The chemical removal and dissolution of deposited wax has been described and proven in a variety of applications. This paper describes in detail the removal of wax deposits from a major subsea flowline with the use of a chemical dissolver. The following stages were key to the successful wax removal operation; selection and design phase of the chemical application, the chemical environmental selection criteria, the development of the work scope, as well as the mobilisation and logistics of the chemical application. This paper will illustrate the challenges faced as well as the novel monitoring and analysis techniques used in the field to determine the level of wax dissolution in situ. The wax removal process was deemed successful and offered the client significant benefit in terms of increased oil production. Reduced pipeline differential pressure and increased fluid arrival temperatures also indicated that the wax restrictions in the flowlines had been significantly removed. In addition, the impact on the platform processing facilities during final fluid displacement was much less than anticipated and occurred with no major concerns. A chemical dissolver application of this magnitude is thought to be unique, indeed a world first. The application was conducted in the Gannet D Field in the UK sector of the North Sea to remove wax deposits from two 16 km 6″ subsea production flow lines. Introduction The control and mitigation of wax deposition and its concurrent problems is rapidly becoming one of the critical challenges facing the oil and gas development and production industry. As the industry explores and develops in ever more challenging environments, such as deepwater and sub arctic conditions, the control of wax deposition and its subsequent remediation is becoming a critical technical challenge. Wax deposits can occur widely in the production process and are often considered as the organic equivalent of scale formation. This interpretation is misleading and belittles an important source of refined products from motor oil to jet fuel1. This definition also wrongly simplifies and implies equivalence to inorganic and organic "scales". We would refute this over simplification and take the view that organic and crude oil waxes have considerably different fundamental chemistries in particular in terms of their chemical bonding and the number of factors effecting their deposition1. Our approach to wax dissolution is exemplified in this paper which does not simply treat a deposited wax as a solid to be solvated and dissolved but involves an understanding of at least some of the complex solvent / solute interactions between the dissolver and the deposited wax 2. This paper therefore describes the selection of a wax dissolver and its full field application. The paper also considers the improvement in production rates in the Gannet D field by the application of a wax dissolver to remove restrictive deposition along a sub sea flow line. Field location and characteristics The Gannet field lies some 180km east of Aberdeen in a water depth of approximately 90m. Since the field was originally discovered in the 1970's, several satellite fields have been tied into the Gannet facilities. Gannet D is an oilfield located 16km northeast of the Gannet Alpha (Figure 1). Production is from five wells with oil being transported back to the Gannet Alpha facilities via two looped 6″ subsea flowlines referred to as Riser 31 and Riser 32. The crude from these reservoirs typically has an API of 41, a wax content of approximately 7%, and a wax appearance temperature in the region of 35.5oC. The Gannet G field is also produced via this system with a single 6″ flow line tied in at the base of Riser 32, half a kilometre from the Gannet Alpha platform. Therefore Riser 31 carries Gannet D crude only and Riser 32 carries Gannet D and G crude topsides onto the Gannet Alpha processing facilities where the oil is co-mingled with other Gannet fluids before being exported to the Fulmar platform.

It is accepted that sulphate reducing bacteria (SRB) and certain general heterotrophic bacteria (GHB) can promote pit corrosion of topside and downhole equipment and cause formation damage in the reservoir including H2S souring. In order to inhibit microbial growth and hence minimise these damage mechanisms, it is necessary to impose a strict microbial monitoring regime that can be used to optimise any biocide treatments. There are two major considerations relating to microbial monitoring which must be taken into account which are planktonic microbes (those in suspension) and sessile microbes (those attached as a biofilm). By monitoring the numbers of SRB/GHB entering and leaving each component of the topside process system it is possible to determine whether each is under good microbial control. If numbers are found to increase from inlet to outlet, then biocide treatment at a suitable concentration, can be used to treat the fouled components before pit corrosion or H2S production becomes a serious problem within the component. If the biocide treatment is not performed in time the system downstream may also become contaminated. By carefully monitoring each process system including injection water, firewater, cooling medium, and production systems, it is possible to extend the process equipment lifetime considerably, resulting in a major saving in equipment replacement and lost shut down time. This paper describes the microbial monitoring techniques required to minimise corrosion, biopolymer, insoluble metal sulphide and H2S production both topside and downhole. Introduction The action of SRB in causing microbially influenced corrosion of steal is well documented.1–6 If allowed to go unchecked in oilfield process systems pit corrosion can result with subsequent expensive equipment/pipework replacement being necessary. In addition to SRB corrosion, the growth of GHB can result in polymer precipitation and acid production which can further aid the corrosion process and act as a substrate for sessile biofilm development.7 In seawater injection systems SRB/GHB growth is most evident within the deaerator towers and downstream into the injection downhole tubulars. In production systems the activity of SRB/GHB can occur both downhole in the reservoir, production tubulars and topside in the separators and downstream process equipment towards the export oil pipeline. Oil and water pipelines can also suffer SRB/GHB related corrosion particularly in the six o'clock position where abrasion of the sulphide layer can occur. This results from particulates (sand, corrosion fragments) dragging along the bottom of the pipeline exposing fresh metal to SRB pit corrosion with a pronounced groove being developed. In order for SRB to grow, sulphate together with a suitable carbon source, usually volatile fatty acids such as acetate, are necessary. The source of carbon in seawater injection systems is normally from bacterial breakdown of algae and zooplankton (copepods) which is greatest during bloom periods in the local region. In the North Sea the algal and copepod bloom occurs twice a year around the end of spring and again in the autumn, with promoted SRB growth at these times in response to the elevated carbon in the injection topside equipment. The source of sulphate is present in the seawater itself. The source of carbon in production systems is mainly volatile fatty acids from the crude oil such as formate, acetate, propionate and butyrate. The sulphate in the production system originates from either the native formation brine (connate water) or a mixture of seawater (from injection seawater break-through) and formation brine. The higher the carbon and sulphate concentrations then the more likely a system will support SRB growth and be more prone to suffer microbially influenced corrosion.

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