Maturation of hydrocarbon reserves often occurs conjointly with an increase in flow assurance challenges. Deposition of paraffin and/or asphaltene is at the forefront of these challenges. Well maturity, declining reservoir pressure, coupled with hydrocarbon deposition, negatively impact the economic potential of a given reserve. Trinidad's Block Two Region is inundated with hundreds of mature paraffinic wells. To maintain cost effectiveness; proactive initiatives must be implemented with minimal operational expenditure. One such initiative used in the remediation of downhole hydrocarbon deposition, is the implementation of downhole treatment via chemical additives. Newer wells are often completed with allowances to enable targeted downhole chemical remediation. However, for older wells, as is the case in some Trinidad onshore blocks, the implementation of these enhanced modes of downhole chemical delivery, typically requires redesign of the downhole completion. The capital associated with this activity is considered cost prohibitive given the current oil price and low oil production from majority of these wells. This paper serves to highlight the profitability study with regards to the successful implementation of three common modes of topside treatment of paraffin deposition; steam treatment, annular chemical injection, and periodic batch treatment. It will also compare the return on investment associated with these successful applications. In this present economic climate, it is imperative for producers to adopt a proactive approach in the resolution of flow assurance challenges, namely hydrocarbon deposition, to ensure maximized production.
Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.
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