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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.

Summary With the development of more and more subsea fields, the challenge for scale-inhibitor squeeze treatments is to reduce intervention frequency by extending squeeze treatment lifetime while concomitantly reducing any potential damage in both low water-cut and high water-cut wells. This paper discusses the technical problems and examines new technologies for treatment of such production wells through their life cycle. This paper covers the findings from late 2001 through early 2002. Because even newer technologies have been developed since the writing of this paper, it should be read as the history of technological development. Scale control technology available to control scale formation within the reservoir and near-wellbore area of production wells will be outlined with a focus on the current developing technology to control scale within low water-cut wells. Moreover, this paper shows that the new technical area of emulsion-scale-inhibitor-delivery systems, originally designed to control scale within low water-cut wells, has applications in both low and high water-cut wells. This study assists in developing an understanding of the mechanism of interaction of emulsion-based products—in particular, the impact of the level of water saturation within the core system. In addition, it demonstrates that the emulsion particles are retained in the core matrix during both crude and brine flowback. This paper indicates that the emulsion product offers the potential for extremely long squeeze lifetimes with minimal damage in oil-production wells with rising water cut. It also demonstrates how different technologies have their own place in the life cycle of a production well. Introduction Flow assurance is an essential aspect of the economic production of crude oil. It can be considered the ability to produce petroleum fluids economically from the reservoir to a production facility over the lifetime of a field. Scale control is one of the key aspects of the flow-assurance issue. The increasing number of subsea fields, together with deepwater production, raises particular issues and evolving challenges for flow assurance beyond those seen for simple vertically drilled wells. The complexity of new well completions in terms of horizontal and multilateral wells, subsea tiebacks, and commingled flow presents particular challenges. Where scale-inhibitor treatments are required for such complex wells, they are often associated with very high intervention costs. Scale control issues need to be addressed as part of asset life cycle management, whereby the issues are tackled before field development/production [i.e., capital expenditure (capex) phase] rather than being reactively confronted once water breakthrough occurs [operational expenditure (opex) phase]. Such an approach allows for the selection of an appropriate economic technology. Indeed, the anticipated problems may influence the plans to develop a field, for example, in terms of water-injection strategies or implementing appropriate technology upon well completion. Scale control within life cycle management is based on varying challenges seen with the increase in water cut as a field and its wells move from dry production to high water cuts. This is associated with four phases of field development—project, plateau, decline, and decommission (Fig. 1). At the project stage, scale control treatment strategies can be developed. The scale issues at subsequent stages depend on the nature and severity of the anticipated scale problem. Fig. 2 outlines the scale issues associated with the injection of seawater into a reservoir with barium and bicarbonate present in the formation water. The process of evaluating the risk of scale in a field under appraisal is briefly outlined below. The factors to be taken into account when evaluating the risk of scale formation and control are described in detail, along with currently available technologies and the gaps that exist in a recent SPE publication (Jordan et al. 2001).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWith the development of more and more subsea fields, the challenge for scale inhibitor squeeze treatments is to reduce intervention frequency by extending squeeze treatment lifetime whilst concomitantly reducing any potential damage in both low water cut and higher water cut wells. This paper discusses the technical problems and examines new technologies for treatment of such production wells through their life cycle.Scale control technology available to control scale formation within the reservoir and near-wellbore area of production wells will be outlined with a focus on the current developing technology to control scale within low water cut wells. Moreover, it is shown that the new technical area of emulsion scale inhibitor delivery systems, originally designed to control scale within low water cut wells, has application in both low and high water cut wells This study assists in developing an understanding of the mechanism of interaction of emulsion-based products; in particular the impact of the level of water saturation within the core system. In addition, it demonstrates that the emulsion particles are retained in the core matrix during both crude and brine flowback. This paper indicates that the emulsion product offers the potential for extremely long squeeze lifetimes with minimal damage in oil production wells with rising water cut. It also demonstrates how different technologies have their own place in the life cycle of a production well.