One challenge facing the adoption of electric vehicles (EVs) is the reduction of the impact of running out of fuel. An EV, with its limited charging point infrastructure and long charge times, is not seen as being as reliable as a conventional car in this respect. To make EVs more acceptable, forward-looking predictive methods of calculating range need to be developed which also take into account opportunities to conserve or harvest energy, as well as environmental factors such as terrain and weather conditions. Using a well-established EV range simulator, this paper describes scenarios showing the limitations of relying on such an approach and the potential detrimental results to both the driver and vehicle's ability to start and complete a journey. It provides an overview of the research being undertaken by the authors to address these problems, including a description of 'Electrikitty', a road legal pure EV that will be used to gather data to verify the development of novel range estimation algorithms.

A common method to prevent scale forming in oil production wells is to inject scale inhibitor into the formation in so called squeeze treatments. Conventional scale inhibitor treatments with a brine pre-flush, main scale inhibitor pill and brine over flush stages are often not considered to be economically efficient as a large proportion of the scale inhibitor introduced into the squeeze treatment is returned almost immediately and therefore does not serve to provide long term scale protection. Various techniques have been used successfully to increase the proportion of scale inhibitor retention in the well during squeeze treatments. For example, it has been reported previously in many papers where poly amino acids and poly quaternary amines have been injected into a well as part of the pre flush process and have significantly improved scale inhibitor retention and scale squeeze lifetimes. It has now been found that scale inhibitor treatment lifetimes can be improved by incorporating an ionic polymer such as a poly amino acid or poly quaternary amine in the over flush stage of the squeeze treatment. Indeed this method has been found to further extend the treatment lifetimes when combined with the same additives in the pre-flush stage of the scale squeeze treatment. The new scale squeeze design technology can be considered very flexible as it can be applied with most scale inhibitor chemistries including both phosphonates and polymers with minimal formation damage potential compared to most precipitation scale squeeze treatments. It should be applicable over a wide temperature range from 30°C to 200°C and, in addition, the treatment strategy also lends itself to both aqueous and non-aqueous deployment and hybrid treatments and could provide extra protection against fines production in water sensitive wells depending upon the ionic polymer deployed. Initial field treatments have demonstrated the potential to extend treatment lifetimes by retaining up to 20 to 50% more useful chemical in the treatment reservoir. This paper will highlight the proposed mechanisms of how the ionic polymer additives can improve squeeze treatment lifetimes as part of the over flush and will present field data for treatments on two wells in an HP/HT field at 165°C that demonstrated improved chemical retention and scale inhibitor returns compared to treatments without the ionic polymer additive in the over flush.

Nelson is a platform development in the Central North Sea approximately 180km east of Aberdeen, producing 38° API oil from a Forties type reservoir with seawater injection pressure support. The high-salinity formation water contains up to 370 mgl-1 of barium, creating a significant scaling risk to the wells upon sea-water breakthrough. The majority of current wells are highly deviated but several horizontal wells with variable permeability exist, which pose a considerable challenge in terms of scale-squeeze placement. N19z is a horizontal well in the North Central region of the reservoir with a 500m cased/perforated producing interval in which breakthrough of sea-water has been confirmed. The well has previously been squeezed, both non-diverted and diverted with wax beads, each with varying success. Earlier reports have examined the effect of applying lightly viscosified fluids on placement of treatment fluids across long intervals to overcome friction and crossflow effects with the potential to assist in treating zones with permeability contrasts1. This approach was pursued to improve the effectiveness of squeeze treatments in long-reach horizontal wells in Nelson, culminating in the successful squeeze of well N19z with a precipitating inhibitor in which all squeeze stages were viscosified. The paper reviews the advantages of the viscosified approach, reports laboratory testing, compares the performance of the squeeze relative with non-diverted and wax-bead-diverted treatments, and highlights some of the pitfalls in applying fully viscosified treatments in both Nelson and other field horizontal or high permeability contrast wells. Introduction Scale control in horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be guaranteed through conventional bullhead squeeze treatments. With longproducing intervals wellbore friction can make uniform treatment difficult even where no significant contrasts in permeability exist; permeability contrasts can exacerbate this still further, in particular, where highest permeability is found near the "heel" of a horizontal well. Moreover, production from zones of different pressures, can generate wellbore crossflow, which can seriously compromise effective adsorption/precipitation of inhibitor during shut-in. Under some of the aforementioned circumstances even placement using coiled-tubing operations cannot guarantee effective chemical placement. The cost associated with use of coiled tubing is very much greater than that associated with conventional bullhead operations, as have been discussed in a number of recent publications.[1–8]

