No abstract
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSince the early 1990's scale inhibitor precipitation technology has been routinely used throughout the North Sea to provide improved placement and extended treatment lifetimes when compared to conventional aqueous-based scale inhibitor squeeze treatments. Controlled precipitation technology is based upon the deployment of a specially formulated scale inhibitor package containing an organic additive that breaks down thermally and acts as a pH modifier resulting in in-situ scale inhibitor precipitation. However, the reliance on thermal degradation of the organic additive to cause precipitation means that this technology is limited to use in wells at temperatures > 85°C. This paper describes the development of a low temperature, scale inhibitor precipitation delivery system. The new system is based upon the use of novel enzyme technology to break down the pH modifier using a non-thermal mechanism, thus allowing product deployment at low temperatures previously unavailable to the thermal degradation systems. Laboratory studies have so far indicated that the enzyme is effective at inducing scale inhibitor precipitation at both 40°C and 80ºC.A description of the laboratory development and evaluation of the new enzyme precipitation technology including enzyme assay, full analysis of the precipitation mechanism and core flood studies to evaluate formation damage potential and retention and release characteristics will be presented. This paper will also highlight how the use of the enzyme precipitation process can increase squeeze lifetimes when compared to traditional adsorption squeeze treatments at low temperatures.
Precipitation and deposition of asphaltenes is becoming a more common issue in the hydrocarbon production process from high pressure reservoirs. Asphaltenes are organic solids commonly considered to be polyaromatic structures with aliphatic chains, sometimes including other heteroatoms. Asphaltene formation in the near-wellbore area and downstream in production facilities can cause numerous flow assurance related issues. This paper describes work performed in developing a novel class of materials, using dendrimers as a platform to inhibit asphaltene deposition in oilfield applications. Dendrimers, or hyperbranched polymers, are tree-like structures grown from a central core with repeating subunits that provide high molecular weight compounds. This paper describes the initial development of the dendrimeric chemistries, including initial crude characterisation, laboratory performance evaluation of the products, and two subsequent successful field treatments. The data presented shows effective reduction of precipitation and deposition of asphaltenes both downhole via capillary injection and topsides in production facilities both previously encountering complicated asphaltene issues.
The accurate and timely analysis of oilfield chemicals is crucial in allowing cost effective chemical management. Unfortunately, many of the current detection methods are time consuming and are not appropriate for on-site applications. Clariant Oil Services and Haptogen Ltd have developed a detection kit that allows accurate on-site, same day chemical analysis. The test kit has been designed in a simple format, allowing analysis to be performed offshore and without the need for laboratory facilities. The test method is based on antibodies that specifically bind to a single production chemical molecule, allowing detection of the molecule without interference from other species which may be present in produced water samples. Antibodies have been developed for a specific, polymer based scale inhibitor used on a North Sea field that exhibits a harsh scaling environment. These antibodies have been evaluated in the laboratory in comparison with traditional test methods and found to be accurate at concentrations down to below 1ppm of applied scale inhibitor. It is now planned to evaluate the kit in the field. Future work will also build up a suite of antibodies, which will allow detection of a wide range of production chemicals using this technique. Introduction A wide range of chemicals may be used during production operations, such as scale, corrosion, wax and hydrate inhibitors, containing many different molecular species. Often it is important to have the ability to measure unknown concentrations of chemical returning from the production system. For example, in the North Sea, scale inhibitors are often "squeezed" into a well, and protect the well from scaling as the inhibitor is retired in the produced water. Over time, the concentration of scale inhibitor in the produced water declines as the treatment becomes exhausted, until the level is too low to provide effective protection and it becomes necessary to re-treat the well. The point at which this will occur cannot always be accurately predicted, and so it is usually necessary to analyse produced water samples for scale inhibitor content on a regular basis, in order to know when to re-squeeze. In some harsh scaling conditions, more than 100kg can deposit per 1000bbl of produced water1. It is therefore potentially of great economic benefit to have a rapid and reliable analysis method on which to base decisions to re-treat, and so ensure well integrity. Furthermore, the cost of treating a well can be substantial, in terms both of chemical / deployment costs and in lost oil production for the period of the treatment. Same day analysis would prevent treatment more frequently than is actually needed due to uncertainty, leading to cost savings. Unfortunately, it is usually necessary to transport samples off site for analysis, leading to extra transportation costs and also to delay in the availability of the results. For example, some scale inhibitors can be detected by inductively coupled plasma atomic emission spectroscopy (ICP-AES), which can determine the proportion of a single atom present in a sample. Unfortunately this requires on-shore laboratory facilities, and furthermore is only possible if the chemical being detected contains an atom which is not present in any other components of the produced fluid, for example phosphorus in phosphonate based scale inhibitors. In the case of polymeric scale inhibitors there is often no distinctive atomic species present and it is necessary to use more costly and time consuming methods2. In many cases there may be no simple and accurate test method for detection of a particular chemical. In this instance it may be possible to deduce the presence of a chemical via the behaviour of a fluid, however again this is likely to be time consuming. Finally, the presence of many different chemical species in produced fluids can cause interferences, making it difficult to assess the quantities of each separate component present. Clariant Oil Services and Haptogen Ltd have developed a detection method that avoids these problems by allowing on-site, same day chemical analysis of aqueous samples. The test method is based on antibodies that specifically bind to a single production chemical molecule, allowing detection of the molecule without interference from other species which may be present in produced water samples.
This paper describes the approach taken to evaluate and successfully treat flow assurance challenges associated to high viscosity produced fluids in an oil producing field, offshore Gulf of Mexico. The first section of the paper outlines primary evaluation criteria: discussing base line modeling of crude oil characteristics at various points of the production system, laboratory analyses, detailed explanation of the chemistries considered for reducing the viscosity, and the strategy to remediate multiple flow assurance challenges with subsequent performance testing. The second section presents field trial data from the application of the selected flow improver and its longer-term performance. Initial evaluation of high viscosity was required due to deposition of asphaltene, high levels of emulsion, increased pressure and resultant decrease in production All of these production issues caused increased spending on fluids treatment in a field that is mature and becoming more marginal to produce. Initial analysis of the produced fluid did not result in an immediate, clear approach to address the concern, without considering the multiple factors that can contribute to flow assurance challenges. Organic deposition, such as waxes and asphaltenes, were found to increase fluid viscosity and worsen highly stabilized emulsions. Crude oil/water emulsions also cause increased viscosity and needed to be addressed as part of any holistic solution. Each issue was studied and experimented on its own and in combination to ensure there was no reductive effect in a final chemical application that needed to treat them all. Successful field application of the selected flow improver technology exceeded the performance at laboratory scale achieving over 30% reduction in total fluid viscosity over long-term field deployment with associated benefits to the offshore operator which will be elaborated further in this paper. As an outcome of this field trial, this paper also presents a proposed generic approach in devising chemical solutions for treatment of high viscosity fluids.
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