Well Treatment Fluids Prepared with Oilfield Produced Water

Abstract

Oilfield produced water usually comprises both the formation water and injected fluids from prior treatments. Produced water may be environmentally hazardous and usually contains bacteria, hydrocarbons, and high levels of dissolved salts. As such, the proper disposal of produced water is often expensive. Meanwhile, fresh water used to formulate oilfield treatment fluids is becoming more costly and more difficult to obtain. Operators, as well as service companies, have therefore shown a strong desire to use produced water in field operations to reduce costs. Consequently, a series of laboratory experiments have been performed to optimize the viscosity profile of fracturing fluids prepared with produced water. Preparation of polysaccharide-based fracturing fluids with produced water frequently resulted in fluids with poor viscosity profiles despite the fact that the produced water was pretreated with biocide. Furthermore, the problem could not be resolved by just adding more biocide. In a number of representative cases, the guar-based fracturing fluids, prepared with produced water and regular biocide, quickly lost their viscosity after hydration, possibly because of the degradation of the guar by the bacterial enzymes in the produced water. A new fluid stabilizer was recently invented to address the problem, and it was observed that the addition of the stabilizer dramatically extended the lifetime of the polysaccharide-based fracturing fluids prepared with produced water. The fluid stabilizer was simply added to produced water prior to mixing the polymer. The polysaccharide-based fluids prepared with the stabilizer-treated produced water showed stable viscosity profiles at both surface and bottomhole temperatures. The use of the fluid stabilizer has greatly enhanced the fluid performance and job efficiency since its initial introduction in the field in June 2008 and was implemented in about 80 successful fracturing and sand control jobs by the end of 2008. The invention and successful application of the fluid stabilizer have reduced the operating costs for the operators and service companies. At the same time, this new technology has also helped improve the environment by cutting the fresh water usage in the field. This paper will discuss the chemistry, experimental studies, and case histories. Background Oilfield produced water is a term used in the oil industry to describe the water that is produced along with the oil and/or gas, and it may contain formation water, flowback fluids, surface water, and water from any other sources. Produced water is in good contact with various environmental elements such as air, soil, formation, and contaminated water tanks, and it is therefore not surprising that produced water often contains high level of bacteria and/or bacterial enzymes as bacteria are ubiquitous in almost every habitat on Earth. Formation water usually consists of salty water that may be the ancient seawater trapped in the formation. On the other hand, produced water stored in tanks or ponds is often subjected to evaporation that can further increase the salt concentration in the water. Measured by volume, produced water is the largest waste generated during the production process, and the volume of produced water can be several times that of hydrocarbons produced (Stephenson, 1992). The potential benefit of using such produced water, if feasible, for oilfield operations is at least twofold. First, the cost related to the proper disposal of produced water can be reduced. Produced water usually contains high levels of salt and hardness as well as bacteria. Without proper treatment, produced water is environmentally hazardous. It can be, however, costly to clean up produced water following the local, state, or federal regulations. If produced water can be treated in situ and then used to prepare fracturing fluids, the operating cost is expected to decrease. Second, as large amount of fresh water is used for oilfield operations such as water flooding, subterranean fracturing, etc. (Gleick, 1994), reusing produced water can cut the consumption of fresh water that is becoming more costly and more difficult to obtain since neighboring residents and municipal and state governments are putting more restrictions on water availability from either surface or subsurface aquifers. Operators, as well as service companies, are therefore interested in using produced water to reduce operating costs and gain competitive edges.

Well Treatment Fluids Prepared With Oilfield Produced Water: Part II

“…All of the wells were completed in multistage fracturing treatments (21 fracturing jobs in total) using the borate-crosslinked guar fracturing fluid. Average perforation depth was 1740 to 1950 m (5,700 to 6,400 ft) (TVD) and 1800 to 2100 m (5,900 to 6,900 ft) (MD), with the bottomhole temperature of 88 to 99°C (190 to 210°F), again significantly higher than the bottomhole temperature of about 54°C (130°F) where the fluid stabilizer-protected guar fluid was initially used in Bakersfield, California (Li et al 2009). Average fracturing treatment size was 50 000 to 73 000 kg (110,000 to 160,000 lb) of 16/30 proppant per stage.…”

“…The low-quality water often contains high levels of salinity and/or hardness as well as bacteria since the water can come from any sources and can be in contact with various environmental elements (Li et al 2009). Even with the addition of frequently used biocides from the family of glutaraldehyde, 2,2-dibromo-3-nitrilopropionamide (DBNPA), tetrakishydroxymethyl phosphonium sulfate (THPS), or quaternary ammonium compounds (QACs) (Paulus 2005), it is still a challenge to prepare a stable polysaccharide-based fracturing fluid using this water.…”

“…In 2008, we successfully implemented a fluid stabilizer in oilfield to protect the polysaccharide fluid from damage by bacterial enzymes in produced water (Li et al 2009). Several inorganic or organometallic compounds of a transition metal, used individually or in combination, acted as the fluid stabilizer.…”

“…The fluid stabilizer not only mitigated the damaging effect of the bacterial enzymes in produced water, thus protecting the polysaccharide molecules, but also denatured other sources of enzymes, such as those in common oilfield enzyme breakers that might remain in flowback water (Li et al 2009). Operationally, it was simple to apply the fluid stabilizer by just adding it into the produced water prior to polymer hydration.…”

“…In 2008 alone, the fluid stabilizer greatly enhanced the fluid performance and job efficiency in about 80 fracturing and sand control treatments in Bakersfield, California. In these jobs, the produced water was treated with the fluid stabilizer at a dose of about 70 to 270 ppm before it was used to prepare the borate-crosslinked guar fluid with a typical guar loading of 0.3% for the bottomhole temperature of about 54°C (130°F) (Li et al 2009). …”