The current practice of overboard discharge of produced water from offshore facilities is becoming increasingly less attractive owing to environmental concerns and the impact of more stringent regulations. An alternative to overboard discharge is produced water re-injection (PWRI) into depleted reservoirs or into non-communicating aquifers. However, as offshore developments become more complex, with new fields producing through existing facilities, PWRI must face the problems involved in combining and re-injecting incompatible fluids and/or production chemicals. In this paper we describe a laboratory testing programme which was devised to aid in the development of a PWRI scheme for a North Sea facility. In the proposed re-injection scheme, produced waters from five fields are combined at a central facility prior to re-injection. Initial brine/production chemical compatibility tests identified potentially problematic incompatibilities. A series of formation damage core floods were performed to investigate the effect of these incompatibilities on injectivity into reconditioned reservoir core material from the proposed re-injection well. These tests were followed by further core flooding work in which alternative solvent-based strategies for the amelioration of incompatibility issues were investigated. From this sequence of tests emerged a PWRI protocol suitable for advancement towards field trials. This paper describes typical problems encountered in the development of multi-well produced water re-injection projects using commingled waters produced from different fields containing potential incompatibilities both from the co-mingled brines themselves and also as a result of the diverse range of treatment chemicals present in the individual production streams. The strategies employed to overcome these problems in this field case are discussed. Introduction The Cleeton field forms part of the BP ‘Villages’ complex in the Southern North Sea. Though production from the Cleeton reservoir ceased in early 1999, the Cleeton facilities continue to be used to handle produced fluids from adjacent fields. Currently, all produced waters on Cleeton are processed prior to overboard discharge. As part of the development of the Easington Catchment Area (ECA) fields, the Cleeton facilities are being converted into a transportation hub. Phase 1 of ECA involves production from the Neptune and Mercury fields. The hub requirements will then be expanded by the JUNO project, which will require services for a further five ECA Phase 2 fields. Figure 1 shows a schematic of the proposed ECA development. To comply with UK regulatory limits for oil discharge and with BP Federal Goals of eliminating produced water discharge, and to design the facilities for limited access (simple process facilities), it is proposed that the produced waters from the new fields will be processed on the Cleeton platform and then re-injected into a depleted Cleeton production zone, along with produced waters from Phase I fields. This will entail the topside mixing of various produced waters containing a mixture of chemicals (scale inhibitor (SI), corrosion inhibitors (CI1 and CI2), kinetic hydrate inhibitor (KHI) and methanol), followed by injection of the mixture into the Cleeton reservoir. The different production chemicals encompass a wide range of potentially incompatible chemical species including anionic scale inhibitor molecules, cationic corrosion inhibitors (quaternary ammonium salts, imidazolines etc.) and polyvinylcaprolactam-based kinetic hydrate inhibitor. The potential for incompatibilities between the chemicals produced from the different fields and also brine incompatibilities therefore exists in a similar manner to that previously discussed[1,2]. In addition, very mild chemical incompatibilities may exist which would not be expected to be severe enough to result in significant production issues. It is recognized that such minor incompatibilities may have minimal impact on produced water reinjection into thermally fractured wells.[3,4,5,6] However, more significant reduction in injectivity may be recorded when considering re-injection of produced waters into low permeability non-fractured reservoirs, as in this proposed field example.

