Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer-flood-pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact more than 300 ft through the Tambaredjo formation. Our results may help explain the inconsistency between good production responses and highly degraded polymer observed in many past field projects. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and, therefore, high viscosity for much of the way through the Sarah Maria polymer-flood-pilot pattern. A strong shear-thickening rheology was observed for 1,000 ppm and 1,350 ppm hydrolyzed polyacrylamide (HPAM) solutions in porous media, even though the salinity was only 500 ppm total dissolved solids (TDS). Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer-injection wells. Injectivity was insufficient until fractures were initiated hydraulically; however, the fractures propagated a distance of only approximately 20 ft and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation.The Sarah Maria Polymer-Flood Pilot Reservoir Description. Staatsolie's Sarah Maria polymer-flooding-pilot project in the Tambaredjo field (Fig. 1) currently has
Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer flood pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact over 300 ft through the Tambaredjo formation. This finding substantially reduces concerns about HPAM stability and propagation through low- and moderate-temperature reservoirs. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and therefore high viscosity for much of the way through the Sarah Maria polymer flood pilot pattern. A strong shear- thickening rheology was observed for 1000-ppm and 1350-ppm HPAM solutions in porous media, even though the salinity was only 500 ppm TDS. Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer injection wells. Analysis suggested that the fractures extended only a short distance (~20 ft) from the injection wells and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation.
Chemical EOR is starting to pick-up in the industry in the last 10 years due to the high oil cost and lower chemical costs. Preparing the solution for injection is the well established part of the process. However, treatment of the fluids coming from chemical flooded projects is one of the main risks associated with Chemical EOR processes. There are a number of processing difficulties which is caused by the back produced chemicals. Including tighter emulsions, heater fouling and other water treatment challenges. The back produced polymer is recognized as a risk that need to be addressed and mitigated as early as possible for any polymer project. In a field in the Sultanate of Oman, a polymer flood project was initiated early 2010. As part of the project, induced gas flotation and filtration units were installed in order to treat the produced water to the required specification for polymer solution preparation and injection. The required specification is 5 ppm (w) OIW and 2 ppm (w) TSS at the outlet of the filtration stage. This specification is required for polymer preparation and water injection. The molecular weight of the polymer coming back from the reservoir was measured to be in the range of 7 to 10 million Dalton molecular weight. Induced gas flotation technologies are accelerated gravity separation process. If the viscosity of the continuous phase increases, the raising velocity of the oil droplets reduces. It is then very essential for the viscosity of the continuous phase (water) to be maintained. It was found that the performance of the flotation cell decreases dramatically if the viscosity of the water increases more than 1.5-2 cP (at 7.0 s-1 shear rate) by using bench-top IGF trials. Mechanical and chemical means of breaking the HPAM polymer is investigated in this paper to decrease the viscosity of the produced water to a level that will enable the flotation technology to maintain performance to allow a method to be used in the field where these conventional technologies has been already installed. A success criteria was set which is the ability of the method to reduce the viscosity to the range of 1.5 – 2 cP. In terms of mechanical means to break the polymer, it was found that shearing through valves by differential pressure of 40 bars decreases the viscosity to about 2 cP using both higher molecular weight polymer or lower molecular weight polymer and it was more effective than 3-stages centrifugal pump. The main disadvantage of the mechanical shearing is the formation of smaller oil droplet through the shearing and smaller oil droplet which means slower raising velocity in the flotation cells. An attempt was carried out to quantify the effect of the pressure drop on the droplet size distribution. However, the starting droplet size was already in the range of 10 micron. It was observed that there is a small reduction in the droplet size from 10 micron to around 7 microns when the pressure drop is about 40 bars. In terms of chemical means to break the polymer, Sodium hypochlorite was the most effective chemical to break the HPAM polymer. The required dosage rate is in the range of 50 −100 ppm to achieve 1.5-2 cP (at 7.0 s-1 shear rate). In the presence of H2S in the water, it was observed that the dosage rate increases to about 500-1,000 ppm which makes it uneconomical to be implanted in the field. The oxidizer preferentially reacts with H2S to form a colloidal suspension.
Background: Increasing the efficiency of a polymer flooding project, both technologically and economically, is always relevant. Aim: This paper aims to consider switching to less saline water as a fairly simple and effective way to increase the effectiveness of a polymer flooding project. Materials and methods: The work used data from a real polymer flooding project. Results: As a result, we have been able to significantly reduce polymer consumption and improve pumping efficiency. Conclusion: This work shows that, with the possibility of using less saline water, as a simple and effective way to reduce costs and increase efficiency, rolling polymer flooding.
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