Calcium carbonate scale impacts oil production in a large number of fields worldwide. This scale is generally managed by acid washing to remove the scale and/or by performing scale inhibition treatments. The methodology adopted is usually cost driven with high cost operations generally selecting scale prevention rather than removal. Recently reported work1 showed the potential to integrate scale removal and scale inhibition treatments into a single package, offering clear economic and technical advantages. The combined treatment inherently reduces well intervention costs and well downtime, and protects the value added by the scale removal treatment - by assuring that all of the zones that are stimulated are also inhibited. Combining acid stimulation chemicals and scale inhibitors is by no means a simple process. Compatibility between the acid, the acid additives and the scale inhibitor presents a significant issue in both live and spent acids. This paper will examine these technical challenges and describes the desired properties of such combined systems. Case histories of recent field trials of combined scale removal and inhibition treatments will be presented, including details of job design, job execution and post-job evaluation. Data demonstrating the scale inhibitor return profile in these treatments will be shown, and lessons learnt from the initial trials will be discussed. Comparative performance data for previous acid treatments will also be presented. Introduction Acid stimulation treatments are often used to improve well performance. Hydrochloric acid (HCl) is generally the acid of choice when calcium carbonate is the suspected damage mechanism, unless corrosion cannot be adequately controlled. For high temperature applications, organic acids have been used in preference to HCl, due to such corrosion concerns.2–3 The stimulation benefit of such an acid treatment is often only maintained if a scale inhibitor is subsequently deployed. Recently reported work1 demonstrated that certain scale inhibitors are not only compatible with HCl but also that they retain their ability to adsorb onto reservoir rock under highly acidic conditions. Hence a scale inhibitor could be deployed directly in the acid system, negating the need for a separate scale inhibition treatment. Previously, it had been thought that scale inhibitors could not perform effectively in the post-acid treatment environment.4 Background Two field trial candidate wells were identified, both of which had sand control completions installed. The wells were in different fields and one of the wells had been matrix acidised approximately one year earlier. The cause of decline in each candidate was inconclusive with both calcium carbonate scale deposition and/or fines migration being plausible options. Both of the wells had already been selected as acid stimulation candidates. Combining scale inhibition with the acid treatment offered the advantage that the treatment could be used not only as a stimulation treatment but also as a diagnostic treatment to assess the dominant damage mechanism.

As the oil industry continues to operate in more complex and ultrahigh temperature environments scale control becomes an ever increasing challenge. Scale inhibitors are being pushed to their operational limits and start to lose their efficiency against both calcium carbonate and calcium sulphate scales at >400°F. It is therefore essential to develop the next generation scale inhibitor to work effectively against scale in harsh, high temperature environments such as steam floods and gas wells. In this study, details will be provided on the thermal stability test of a novel, biodegradable phosphonate scale inhibitor at temperatures 300°F and 400°F at two pH values, pH 4.0 and pH 6.0. Bottle tests on calcium carbonate and calcium sulfate were conducted with the thermal-aged phosphonate for their inhibition. Dynamic tube blocking tests were also conducted for calcium carbonate and calcium sulfate inhibition at 392°F to demonstrate the performance of the inhibitor. The new phosphonate scale inhibitor has also been designed to be biodegradable and it can be deployed by both continuous injection and scale squeeze treatment which is an advantage compared to polymers as they are often less suitable for high temperature scale squeeze treatments. Careful consideration was also given in the molecular design process for high calcium tolerance and details of brine compatibility at high temperature will be provided. This paper presents details of the evaluation of a biodegradable, thermally stable and calcium tolerant phosphonate scale inhibitor for both calcium sulphate and calcium carbonate scale control in ultrahigh temperature environments at ~400°F. In addition, the environmental test data will be discussed along with details of a field example of continuous downhole deployment of the new phosphonate scale inhibitor for calcium carbonate scale control in a high calcium brine (30,000 mg/L).