Produced water is the largest volume waste stream in oil and gas production and is a particular problem for late-life operation of oil fields. The huge waste volumes result in two obvious consequences and cost drivers; fast declining reservoir pressure and tremendous power used to handle it. Produced water reinjection has been used as a main strategy for both managing produced water volumes and supporting reservoir pressure. Treating produced water subsea as close as possible to the production wells has several advantages such as smaller topside footprint, minimizing the energy demand and associated emissions, reducing the well back pressure and increasing production rates. While some work has been done in the past on subsea use of deoiling hydrocyclones, robust high performance subsea produced water treatment equipment and processes have not yet been made available. The Compact Flotation Unit (CFU) is a well proven technology for topside use and has been considered promising for subsea use, but never before been tested at subsea relevant pressures. Aker Solutions with partners Aker BP, Equinor and Total and support from Research Council of Norway have successfully run a joint industry project to qualify this technology for subsea application. Pilot testing of a subsea CFU was carried out in Equinor's large scale test facilities in Porsgrunn, using crude oil, natural gas and synthetic produced water. The pilot CFU was tested with pressures significantly above that used for conventional topside CFUs, and at various temperatures. Gas bubbles were injected by use of ejectors designed to provide the desired bubble size. Oil droplet size, flow rate and oil in water concentration were the major control variables in addition to pressure and temperature. The effect of injection of flocculant was also investigated. The main topic of interest was the oil removal efficiency of the CFU under high pressure. The analyses of the results showed that the CFU's efficiency improved with increase of the operational pressure. This was likely to be related to the changes of physical properties of gas, oil and water as pressure increases, and the changing balance between physical phenomena in the process. The CFU also demonstrated robust performance with a large turndown ratio. Test of flocculant at high pressure showed instant and substantial improvement in the CFU efficiency, and the effect of flocculant was not compromised by the high pressure. The promising results suggest that CFU performs well at elevated pressure and is a viable solution for subsea produced water treatment.
Reduced environmental impact is the goal when choosing produced water treatment technologies. On the Norwegian sector the method used for quantifying this impact is the Environmental Impact Factor, EIF. This method is computerized in a tool that calculates the environmental impact from each of a number of chemical component groups that are present in produced water. Re-injection of produced water is the preferred option, and mostly used when pressure support is required. This paper, however, describes new treatment technologies aimed at produced water being released to sea. The technologies are suitable for different produced water compositions. The components in the produced water that contribute to the environmental impact are mainly: aliphatic hydrocarbons, heavy aromatic compounds (PAH), alkylated phenols and man added production chemicals. At several Statoil operated fields the corrosion inhibitor and H2S scavenger are giving a significant contribution. Several new technologies will be described. Statoil has had a leading role and actively participated in the development and qualification of most of these technologies. The results from this work will be presented. The technologies will include the CTour process, Epcon CFU, droplet coalescing technologies as well as new technologies to reduce discharge of production chemicals. The main conclusion is that knowledge is needed about which compounds contribute to the environmental impact of produced water before deciding which technology to use. Introduction The main focus in reducing the possible pollution from produced water to the sea has traditionally been on reducing the content of dispersed oil. Even though some countries have placed their attention on other compounds, international regulations like the new OSPAR regulations [1] still focus mainly on dispersed oil content in produced water. The new OSPAR regulations demanding less than 30 mg/l dispersed oil, and a 15 % reduction in total oil from year 2000 level will be implemented by 2006. On the Norwegian sector of the North Sea, all operators must, in addition to fulfilling and reporting according to the dispersed oil regulations, report the total environmental impact of the produced water release to the sea to the Norwegian Pollution Control Authorities (SFT) [2]. This reporting is done on an annual basis and is based on thorough (GC-MS) analysis of the produced water to quantify the content of all compounds of interest. The method for quantifying the environmental impact is the Environmental Impact Factor, EIF [3], which relies on DREAM (Dose Related Risk and Effect Assessment Model) [4]. In this model a comparison is made between the concentrations of possible environmentally harmful compounds and the predicted no effect concentration, based on an environmental risk assessment approach. The EIF is not only a valuable tool for quantifying the total environmental impact from one platform or a group of them, but also for evaluating the contribution from the different constituents in the produced water. In this paper three different technologies for produced water purification will be presented. The CTour process that is a liquid-liquid extraction process, the Epcon Compact Flotation Unit and Mare's Tail that is an oil droplet coalescer. In addition to these three technologies measures to reduce the environmental impact from production chemicals will be presented. Produced Water Purification Processes The compositions of produced water from different fields vary significantly. Hence, each field should be evaluated with respect to which compounds contribute to the environmental risk. When selecting produced water treatment technologies, one should focus on the major contributors to reduce the total environmental impact. Experience has shown that the major contributors to the EIF are dispersed oil, volatile aromatics, heavy aromatics, alkylated phenols, and added chemicals.
