Application of a Scale Inhibitor Squeeze Model To Improve Field Squeeze Treatment Design
- K.S. Sorbie (Heriot-Watt U.) | MingDong Yuan (Heriot-Watt U.) | M.M. Jordan (Heriot-Watt U.)
- Document ID
- Society of Petroleum Engineers
- European Petroleum Conference, 25-27 October, London, United Kingdom
- Publication Date
- Document Type
- Conference Paper
- 1994. Society of Petroleum Engineers
- 5.6.5 Tracers, 1.8 Formation Damage, 5.2 Reservoir Fluid Dynamics, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.2 Separation and Treating, 3.2.6 Produced Water Management, 1.6.9 Coring, Fishing, 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 4.3.4 Scale
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The most common remedy which is applied to solve mineral scaling problems in water producing North Sea fields is the scale inhibitor squeeze process. The central objective of this treatment is to maintain a sufficiently high level (typically, 2 - 50 ppm) of inhibitor in the produced water to prevent scale formation. The process is often applied in an empirical way although a body of knowledge now exists which allows us to design this process in a more rational engineering manner. This paper presents the results from an experimental and modelling study which aimed to improve downhole scale inhibitor squeeze treatment design by extending the squeeze lifetime in the Alwyn North field.
The model used in this work is a radial single well model for describing scale inhibitor squeeze processes in the near-well formation. In order to carry out the optimisation of the squeeze design, scale inhibitor laboratory core floods were carried out at reservoir conditions in order to derive inhibitor dynamic adsorption isotherms. The model then used the isotherms to perform the prediction of the lifetimes of the multiple scale inhibitor squeeze treatments and to optimise the squeeze operational design. The improved design was then implemented in the Alwyn North field and extended squeeze lifetimes have been achieved in broad agreement with predictions.
The model correctly reproduces the effect of (i) the residual inhibitor left in the formation from the previous squeeze treatment on the lifetime of the subsequent treatment and (ii) the effect of the operational parameters, such as overflush volume, on the squeeze lifetime. Using the first squeeze treatment in the well as the base case, a modified squeeze design (in this case, a larger overflush volume) was recommended based on the model prediction. This recommended design for the inhibitor treatments was implemented in the field by the operator and significantly improved squeeze lifetimes have been achieved.
The approach for squeeze optimisation described in this paper is referred to as the development of a "Field Squeeze Strategy". This, in contrast to the "rule of thumb" empirical approach, offers a systematic and quantitative method to evaluate and improve a scale inhibitor downhole squeeze treatment In addition, this paper also addresses the issue of how fast the formation, where it is cooled by the injected squeeze fluids, would be warmed up during a well shut-in. We intend our findings on this matter to clear up some misconceptions on local formation cooling.
Oilfield water scaling, barium sulphate (BaSO4) scaling in particular, has been causing production problems such as productivity decline in the Alwyn North oilfield in North Sea. The scale deposition in this field is primarily a result of the chemical incompatibility between the reservoir formation connate water and the injected sea water.
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