High-Temperature Fracturing Fluids Using Produced Water with Extremely High TDS and Hardness
Authors: Li Leiming , Sun Hong , Qu Qi , Mehle Michael P. , Ault Marshall G. , Morse Aaron , Zhou Jia , Smith David D. 
Published: March 2015

Produced water often contains high levels of total dissolved solids (TDS) in addition to precipitates, suspended particles, and hydrocarbons. The main components of the dissolved solids include sodium, calcium, and magnesium salts. The combination of high salinity and hardness can be very damaging to many types of fracturing fluids that are commonly formulated with fresh water. It is usually costly to treat high-TDS produced water to such an extent that it can be safely and stably used to formulate fracturing fluids. On the other hand, fresh water for formulating fracturing fluids is becoming more costly and more difficult to obtain in many oil/gas production areas. Fluid systems have therefore been highly desirable and sought after that can be formulated directly with high-TDS hard produced water and perform well at high temperature of 275 °F or above.

A series of fracturing fluids were successfully identified recently that performed very well at high temperatures when formulated with untreated high-TDS produced water. The produced water samples tested had TDS up to about 330,000 mg/L and hardness (calcium carbonate equivalent) up to about 90,000 mg/L. The fracturing fluids comprised of organometallic-crosslinked derivatized polysaccharide. In one typical example, the viscosity stayed above 100 cP (at 100/s shear rate) for over 80 minutes at 275 °F recorded for a fracturing fluid prepared with untreated produced water with TDS of about 300,000 mg/L and hardness of about 50,000 mg/L. The magnitude and lifetime of the fluid viscosity were dependent on a number of factors such as the water TDS and hardness, test temperature, polymer loading, fluid pH, etc. The fracturing fluids also showed minimum damage to the formation or proppant pack tested. In representative proppant pack conductivity tests, the retained conductivity was about 73% at 200 °F and about 89% at 250 °F for the fracturing fluids mixed with appropriate amount of oxidative breaker.

The underlying mechanisms of the high-temperature fracturing fluids prepared with untreated extremely high-TDS and hard produced water will be discussed, and the field-related laboratory tests will be presented.

Introduction

Produced water usually refers to water that is produced along with oil/gas from hydrocarbon wells. Flowback water can be considered as a type of produced water. Flowback water usually refers to fracturing fluid that flows back through the well that may account for part of the original fracturing fluid volume. Broadly defined, produced water may refer to any unclean oilfield water (Li et al. 2010) including produced formation water, flowback water, pit water, contaminated river water, etc. Produced water often contains high levels of salinity and hardness. Produced water is often subjected to evaporation that may further increase its TDS and hardness to near saturation values. Produced water samples, especially those from shale formations such as Marcellus and Bakken, have high TDS and divalent cation contents (Zhou et al. 2013). When measured by volume, produced water is the largest waste generated during the production of hydrocarbons (Stephenson 1992).