Modelling of Scale Inhibitor Treatments in Horizontal Wells: Application to the Alba Field
Authors: Mackay E. J. , Matharu A. P. , Sorbie K. S. , Jordan M. M. , Tomlins R. 
Published: December 2007

Abstract
Recently there has been a large increase in the number of horizontal and highly deviated wells which are coming onto production in reservoirs with aquifers or where there is water injection. It is envisaged that many of these horizontal wells will produce both oil and brine for an extended period of time and therefore, in many cases, the problem of mineral scale deposition must be solved. The most common method for preventing downhole mineral scale formation is by treating with scale inhibitors in a "squeeze" treatment. However, scale management in long horizontal wells does face several challenges, a major one being the correct placement of the scale inhibitor slug in the formation. This is an important topic, since chemical volumes for such treatments may be large due to the lengths of well which are being considered. Accurate placement is required to ensure that vulnerable well sectors are treated, without wasting chemical in the protection of zones which will not cut water during the lifetime of the squeeze treatment.
This paper presents results from a novel near-wellbore simulator (ASSIST2) which can be used to model placement of scale inhibitor treatments into horizontal wells. A technique for modelling such treatments has been developed which gives an improved understanding of where the chemical will be placed under different injection strategies, and how the placement will impact the return profile (squeeze life). It also allows the engineer to assess the impact of varying such parameters as inhibitor slug volume and concentration, overflush volume, injection rate, etc. Different inhibitor chemicals with known adsorption isotherms can be compared for their performance under the specific reservoir conditions being modelled.
This technique has been applied to model a squeeze treatment in a horizontal well in the Chevron operated Alba reservoir (North Sea) where good production data is available. Connection oil and water flow rates, calculated by a conventional full-field simulation model, have been matched by the near-wellbore simulator, ASSIST2. Once a good match of the production flows was achieved and validated by comparison with production logging data which was available for the well, the model was run to simulate the inhibitor injection and subsequent production periods. Various treatment designs were tested to assess the impact of the controllable parameters listed above. Findings enabled a treatment to be specified which was predicted to increase the squeeze treatment lifetime without increasing the volume of chemical required. This modelled application strategy will also reduce the initial inhibitor concentration spike in the return curve. High concentrations of chemical returning in the first few days of a treatment have been known to cause topside facilities problems in Alba. Thus, the predicted reduction in the spike represents a considerable production advantage in addition to extending squeeze lifetime by reducing early losses of chemical through immediate back-production. The performance of various chemicals under reservoir flow conditions was modelled, with a clear best choice for this particular well emerging as a result of these studies.
Based on the findings of this modelling work, recommendations were made for a squeeze treatment which were implemented in Alba and the resulting field data are presented in the paper.