The fouling behavior of water streams in steam-assisted gravity drainage (SAGD) operations can be affected by chemical selection, including a reverse emulsion breaker, demulsifier, flocculant, and dispersant. Reverse emulsion breakers and demulsifiers were chosen to give the cleanest water quality and best dehydration during laboratory testing of reverse emulsions produced at SAGD facilities. A group of polyquaternary amine reverse emulsion breakers were synthesized to have a range of molecular weights with equivalent charge densities. The effect of their molecular weights on water clarification was investigated by standard bottle testing. It was found that the higher the molecular weight, the more effective the chemical was at removing suspected fouling agents. A flocculant has to be used with care to avoid overtreatment of the system. If fouling occurs during normal operation due to produced water from the primary separation vessel containing residual amounts of oil or other impurities, remediation can be used to address the fouling. A series of dispersants were tested to check if the oil could be kinetically stabilized in the produced water phase. It was shown that decreased viscosity of the oil increased the tendency for the oil to be dispersed. Certain surfactants helped the oil to be dispersed into the water and then to be released upon settling for 30 min. This type of dispersant could be applied in any SAGD operation with heat exchanger fouling problems.

The standard method for water clarification in SAGD operations involved the injection of latex polymers to break produced reverse emulsions. Operationally, this resulted in large quantities of oil in the water downstream of the first oil and water separation vessel. Problems occurred because this generated large amounts of oily solids and emulsion. This slop material represented a significant additional expenditure. Champion developed a novel approach to treat these systems and reduce slop. This program has been very successful in removing oil from the water stream during primary separation, thus reducing costs associated with reprocessing slop oil, and resulting in greater oil recovery.

For an extended period of time water-quality problem was experienced from the water leg of the primary treater, so-called high-temperature separator (HTS), which resulted in limited water-disposal in a SAGD facility near Fort McMurray, Alberta. A reverse emulsion breaker was recommended based on bottle testing data and a chemical application program was developed to clarify the produced water and to remove this major bottleneck of the system operation. Bottle testing a wide range of reverse emulsion breakers with the fresh reverse emulsion from this SAGD facility resulted in two products that were plant tested at various locations in the plant and correlated with the chemical performance. During lab testing the quality of the water resolved from the reverse emulsion was determined both qualitatively (visual observation with a ranking card) and quantitatively (with a turbidity meter) for a range of chemicals, chemical dosages and agitation levels. The method of chemical application has also proven to be as important as chemical itself. Chemical injection directly upstream of the HTS did not perform well, but moving it farther upstream from the HTS produced clean water within several hours from the commencement of the plant test. The percentage of water recycled from the produced water tank into steam generation was increased from 20% to 80%, thus not only removing the bottleneck but also presenting huge savings to the facility. It was demonstrated that working together with the SAGD operation staff to modify the chemical program would give mutual benefits to both parties involved. Introduction Oil sands deposits are deposits of sand saturated with bitumen and water, which are commonly found at or near the earth's surface. About 98% of all oil sands are found in seven large deposits, and the Athabasca deposit in Western Canada is the largest, containing an estimated 137 billion m3 of oil1. The Athabasca deposits are strip-mined if they are near the surface, and in-situ recovery processes are being developed for deposits too deep for economic surface mining. The in-situ recovery processes may include cyclic steam stimulation (CSS), steam assisted gravity drainage (SAGD), steam and gas push (SAP), and vapor extraction (VAPEX). Among these in-situ recovery methods SAGD is now considered commercially proven and the leading process to recover bitumen that is not available for surface mining. The SAGD process can recover over 60% of the oil in place. Several oil companies have active or proposed commercial projects using SAGD technology for bitumen recovery, and some producers are also proposing to integrate the SAGD and upgrading technology at their field sites to produce high-quality synthetic crude oil2. The SAGD operations require two parallel horizontal wells that are ca. 5 m apart in height. Steam is injected continuously into the top well, creating a steam chamber that grows as the steam condenses on the chamber walls and ceiling and releases heat. Heated bitumen and condensed steam drain by gravity into the lower production well and then are pumped out. The steam quality is usually higher than 80% because the sensible heat of the condensate is not utilized for bitumen mobilization. The average economic limit steam-oil-ratio is about four, independent of reservoir permeability3. The oil-in-water emulsion, or so-called reverse emulsion, is produced in all SAGD operations. Despite the variations of the treating systems, chemicals are always required to resolve this reverse emulsion, i.e., to give dry oil that meets the pipeline specifications and preferably oil-free water that could be recycled to the steam regenerator or pumped to disposal wells. It is important to have a good understanding of the functions of each chemical type used in breaking reverse emulsions so that the best chemical program can put in place4.