This paper presents the challenges of identifying and deploying a non-damaging non-aqueous scale inhibitor for pre-emptive squeeze into the largest dry producer in the BP-operated Mungo field. In order to pre-empt potential downhole scaling & subsequent impact on production, the Mungo asset requested a non-damaging, pre-emptive squeeze option for application prior to water breakthrough. Scale inhibitor squeezes are usually deployed post water breakthrough and when scale is predicted to form as a result of the co-mingling of incompatible produced brines. On the other hand, pre-emptive squeezes are preferred either when scaling is predicted from the start of water breakthrough or when the time required to mobilise chemicals etc. for an intervention is too long, placing production at risk. For Mungo, both these last scenarios applied: the predicted scaling tendencies were severe and immediate on water breakthrough, and the difficulty in mobilising a support vessel etc. to perform the job required careful planning and time. BP and their Mungo partners initiated a chemical selection test programme through their CMS provider to identify a non-damaging "Best in Class" chemical squeeze option for Mungo. The CMS partner with responsibility for chemical management of the Mungo asset organised an independent laboratory to screen commercially sensitive, "non-aqueous" products (non-aqueous carrier phase) from both their own product range and those of their competitors for potential application. When assessing chemical performance, clear selection criteria were issued to all the participating chemical suppliers prior to commencing any laboratory work. The chemicals were required to:cause minimal formation damage (or <10% damage in core flood tests);provide a maximum squeeze life (ca. 1 year was requested by the Mungo asset);be compatible with the incumbent corrosion inhibitor (>95% corrosion inhibitor performance was required); andbe compatible with Mungo brine. Other selection criteria also included environmental category, cost, impact on facilities, practicality of deployment and proven track record. This paper focuses on the main selection criteria (a) and (b). Comparative core flooding tests presented in this paper demonstrate that only one application fell within the specification of < 10% reduction in permeability. Having selected the least damaging non-aqueous chemical, further core flood tests were designed to simulate:injection into a lower permeability zone of the reservoir (or potential formation damage effects in the near wellbore region); andthe impact of chemical shut-in or adsorption. Two pre-emptive squeeze trials of a novel "non-aqueous" scale inhibitor have now been conducted in wells W168 and W163 on the BP Mungo field. The scale inhibitor was deployed by bullheading, using injection quality base oil as a preflush and overflush. In neither case was formation damage seen as a result of the treatment, with no change in oil or water rates pre and post-squeeze. In summary, the paper discusses how BP, Mungo partners and the CMS providers worked together to find the best technical solution to an important challenge facing many other fields and new developments, i. e. how to effectively select and deploy a non-damaging pre-emptive scale inhibition squeeze treatment. Independent testing has enabled the selection and deployment of a highly commercial "non-aqueous" application from an alternative non-CMS service provider.

Inhibitor performance in terms of the minimum inhibitor concentration (MIC) or the threshold concentration required to prevent scale is the most important aspect for scale control additives. The laboratory test protocols adopted throughout the industry are very similar and are based upon static "bulk" inhibition performance tests and dynamic "tube blocking" inhibitor performance tests. However it has become evident from field selection studies that performance results, obtained from different laboratories using similar techniques, can be significantly different. In this paper the various procedural differences are described. Results are presented from an extensive series of comparative performance tests examining both static and dynamic performance against calcium carbonate and barium sulphate scale. The results clearly demonstrate how relatively small differences in test procedure, as currently adopted by different laboratories, can have a significant impact on determined MIC values and comparative performance of different species. Such procedural modifications can therefore impact upon the reliability of data obtained in field chemical selection studies and the determination of dose levels, leading to the selection of less effective products. Tests examine the comparative impact of test procedures on generically different inhibitor species including phosphonate, polyacrylate and polyvinylsulphonate chemistries. The impact of the following aspects are covered:The inclusion of bicarbonate ions on both static and dynamic barium sulphate performance tests.The manner in which pH adjustment impacts dynamic sulphate and carbonate performance tests.Effect of flow rate, un time, coil dimensions and pre-scaling on dynamic barium sulphate and carbonate performance tests. Significant changes in both MIC values and also product ranking are recorded using variations on the standard test protocols commonly used in different laboratories, which demonstrates that more standardised and field appropriate procedures are required. The results in terms of changes in MIC and ranking of the different products are then explained mechanistically based upon the properties of the different products and the impact of modifications to test procedures. Examples of comparative performance for particular field cases are shown which demonstrate the importance of a field appropriate procedure. Finally, recommended test protocols will be detailed based upon the findings of this study. Introduction Inhibitor performance in terms of the minimum inhibitor concentration (MIC) or the threshold concentration required to prevent scale is one of the most important aspects for scale control additives, equalled only by the challenge of effective placement and deployment in today's ever more complex production environments. The laboratory test protocols adopted throughout the industry are very similar and are based upon static "bulk" inhibition performance tests and dynamic "tube blocking" inhibitor performance tests. The conventional static "bulk" or "jar" test procedures commonly adopted are related to that described in the NACE standard TM 0197–97.1 Such tests have been described in many previous papers for both examination of the factors controlling inhibitor performance2,3and for selecting scale inhibitor products prior to field applications.4–7These tests are used routinely throughout the industry for scale inhibitor selection and optimisation studies.

Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H2S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H2S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified. A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe+2 and S2-) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan. As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications. Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.

The Varg field (PL038, Block 15/12) is located in the Norwegian Sea. The Varg reservoir is Oxfordian sandstone of Jurassic age, with an upper (1000–2000 mD) and lower (100–200 mD) sand separated by a mud rich sandstone. The field is highly compartmentalized and is located around a salt dome, and contains a number of different formation waters ranging from high salinity, higher barium (up to 280 mg/l) in the West and lower salinity and lower barium (30 mg/l) in other areas. All waters contain naturally occurring dissolved iron at concentrations up to 175 mg/l. Following scaling in several wells, a chemical re-selection and treatment optimisation programme was initiated. Extensive laboratory studies were undertaken to select optimum inhibitors, which was further complicated by environmental requirements. The presence of dissolved iron was shown to have an adverse effect on the incumbent scale inhibitor, leading to the selection of a number of alternative products. Given the highly compartmentalized nature of the reservoir and the large permeability contrast between zones, near wellbore modelling studies, examining chemical placement using both conventional (aqueous) based treatments and also viscosified treatments, were conducted. The potential for poor placement and subsequent poor lifetimes led to further detailed simulation work using up to date PLT logs to further refine the treatments in subsequent wells. Therefore, this paper describes the various challenges facing scale control in the Varg field. The paper presents results from a chemical re-selection exercise showing the controlling influence of dissolved iron, together with coreflood studies used to select the most effective non-damaging product for subsequent field trials. Extensive near wellbore modelling results are presented to illustrate the challenges faced with respect to effective chemical placement, which highlight the challenges faced. Several field trials have now been conducted with a new chemical and the results of these are also discussed. Introduction & Challenges The Varg field is located in block 15/12 of the Norwegian Sea (Figure 1) at a water depth of 86m, and came on stream in December 1998. The wells are tied into the wellhead platform Varg A, and the oil is processed at the FPSO Petrojarl Varg (Figure 2). The distance between the well head platform and the ship is 1 km. The oil is exported by tankers and the produced gas re-injected. The Varg reservoir is Oxfordian sandstone of Jurassic age, with upper and lower sands separated by a mud rich sandstone. The upper sand, which is mainly deposited in the south, is of good quality (permeability range 1000–2000 mD). The lower sand is of more variable quality with an average permeability around 100–200 mD with some zones significantly lower. The field has a complex fault pattern, especially close to the salt dome. There are strong tectonian forces in the area and the seismic has poor resolution due to overlaying chalk. This limits the sensitivity of the reservoir description used in the full field model and makes accurate assessment of the water sweep patterns difficult. There are different fluid properties in most wells, consistent with the highly compartmentalized nature of the field and the field consists of several PVT regions. Most of the wells are vertical or normally deviated cased, cemented and perforated wells with relatively short pay zones from different formation zones. There are also horizontal wells, the longest horizontal being about 1000m long, again producing from different zones. Most of the wells have gas lift due to low reservoir pressure. Carbonate scaling is relatively insignificant in this reservoir with the main challenges associated with barium sulphate scales both relating to self scaling issues and also mixing of reservoir formation waters with injected sea water.

Paraffin fouling deposition is a common issue in oil production that leads to constrictions within the system wherever the system temperature drops below the wax appearance temperature (WAT). Chemical mitigation of these issues often relies on various laboratory equipment for product selection, but often the test conditions chosen are not representative of the field; therefore, the resulting deposit generated may give misleading results. In this article, our aim is to investigate how the use of different laboratory techniques can be utilized to generate a field-representative wax deposit. Our study includes the traditional cold finger (CF) apparatus, the coaxial shear cold finger (CSCF), and the dynamic paraffin deposition cell (DPDC), a test method developed in house. The pieces of equipment use similar temperature-driven deposit formation to measure fouling but with very different mixing conditions. The study of paraffin deposition at narrow temperature gradients with these techniques showed similar trends for deposit weight when compared to the fouling factor obtained using a common oil and the Para-window technique presented in a previous study. Significantly, it was observed that for all of the laboratory techniques used, different sample homogenization/mixing mechanisms did not affect the carbon chain distribution of the most insoluble and problematic high-molecular-weight wax (≥n-C 35 ) but did affect the shorter chain composition (i.e., those that are most prevalent in the parent crude oil). The results confirm that temperature is the main driver dictating the nature of the most field-representative deposit characteristics using the laboratory test systems available. This presents the opportunity to gain better insights into paraffin deposition in the laboratory and prepares us to develop better screening capabilities in order to meet current and future paraffin challenges faced in the field.