Reusing Flowback and Produced Water with Different Salinity to Prepare Guar Fracturing Fluid

Economical and environmental concerns have forced the oil and gas industry to consider reusing flowback and produced water for fracturing operations. The major challenge is that the high-salinity of flowback water usually prevents its compatibility with several fracturing fluid additives. In this paper, the authors explored an economic and effective method to prepare guar fracturing fluids with different salinity waters. The main research idea was to use chelating agents to mask metal ions, such as calcium and magnesium, that are harmful to crosslinking. Firstly, a complexometric titration test was conducted to measure the chelating ability of three chelating agents. Secondly, through viscosity, crosslinking, and hanging tests, it was verified that the complex masking method could cope with the problem of high-valence metal ions affecting crosslinking. Thirdly, the preferred chelating agent was mixed with several other additives, including thickeners, crosslinkers, and pH regulators, to prepare the novel guar fracturing fluid. The comprehensive performances of the novel fluid system were tested such as temperature and shear resistance, friction reduction, gel-breaking performance, and core damage rate. The results show that the organophosphate chelating agent (i.e., CA-5) had the greatest ability to chelate calcium and magnesium ions. There was a good linear relationship between the dosage of CA-5 and the total molar concentration of calcium and magnesium ions in brine water. The main mechanism was that the chelating agent formed a complex with calcium and magnesium ions at a chelation ratio of 1:5. The test results of the comprehensive performance evaluation indicate that the prepared guar fracturing fluid met the requirements for field application, and the lower the salinity of the flowback water, the more it is economical and effective.

Reuse of Flowback Water from Hydraulic Fracturing for Drilling Mud Preparation and Secondary Hydrocarbon Recovery

Flowback water after completion of hydraulic fracturing is one of major waste streams generated during the lifespan of a well so its beneficial reuse is crucial. The application of treated flowback is not limited to stimulation processes but also may include drilling operations and secondary oil recovery. The flowback water used in this work is characterized by high salinity reaching up to ~295 g/L caused mainly by NaCl. The presence of suspended solids, mainly corrosion products, prompts the use of coagulation and filtration as treatment methods. Among tested coagulants the most effective one was the SAX18 (NaAlO2) commercial coagulant applied at concentration of 12 mL/L which reduces the water turbidity from over 400 FTU to 23 FTU. The applied treatment greatly reduces the concentration of scaling ions and so the concentration of SiO2 is reduced by 64%, Ba2+–66%, Fe2–36%, Mn2+–65%, SO42−–66%. The treated flowback fluid can be reused in surfactant flooding for enhanced oil recovery where achieves 7% higher displacing efficiency than fresh water. The drilling muds which were prepared using the untreated flowback water exhibit good rheological properties. The obtained results show that recycling of flowback water in future drilling and exploitation operations is technically feasible.

Analysis of Compositions of Flowback Water from Marcellus Shale Wells by Utilizing Data Mining Techniques

Volume and salt concentrations in Marcellus flowback water depend on geology, drilling and completions, stimulation and flowback operations. Recent studies include evaluations of geochemical origins based on the compostition concentrations, flowback sampling analysis and numerical studies. However, an in-depth understanding of chemical compositions as well as the changes of compositions is still needed. In this paper, we will first review the literature related to flowback water in Marcellus shale gas wells to fully understand the chemistry, geochemistry, and physics governing a fracture treatment, shut-in, and flowback. We will then gather all public and in-house flowback data, named as 3-week or 3-month flowback in this work, to build a data set of flowback water compositions. After data screening, we will then analyze this database using four different methods: geographical changes over time, linear regression, clustering and multi-variable analysis. New understandings such as the magnitude and prevailing trends of concentrations for target constituents as well as the correlations among flowback compositions, the differentiation between early and late time flowback water were obtained and explained on the basis of geochemistry and physics. This helps production companies and other stakeholders to better manage and reuse waste water for energy production.

Geochemical Characteristics of Gas and Flowback Water in Lake Facies Shale: A Case Study From the Junggar Basin, China

The chemical and isotopic compositions of the natural gas and the co-produced flowback water from the XJC 1 well in Junggar Basin, China, were analyzed to determine the origin of gases in the Permian Lucaogou Formation (P2l) and the Triassic Karamay Formation (T2k) in the Bogda Mountain periphery area of the Southern Junggar Basin. The value of carbon isotope composition of the P2l lacustrine shale gas in the Junggar Basin was between the shale gas in Chang 7 Formation of Triassic (T1y7) in the Ordos Basin and that in the Xu 5 Formation of Triassic (T3x5) in the Sichuan Basin. The difference in gas carbon isotope is primarily because the parent materials were different. A comparison between compositions in the flowback water reveals that the P2l water is of NaHCO3 type while the T2k water is of NaCl type, and the salinity of the latter is higher than the former, indicating a connection between P2l source rock and the T2k reservoir. In combination with the structural setting in the study area, the gas filling mode was proposed as follows: the gas generated from the lacustrine source rocks of the Permian Lucaogou Formation is stored in nearby lithological reservoirs from the Permian. Petroleum was also transported along the faults to the shallow layer of the Karamay Formation over long distances before it entered the Triassic reservoir.