The laboratory determination of scale inhibitor (SI) performance under field specific conditions using dynamic or static scale inhibitor tests provides an important method for determining minimum inhibitor concentrations (MIC's) for the inhibition of scale growth. This paper will discuss the ability of small amounts of ferrous iron to dramatically reduce the ability of SI's to inhibit calcium carbonate scale formation under dynamic laboratory test conditions. It has been previously reported that the presence of ferrous ions has an inhibiting effect on calcium carbonate formation under dynamic test conditions, which was confirmed for the brine systems used in this study. However, despite the somewhat milder scaling regime in the presence of ferrous ions, addition of Fe2+ ions to test brines caused the observed MIC's of typical scale inhibitor chemicals to increase more than one hundred fold when tested against calcium carbonate scale. A much less dramatic reduction in SI performance in the presence of ferrous ions was observed for barium sulfate scale formation under dynamic test conditions. Such interference in inhibitor performance can have major implications for the field application of scale inhibitor chemicals, leading to unexpected decline in production. The presence of ferrous ions has been shown to adversely affect scale inhibition of a number of different classes of SI chemicals, including poly(vinylsulphonate) (PVS) which has previously been reported as being iron-tolerant. This paper will describe the results of laboratory studies into this phenomenon, in which the nature and scope of the interference were investigated. 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 importance of appropriate laboratory test procedures has recently been discussed in detail.[1] The conventional static "bulk" or "jar" test procedures commonly adopted are related to that described in the NACE standards TM 0197–97[2] and TM 0374–2001.[3] Such tests have been described in many previous papers for both examination of the factors controlling inhibitor performance and for selecting scale inhibitor products prior to field applications. These tests are used routinely throughout the industry for scale inhibitor selection and optimisation studies.[1] In addition to static "jar" tests, dynamic "tube blocking" performance tests are also routinely used for scale inhibitor selection in oilfield environments. Dynamic tests complement static tests by allowing different facets of scale inhibitor activity to be examined. For example, dynamic tests examine activity under much shorter residence times than static tests, and so can be used to highlight differences between nucleation and crystal growth inhibition effects. Dynamic tests also allow for the impact of scale nucleation and growth on the walls of the micro-bore tubing to be assessed under laminar flow conditions. There are a number of benefits associated with dynamic performance tests, which have been described in a number of previous publications as follows[1]:Dynamic laminar flow system, as in oilfield productionExamines growth and blockage of microbore metal coilsSystems can be examined under pressure. This allows for routine testing under;higher temperature conditions (> 100°C),in the presence of bicarbonate ions without loss of pH control Finally, and of more importance for this study, the sealed nature of the dynamic flow tests means that:Examination of systems in the presence of dissolved iron can be more readily achievable than in static tests, provided that feed brines are adjusted accordingly to minimize potential oxidation of Fe(II) - > Fe(III).[4]

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.

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Chemical Placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments. For heterogeneous wells and long reach horizontal wells, various factors (including heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) all contribute to uneven placement in the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut-off) treatments or overdosing some zones to gain placement in other (e.g. low permeability) zones. For other very near wellbore treatments e.g. acid stimulation, a number of self-diverting strategies have been applied in field treatments with some success. Unfortunately, the properties which make such treatments applicable for acid stimulation may also make them inappropriate for scale squeeze treatments. Other modified lightly viscosified fluids have however been demonstrated to be of significant importance for improving chemical placement thereby reducing the potential for low permeability/high pressure zones being rapidly denuded of chemical during flowback. Critical to our understanding of such a process is the ability to accurately simulate the effectiveness of such treatments in the laboratory and to use the data to build and validate more effective modelling tools to allow field treatments to be designed. The paper examines the potential benefits of using modified injection fluids, including lightly viscosified and shear thinning fluids to aid uniform scale inhibitor placement in complex wells. Laboratory data using dual linear core flood experiments coupled with mathematical modelling are used to describe cases where such fluids are shown to offer benefit for field application and also those where more minimal benefit would be anticipated, such that the risks associated with the use of modified fluids (e.g. potential formation damage and fines mobilization) would outlay the benefits. The paper therefore describes the effective use and interpretation of detailed laboratory core flood data, mathematical modelling and field evidence to describe the benefits associated with the application of modified lightly viscosified shear thinning fluids in scale inhibitor squeeze treatments. INTRODUCTION Chemical placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.[1–8] For heterogeneous wells and long reach horizontal wells, a combination of factors (such as heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) can contribute to uneven placement of a squeeze treatment in the reservoir. This may result in the majority of the squeeze treatment volume being placed in an inappropriate zone in the near-wellbore, which can result in reduced squeeze lifetimes and inadequate scale protection of vulnerable near-wellbore mixing zones. Heterogeneity in the near-wellbore region will obviously affect the placement of a squeeze treatment under permeability control, with most of the volume of a conventional bullhead squeeze being placed in the higher permeability formation. Pressure gradients or crossflow will also influence the placement of an inhibitor slug, with injection being favoured in the lower pressure zones. The presence of crossflow during shut-in can cause a redistribution of the injected slug, resulting in more placement in a lower pressure zone. Other factors such as wellbore friction, layer pressures, the properties of the fluid in place and differences in mobility ratios between different zones also have an impact on chemical placement but will not be considered in this manuscript.