Modelling Scale Inhibitor Squeeze Treatments in Horizontal Wells: Model Development and Application

Abstract

Abstract This paper addresses the issue of downhole mineral scale prevention in horizontal wells. This may be prevented in many field cases by the use of chemical scale inhibitors applied in "squeeze" treatments. From the limited field experience of scale treatments in horizontal wells, it appears that strategies which have been applied quite successfully in vertical wells must be modified or sometimes abandoned in the treatment of horizontal well scaling problems. The main objective of this paper is to establish a numerical modelling approach for the analysis and design of the field squeeze strategy for horizontal wells in different types of formations. A two-phase, multi-component near-well simulator has been developed for modelling scale inhibitor squeeze processes for horizontal wells. In addition, this simulator models the temperature field and the inhibitor transport, including adsorption/desorption, precipitation/dissolution and dispersion behaviour, within the near-wellbore formation. This near-well process model is driven by the production data obtained either from a conventional full field reservoir simulation or from a field measurement where this is available. Application of the modelling approach to a real layered heterogeneous reservoir is presented. Different horizontal production well placement and drive mechanisms are assessed with a view to obtaining the water breakthrough profiles along the well length as a function of time, Qw(z,t). Various scale inhibitor squeeze treatment strategies are then simulated to examine the key factors that govern the squeeze process in horizontal wells. The main contributions of this work are (i) the provision of simulation tools for designing and assessing the performance of squeeze treatments in horizontal wells; (ii) a demonstration of how these tools should be applied in a field case; (iii) a clear pinpointing of the key data that is required in order to design such treatments; (iv) a discussion of the implications of these results for the development of related technologies. Introduction and Background The improvement in oil recovery and project economics obtained with horizontal wells has led to an increasing interest in this technology. The main benefits of horizontal wells over vertical wells in certain circumstances have been identified in the literature in some detail. Horizontal wells can give an opportunity for substantial increases in productivity and sweep factor per well because of the long lengths of producing contact with the pay zone which are possible. This attribute of horizontal wells gives clear productivity advantage for tight reservoirs with distributions of low permeability regions. In practice, wells are drilled horizontally (or near horizontally) to take advantage of one or more of the following features:increased exposure of reservoir rock to the wellbore for improved inflow performance;the ability to connect laterally distributed reservoir features (e.g. sand lenses, reservoir compartments, naturally fractured systems);changed drainage geometry with the horizontal well being parallel to fluid contacts. Although there already exists an extensive published literature on the development of horizontal well technology, very few of the existing publications deal with the production operations and well intervention aspects of horizontal wells in the period after water breakthrough has occurred. However, the maturity of horizontal well technology in the North Sea oil industry has been such that a number of production chemistry problems associated with water breakthrough in horizontal producers have arisen. If given horizontal wells are to have an extensive period of operation with an increasing watercut, it is clearly necessary to consider how mineral scaling problems which may occur in the near wellbore area and tubulars are to be tackled. Factors affecting scale formation and the prediction of the compositions of the resulting scales have been described in more detail elsewhere. P. 853