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Summary Polymeric scale inhibitors are widely used in the oil and gas field because of their enhanced thermal stability and better environmental compatibility. However, the squeeze efficiency of such threshold inhibitors, not only polymeric scale inhibitors but also phosphonates, is typically poor in conventional squeeze treatment. In this research, nanoparticle (NP)-crosslinked polymeric scale inhibitors were developed for scale control. Nearly monodispersed boehmite [γ-AlO(OH)] NPs with average size of 2.8 nm were synthesized and used to crosslink sulfonated polycarboxylic acid (SPCA). Crosslinked AlO(OH)-SPCA nanoinhibitors were produced and developed to increase the retention of SPCA in formations by converting liquid-phase polymeric scale inhibitors into a viscous gel. Study of sorption of SPCA onto AlO(OH) NPs under different pHs with and without assistance of Ca was discussed. In addition, study of sorption of various types of scale inhibitors [SPCA; phosphino-polycarboxylic acid (PPCA); and diethylenetriaminepentatakis(methylene phosphonic acid) (DTPMP)] onto AlO(OH) NPs was performed. Squeeze simulation of neat 3% SPCA, AlO(OH) (3%)-SPCA (3%) NPs, and AlO(OH) (3%)-SPCA (3%)-Ca NPs was investigated. The results showed that the addition of Ca ions improves the squeeze performance of SPCA, and the normalized squeeze life (NSL) of such material (8,952 bbl/kg) was improved by a factor greater than 60 compared with that of SPCA alone (152 bbl/kg).
Abstract Oilfield scale costs are high because of drastic oil and gas production decline, frequent pulling of down-hole equipment for replacement, re-perforation of the scaling producing intervals, reaming and re-drilling of the plugged oil wells, stimulation of the plugged oil-bearing formation and other remedial work-over. As scale deposits around the well-bore, the porous formation becomes plugged and may be rendered impermeable to any fluids. In most of oil and gas fields scale deposition in surface and subsurface production equipment has been recognized to be one of the major operational problem. Problem will be more critical in Water flooded fields where wells will suffered from flow restriction because of scale deposition within the oil producing formation matrix and the down-hole equipment, as well as scale deposits in the surface production equipment. Some of the Oil Fields have been water-flooded with formation seawater. Compatibility tests have indicated probable deposition of scale in surface and subsurface production equipment. This paper outlines the physical and theoretical prediction for down-hole scale deposition in the water flooded fields. Water is the main substance, which is responsible for scale build up problem. In order to study the circumstances behind the scale build up problem, following the new methodology which can be applied to predict the different types of scale build up before start to be precipitated. From the samples of the complete water analysis reports, Scale Indexes were calculated to define the different scales that can be precipitated at different production nodes/conditions. This paper showed that different types/amounts of scale accumulation can be precipitated from the selected water samples since the super saturation conditions of water occurred. It also described the control of scale inhibition programs which could be carried out to control down-hole scale deposition and scale inhibition treatment that could be implemented to overcome the scale deposition, before scale problem will be occurred. Scale control can also been controlled/managed properly by continues updating the new scale index calculations methodology described in the probable problematic water flooded reservoir. Introduction Some of the Oil Fields have been water-flooded with seawater. Compatibility tests have indicated probable deposition of scale on surface and subsurface production equipment. This paper outlines the physical and theoretical prediction for down-hole scale deposition in example OIL wells. It also describes the control of scale inhibition programs which carried out to control down-hole scale deposition by using the formation squeeze technique. Scale deposition on surface and subsurface oil and gas production equipment has been recognized to be a major operational problem. Scale contributes to equipment wear and corrosion and flow restriction, thus resulting in a decrease in oil and gas production. Experience in the oil industry has indicated that many oil wells have suffered flow restriction because of scale deposition within the oil/gas-producing formation matrix and the down-hole equipment, as well as scale deposits in the surface production equipment and, generally in primary, secondary, and tertiary oil recovery phase.
Vazquez, Oscar (Heriot-Watt University) | Young, Callum (Maersk Oil North Sea UK Limited) | Demyanov, Vasily (Heriot-Watt University) | Arnold, Dan (Heriot-Watt University) | Fisher, Andrew (Maersk Oil North Sea UK Limited) | MacMillan, Alasdair (Maersk Oil North Sea UK Limited) | Christie, Mike (Heriot-Watt University)
Summary Inorganic-scale precipitation and deposition in production wells can be a significant impediment to effective reservoir management. In extreme cases, scale can cause the well to be abandoned as a result of reservoir-formation damage in the near-wellbore region and the narrowing of the production-tubing annulus, thus preventing fluid flow. The prediction of the time and location of scale formation is therefore essential for scale management. This study is focused on sulfate scales, which form when sulfate-rich seawater mixes with formation brines that are rich in barium, calcium, and strontium, and which are among the most difficult types of scale to prevent and remove. Formation brines in reservoirs with a tendency for sulfate-scale deposition can have a very different makeup when compared with seawater, which may be injected for pressure support. Having such different chemistries allows seawater and formation brine to be tracked. In this study, two different types of water are considered: formation brine and injected seawater. The objective of this work is to predict uncertainty in sulfate-scale deposition from multiple history-matched reservoir models by tracking injected seawater in the Janice field. There are many examples in the literature in which conventional reservoir history matching (namely, gas rate, oil rate, and bottomhole pressure) are used to generate an ensemble of good history-matched models that will estimate uncertainty of a hydrocarbon-reservoir production. In this study, the same approach will be adopted, but including produced-water chemistry—in particular, seawater breakthrough. This approach provides a methodology to predict the uncertainty of the formation-brine/injected-seawater mixing zone within the reservoir formation. The methodology provides a Bayesian confidence interval (P10/P50/P90) in time and space for the injected seawater, identifying which wells will be at risk on the basis of seawater breakthrough and in which zones of the reservoir mixing is more likely to occur.
Summary Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine-chemistry data set was developed. Systematic analysis of this data set enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, along with improving its prevention and remediation. A study of the individual-ion trends in the produced brine by use of the plot types developed for the reacting-ions toolkit (Ishkov et al. 2009) provides insights into the components that are involved in in-situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion-exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells. A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced-water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate, on the basis of the endpoint formation- and injection-brine compositions and the erroneous assumption that no reactions in the reservoir impact the produced-water composition. Nonetheless, the usual effects of temperature, pressure, and brine composition are accounted for in these calculations by use of classical thermodynamics. The comparison of theoretical and actual results indicates that geochemical reactions taking place in this given reservoir lead to ion depletion, which greatly reduces the severity and potential for scale formation. However, ion-exchange reactions are also observed, and these too affect the scale risk and the effectiveness of scale inhibitors in preventing deposition. Additionally, comprehensive analysis by use of a geochemical model is conducted to predict the evolution of the produced-brine compositions at the production wells and to test the assumptions about which in-situ reactions are occurring. A good match between the predictions from this geochemical model and the observed produced-brine compositions is obtained, suggesting that the key reactions included in the geochemical model are representative of actual field behavior. This helps to establish confidence that the model can be used as a predictive tool in this field.