TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCarbonate and sulphate scales are the most common types of mineral deposit associated with the recovery and processing of hydrocarbon and associated produced water. In three high temperature fields (>140C) within the North Sea more usual scale types have been observed namely zinc and lead sulphide. Conventional inhibitors cannot control these scale types and their removal by chemical means can result in the generation of toxic gas (H 2 S). The conditions for the formation of these unusual scale types is described and well as the economic impact these deposit had on hydrocarbon production of these fields. In this paper the development of a novel scale inhibitor package and its successful application in these fields is described.Field evaluation of the inhibitor types used to control sulphide scale is described in this paper as well as the details on how the field trials were planned, carried out and evaluated.Mechanical and chemical removal are also discussed as an alternative to inhibition.The finding of this paper significantly increase the industries understanding of sulphide scale deposits in terms of mode of formation and mechanism of inhibition. The paper stresses the critical factors to be evaluated within produced water at the early stage of field appraisal/development that can aid in the assessment of the risk of sulphide scale deposition. The development of a novel zinc and lead sulphide inhibitor gives a cost effective, environment friendly alternative to chemical or mechanical removal of such deposits.

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The scale control challenges for two North Sea carbonate reservoirs are reviewed in this paper. Whilst carbonate reservoir are not the largest source of hydrocarbon within the North Sea, they are very significant on a global bases. The mechanism of scale inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulphonate co-polymer inhibitors on carbonate reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale squeeze treatments into fractured chalk reservoirs. Examples from over 50 field treatments applied in reservoirs E and V, where both phosphonate and vinyl sulphonate polymer chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phosphonate to a vinyl sulphonate co-polymer-based scale inhibitor. The selection and qualification of chemical placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale inhibitor chemical placement are vital to economic success during water flood projects. Introduction The correct selection of scale inhibitor for the control of mineral scale within reservoirs and associated production tubing is vital if economic hydrocarbon production is to be maintained. The following section will outline the principle differences between carbonates and sandstone reservoirs, which makes scale inhibitor selection and application a technical challenge. What is Carbonate? Carbonate reservoirs are principally composed of carbonate minerals, which include calcite (CaCO3), dolomite (Ca,MgCO3), ankerite (Ca,Mg,FeCO3), and siderite (FeCO3). Carbonate reservoirs can be sub-divided into chalk and limestone. Chalk reservoirs are composed of small spherical/plate-like particles (cocoliths) of calcium carbonate from the skeletons of marine organisms, which became compacted and cemented to form rock with a higher primary porosity - this shown in Figure 1. Limestone is generally formed by the deposition of fine carbonate mud with associated fragments of biogenetic material (shells, etc) which is compacted to form rock.1,2 Such a limestone reservoir would generally have a low primary porosity but a high secondary porosity owing to the dissolution of some of the rock caused by reaction of pore fluids during burial. Fluid Flow in Carbonate Reservoirs Flow within carbonate reservoirs generally occurs as a result of fluid flow within fractures (both natural and induced), which enhance production. The fluid flows first through interconnecting pores, and then, second, along the fracture paths to the well bore. The pores formed during sediment deposition are generally poorly connected within carbonate reservoirs resulting in a lower permeability/porosity ratio than for sandstone reservoirs. The deposition of scale, both carbonate and sulphate, within carbonate reservoirs results in a decline in total production rate, with the fractures becoming restricted owing to the deposition of scale as a film. In the smaller fractures, the deposition and restriction of flow could be associated with the migration of scale particles which block, or reduce, fluid paths. Mechanical or acid generated fractures can sustain a significant amount of damage (95% of the fracture face not contributing) before the fluid production from such a well is significantly rimpacted.3

Harsh barium sulphate scaling downhole presents a significant squeeze treatment challenge, particularly with providing and then maintaining scale inhibitor residual concentration for extended period at and above the high MIC demand. The control situation worsens considerably when faced with such a scenario in a high temperature, naturally fractured carbonate well. Conventional dispersive type squeezes have found favour here, however their placement and subsequent rapid return at high concentration can result in low squeeze lifetime, mainly due to poor retention of the inhibitor type. The paper details a solution to the inhibitor retention and high MIC demand challenges via development of a novel precipitation squeeze formulation which utilises the dispersive type scale inhibitor as its primary active. The phase-separating ‘precipitation squeeze’ inhibitor formulation is designed to be deployed via conventional bullheaded squeeze into a high temperature, naturally fractured carbonate well environment. The material will thermally activate causing phase separation and enhanced retention of the inhibitor as its calcium salt. Since the active inhibitor is highly tolerant to calcium, it will return into solution with greater facility than conventional precipitation squeeze analogues, leading to elevated levels of scale inhibitor in solution for extended periods compared to standard chemistries in the same carbonate environment. Simulated carbonate field coreflood tests indicated a 3-4 time squeeze lifetime extension was achievable using this technology, and formation damage assessments indicate no identifiable damage to the core material or fluid throughput. The material is now developed for bulk manufacture and is now in the field awaiting first pilot squeeze deployment at the time of writing this abstract. This novel alternative squeeze treatment shows significant increase in achievable squeeze lifetime compared to existing scale inhibitor chemistries for squeeze deployment in harsh barium sulphate scaling carbonate field deployments. Benefits are logistical, environmental and economic when deploying this technology.