Abstract
Umm Gudair field, West Kuwait onshore field has been on production for more than 60 years. MN-Oolite is an upper cretaceous carbonate reservoir, and it is the main reservoir in Umm Gudair Field. After a lengthy period of production, water production began to constrain and restrict oil production, and as a result, water production drastically raised the total operating costs of the field and overburdened the surface facility. In addition to this excess artificial lift horsepower demand for lifting fluids, corrosion-related concerns and well completion damage are on the rise.
In Um Gudair field, several mechanical and chemical water shut-off procedures were applied. Some of them were quite efficient and commendable in terms of increasing oil potential and decreasing water cut. However, this is not the case for all wells in the field; certain wells did not respond adequately to the mechanical water shutoff, primarily due to the conning effect, and required a different water shutoff strategy. In such situations, limiting water output by lowering the influence of water coning necessitates the use of a chemical polymer to form a chemical barrier.
This paper discusses the lessons gathered from more than 30 polymers water shut-off projects undertaken in Umm Gudair field during the past three decades. A rigorous research was undertaken with a precise diagnosis, information integration, and historical well work-over and completion, production, and reservoir data integration. All data is centralized, processed, and reviewed prior to and after water shut-off treatments in order to extract lessons learned for future projects.
The study indicates that the crosslinked polymer treatment is beneficial for a period of time in reducing water generation. In certain circumstances, the water cut may progressively increase, and in some cases, it will reach the pre-treatment level. In addition, the results indicate that the cross-linked polymer can improve well integrity by obstructing tiny cement channels. With high production rates, a high oil viscosity ratio, and high vertical to horizontal permeability in the reservoir, the severity of the water cone influences the polymer, and it is increasing. The success of the treatment is contingent on a number of factors, including the depth of polymer penetration in the formation, rock petrophysics, formation heterogeneity, polymer characteristics, and the correct operation techniques and implementation.