Several fields on the Norwegian Continental Shelf are in the decline phase with an increasing production of water and gas, often in combination with reduction in production pressure. The available area for installation of new equipment on the platforms is often limited, and it is important to minimize both the operational and capital costs. Compact, inline separation technology could be a key technology for mature fields, and also for subsea fields at large water depths where the weight is critical. Statoil has identified inline separation as an important technology to increase the oil recovery at brown fields. Due to low foot print and low operation cost the technology could be suitable to increase and prolong water production from the reservoir. The technology would also make it easier for tie-in of new fields at existing installations. To utilize the technology there is a need for both inline gas/liquid and inline oil/water separation (dewatering). Statoil has been carrying out a qualification program to develop inline equipment for dewatering. The project has been a co-operation between Statoil and FMC Separation Systems, and has been carried out in the period 2008 -2012. The technology is based on cyclonic separation devices with low or moderate pressure drops. An extensive development program has been performed with different geometries for the inline separators, including Computational Fluid Dynamics (CFD) study and testing activities both in laboratory flow loops and at the Gullfaks field. A full scale DeWaterer with 20 liners has been tested to investigate the effect of gas present. The operational window of the inline technology has been established, and the results show that gas and water can be efficiently separated from the well stream. The results will be presented in the paper. The conclusion from the work is that inline technology has a large potential to replace or reduce the size of conventional gravity separators topside, and also to be utilised for subsea separation at large water depths. The qualification work demonstrated that the dewatering technology for the Gullfaks application could separate water with a water quality of less than 500 ppm Oil-in-Water at low pressure drop (1 bar). Based on the qualification work the technology is considered ready for deployment in Statoil.
Estimates of the amount of discharged production chemicals are most often calculated using octanol/water partition coefficients. This is due to the lack of any better methods to predict how much of the chemicals is water soluble and would thus follow with the produced water to sea. Here a laboratory method for determining the partitioning of some typical production chemicals between oil and water is reported. The experimental parameters that influence the partitioning have been examined and partition coefficients for a range of chemicals have thus been established. The validity of this laboratory method has been verified in a field trial in the North Sea. By combining the partition coefficients with production data and putting these into a spreadsheet the so-called ‘Mass Balance Simulator’ is obtained. With this it is possible to predict how much of a chemical is discharged to sea and how much is retained in the crude oil leaving the platform. Introduction Chemicals are added to the oil/gas value chain at different positions during the physical flow from well stream to the traded product. All the different stages in oil and gas production generally require chemicals to assist in specific operations, for the drilling of wells, for the production of the oil or for the transport of oil through pipelines. The chemicals are used for different purposes (like defoaming, demuls-ification and hydrate and scale inhibition/ dissolution) and are added in varying amounts, continuously or in batch. It is generally accepted that efficient and cost-effective oil and gas production is not possible without the use of chemicals. Over the last 10 years, the chemical usage has increased, as is apparent from Fig. 1. Here the amount of production chemicals used at Statoil-operated fields is shown on an annual basis1. A similar trend can be found for drilling chemicals. The increase is not only due to the fact that new fields are brought to production (Sleipner 1993, Heidrun 1995, Troll 1996, Norne 1997, Åsgard 1999). In addition, new solutions have been applied, for instance the use of methanol for multiphase well stream transport from subsea wells. And mature fields like Gullfaks and Statfjord have increased needs for chemical-based treatments like well treatment or water treatment. Consequently, a lot of attention has been paid to this use of chemicals from the oil industry itself as well as from the public authorities due to the environmental strain this may represent.
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