Modelling Scale Inhibitor Squeeze Treatments in High Crossflow Horizontal Wells

Abstract

Abstract Modeling scale inhibitor treatments in horizontal wells is emerging as an important field of research due to the need to reduce the cost of treating wells that may be thousands of feet long. Simulation studies performed using recently developed modeling tools have led to recommendations that have reduced the risk of chemical upsets at the wellhead and extended squeeze lifetimes downhole. However, as an increasing number of "problem wells," such as high crossflow wells, need to be treated to prevent scale formation, these models have to be adapted to enable them to capture the complex range of properties that make these systems so problematic. Diverter technology is being developed to enable optimal placement of chemical inhibitor, but to study the impact of the diverter on the squeeze performance, the fluid flow properties in the near-wellbore region must be modeled accurately. This is done by using a full-field reservoir simulation model that includes sufficient detail in the near-well formation not only to capture the fluid flows, but also to model accurately the chemical placement and recovery. The model can assess the impact of various placement strategies, as well as assist in determining the optimal fluid and chemical volumes. A case study from the North Sea where a gel diverter was selected to assist inhibitor placement is presented. The study demonstrates the types of calculation that can be made, and what information can be usefully supplied to the field engineer designing squeeze treatments. Introduction Mineral scale deposition in the near-wellbore area and tubular is a problem encountered in all types of production wells in the period following water breakthrough(1–3). Squeezing scale inhibitors into the near-wellbore formation is a strategy that has been used to successfully protect many hundreds of vertical wells(4–7). The squeeze treatment involves injection and over flush of a water-soluble chemical inhibitor that adsorbs onto the rock surface during a post-squeeze shut-in period. When the well is returned to production, the inhibitor slowly desorbs from the rock surface into the flowing water phase, and enters the well. Provided an appropriate choice of inhibitor is made, and provided it has been placed correctly, scaling tendencies in the produced water will be inhibited by the returning chemical for as long as its concentration remains above a threshold value(6,8). This Minimum Inhibitor Concentration (MIC) is routinely determined from laboratory Measurements(9). Modeling techniques have been developed to assist the design of squeeze treatments(10–14). Use of these models for optimizing treatments in vertical wells has proved very successful, and simulations are often performed as a matter of routine when designing treatments. However, the long production intervals associated with horizontal and deviated wells, along with the possibility of extended production at high water cuts, can make the design of squeeze treatments in these wells much more difficult. In addition, the increased capital investments and higher production rates associated with horizontal wells mean the risk of scale forming in the wellbore is even less tolerable than for conventional wells.