TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDue to the increased cost of scale management in subsea compared to platform or onshore fields, and because of the more limited opportunities for interventions, it is becoming increasingly important to carry out a risk analysis process for scale management as early as possible in the field development plan. This process involves identifying the potential scale risks, and analysing and comparing the options available for managing those risks.This paper discusses how this risk analysis process should be carried out, with a strong emphasis on the need to integrate all the available production chemistry and reservoir engineering data. To demonstrate this process, an example from a development complex, which lies in >400 m (>1300 ft) water depths offshore West Africa, is used. The process has involved the following steps:Analysis of available brine samples to identify maximum scaling potential. Laboratory testing of available scale inhibitors to identify chemistry best suited to this system. Study of analogue fields to identify scaling risks in these fields, and how these risks have been managed, with implications for fields currently being studied. Modification of full field reservoir simulation model to predict seawater breakthrough and duration of seawater production, to identify when, for how long, and using how much inhibitor the wells would require squeeze treatments to control scale. This process involves using flow profiles derived from the reservoir simulation model, and applying them in a near well squeeze simulator to predict treatment performance to minimum inhibitor concentration measured from laboratory studies. Well-by-well analysis of predicted seawater production profiles and total water production rates to identify

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPrecipitation of mineral scales causes many problems in oil and gas production operations: formation damage, production losses, increased workovers in both producers and injectors, poor injection water quality and equipment failures due to under-deposit corrosion. The most common mineral scales encountered with downhole and topside processes are sulphate and carbonate-based minerals. The development over the past few years of fields where high temperature and high salinity brines are being produced with associated hydrocarbon has presented a more challenging environment for scale management. In such fields hydrogen sulphide gas is quite a common component of the produced fluids.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn this paper we describe the development of a novel water-inoil emulsion system for the deployment of aqueous-based production chemicals.The non-aqueous nature of the emulsion system potentially allows ingress of the chemical into parts of the reservoir normally denied access to an aqueous-based formulation and so can improve contact between the chemical and the reservoir fluids on production. Furthermore, the whole treatment can be deployed as a nonaqueous package allowing oil continuity to be maintained during the treatment. This can (i) prevent changes in the near well-bore relative permeability arising from the influence of the injected fluids; (ii) prevent water becoming trapped in oilbearing zones reducing permeability to oil; and (iii) improve production chemical penetration depths (the water-wet nature of sandstone reservoirs means that the penetration depth of, for example, scale inhibitor solutions can be low). Moreover, for poor pressure support reservoirs, the reduced density of a nonaqueous treatment can obviate the need for artificial lift to restart the well. Originally developed for scale inhibitor deployment, this technology has been advanced by developing slowly degrading emulsion systems, which provide a means of trapping the aqueous production chemical within the porous media and allowing subsequent controlled release of the chemical. This advanced scale control technology has been proven in the laboratory for the encapsulation of corrosion inhibitors, biocides, hydrogen sulphide scavengers, and chemicals for the control of reservoir souring. Encapsulated scale inhibitors have been field deployed in two locations (in the UK sector of the North Sea and in the demanding environment of onshore Alaska under both high water cut and very low water cut conditions). This paper describes laboratory testing, including coretests, and describes the planning, the execution, and the results of the field treatments.

The injection of seawater into oilfield reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature, operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. However, the current drive within the North Sea to reduce the environmental burden of production chemicals and to reduce oil discharge to the environment has focused attention on the challenge of produced water management and has introduced new challenges for scale management involving produced water re-injection. This paper will outline the risk assessment process required prior to undertaking produced water re-injection. The factors that will be considered are the location of scale deposition around fractured and unfractured injection wells, formation damage potential and impact, and retardation effects on injected scale inhibitors. The paper will draw upon computer modelling techniques, laboratory generated coreflood data, and field results that will demonstrate the impact of the following factors on long term water injectivity: viz, scaling tendency, suspended solids content, suspended oil content, injection temperature, reservoir type, and completion type. Furthermore, scale control measures currently being employed (e.g., scale inhibition, hydraulic fracturing, drag reduction, and solvent cleaning) will be assessed and reviewed against the risks identified. Finally, this paper will outline in detail the particular scaling issues associated with produced water re-injection for both platform and subsea facilities. Introduction Increased environmental concern for the effects of produced water discharges is increasingly encouraging operators to dispose of produced water by re-injection either into the oil-bearing formation or into a specially selected aquifer. In addition to the environmental benefits of produced water re-injection (PWRI), there are other potential benefits including making cost, space and weight savings through the optimisation of water treatment facilities and produced water re-injection system throughout the life of a field. Re-injection of produced water is performed in several locations around the world. BP, for example, was an early adopter of the technology with re-injection schemes in Prudhoe Bay and the Forties Field in the early 1990's and the Ula Field in the Norwegian sector of the North Sea from the mid-1990's1–4. Today, BP has a corporate goal of eliminating all discharges to the sea by 2004. Early experience of PWRI was focused on individual wells and did not include the co-mingling of produced water with seawater. With the move to full-field PWRI and the requirement to maintain voidage replacement, there is an increasing requirement to either co-mingle the fluids prior to injection or to inject both seawater and produced water into the same reservoir but via separate wells. Such practices introduce scale formation risks. These can be both calcium carbonate formation arising from the produced water itself and sulphate scales arising from the co-mingling of barium, strontium, and calcium containing produced waters with seawater. Clearly, the formation of such scales poses a risk to the topside injection system, the injection well itself, and finally the near-wellbore. Managing these risks is critically important to effective field management (in terms of being able to maintain adequate water injection) and to being able to maintain a zero water discharge commitment. This paper addresses methods of assessing the risk that scale poses to PWRI schemes and outlines the various management options that are available. The overall process and methodology is illustrated by field examples from the North Sea Basin. Risk Assessment Field Experience Under favourable operating conditions, the risk of scale damage to produced water re-injection wells should not be significant. However, it is possible that under certain injection conditions rapid build-up of scale could lead to complete loss of injectivity. Avoiding such a catastrophic scenario is the objective of the risk assessment process. The preliminary step is to study field case histories. This is then followed by the procedure of calculating potential scaling scenarios using scale prediction codes and fluid flow simulations to evaluate the risk. Field Experience Under favourable operating conditions, the risk of scale damage to produced water re-injection wells should not be significant. However, it is possible that under certain injection conditions rapid build-up of scale could lead to complete loss of injectivity. Avoiding such a catastrophic scenario is the objective of the risk assessment process. The preliminary step is to study field case histories. This is then followed by the procedure of calculating potential scaling scenarios using scale prediction codes and fluid flow simulations to evaluate the risk.