10 million in costs and forgoing much more in lost production.

Now that an entire industry of water management (sourcing, transporting, treating, and reuse) is booming, there is an urgent need to test and monitor the quality of the water being managed, as the various constituents in that water can have dramatic effects on the stimulation process.  

2. Environmental Impact – Environmental and regulatory pressures have resulted in the need for constant monitoring of water, from flowback and produced water to water that has been treated and is ready for disposal or reuse. Furthermore, the EPA and the Department of the Interior have recently issued regulations surrounding hydraulic fracturing and produced water management.  Most states involved in hydraulic fracturing are also considering (or have passed) regulations of their own. It is widely understood that increased testing and monitoring will be mandated in the very near future. Furthermore, the ability to quickly and accurately test on site facilitates cost‐effective recycling of flowback and produced water.

Versatile Tool for the Oil Field

Water Lens’ wide range of fast and easy-to-use analyte testing capabilities makes it an extremely useful tool in the field.  Frac chemistry, scaling, bacteria growth, buffering, and corrosion are universal challenges.

Crosslinkers:  (Boron, Titanium, Zirconium)

Boric acid is extensively used for the cross-linking of guar and its derivatives for the delivery of proppants to the fractures.  Given the imperative for precision of the rates of the reactions, excess boron can interfere with the timing of cross-linking reactions directly or indirectly through undesired buffering conditions.  

Scaling, Friction Reducers & Bacteria:  (Calcium, Magnesium, Barium, Sulfate, Strontium, & Carbonate)

By using Water Lens, a user can detect scale-causing species in real time, while there is still time to react.  This knowledge allows the user to treat accordingly and not overspend on scale-control chemicals.  Furthermore, detecting scale-causing species in real time will help prevent precipitation (and the resulting scale) over time during the life of the well; thus increasing overall production.

Friction reducers are used as carrier agents for hydraulic fracturing and are sensitive to the ionic environment of the water in which they are deployed.  To achieve the maximum benefit, with the minimum amount of added chemical, real-time knowledge of the ionic species present in the water allows operators to mitigate the presence of species that decrease the effectiveness of the friction reducers.  For slick water fracturing to be effective, the polymeric agents must form long, linear chains.  Any chemical agent that promotes coiling or self-aggregations necessitates the use of additives to counteract these effects.  Water Lens enables users to compensate for this in real time by providing lab-quality results in minutes.

Bacteria buildup is partially caused by the presence of sulfate, which serves as a key metabolic requirement for sulfate reducing bacteria.  Toxic hydrogen sulfide and methyl sulfides are produced as a result.  At high concentration, sulfate can also interfere with cross-linking and the proper buffering of these materials. 

Buffering:  (Ammonium, Carbonate, Acetates/Formates, Alkalinity, & pH)

Given the complexity of the chemistry and the geological variability that exists in shale plays, a lot can go wrong during stimulation.  No matter where the frac job is located, fluid performance always depends on pH.  For example, determining the buffer capacity (and species contributing) will help prevent snowing a frac tank.  Additionally, a frac can break into salt formations, a real-time event that can be captured immediately after it happens by analyzing the flowback waters.  Small changes in salt content can lead to large changes in treatment chemical stability, which could lead to formation damage by decreasing the permeability; thus, reducing the ROI of the well.  Knowing this information in real-time enables the user to immediately adjust the chemistry for the next well or stage.

Corrosion:  (Iron (II), Iron (III), Total Iron, Sulfide, Iodide)

The presence of iron (III) indicates corrosion from pipes and serves to catalyze decomposing processes for fracturing fluids.  In acidizing, the presence of iron (III) may indicate excessive corrosion from improper acid buffering.  Iron (II) can also contribute to scaling, when it combines with sulfide, and also oxidizes to iron (III) during ozone treatment, which reduces the effectiveness of the treatment.  Excessive scaling may also permanently damage a valuable formation, in addition to decreasing the flow within the tubular pipes used for transporting hydrocarbons or treatment fluids.  Thus, the concentration of total iron as well as speciation of iron (III) and iron (II) is vital data that drives a number of decision points.

Iodide is used as an inhibitor in conjunction with organic buffering acids to prevent corrosion.  Proper quantification of iodide is required for reusing acidizing fluids.  Iodide in high concentration can also interfere with metabolic processes such that measuring its concentration is vital for proper disposal.

In addition to causing scale formation in the presence of iron (II), sulfide in its various protonation states can be oxidized into sulfate during oxidative treatment of a well. This produces sulfuric acid as a byproduct, decreasing the pH of the fluid and potentially leading to strong corrosion if the pH is not buffered effectively.