High Density Brine-Based Drill-In Fluid Improved Reservoir Producibility in Gas Field Offshore Egypt

Abstract

Abstract Quick clean up and dramatic improvements in reservoir producibility have been achieved in gas wells located offshore Egypt. These wells were drilled and completed using an engineered drill-in fluid system. The fluid formulation was carefully designed and extensively tested in three different laboratories prior to the field applications to help ensure reproducibility of the data and to verify the non damaging characteristics of the fluid. These tests were conducted under simulated downhole conditions to help ensure fluid compatibility with the reservoir rock minerals and natural fluids. To help minimize fluid invasion while drilling in the payzone section, the optimal concentration and particle size distribution (PSD) of the suspended bridging material were selected and maintained during the field applications. The PSD of pure ground marble was selected based on the reservoir rock morphology and average pore size to establish effective bridging near the wellbore and help ensure quick lift-off of the filter cake. A high-density calcium chloride / calcium bromide brine blend (14–14.5 lb/gal ~ 1.68 sp.gr.-1.74 sp.gr.) was used as the base fluid to achieve and maintain the required fluid density without additions of insoluble weight material. Optimal concentrations of non-damaging temperature-stable polymers were used to provide suspension and filtration control. The gas reservoir section was drilled and completed in several wells with the new system. Productivity index and flow rates exceeded the operator's expectations without any stimulation treatments. Substantial savings were realized in terms of rig time and well completion costs. This paper presents the laboratory and field-generated data and discusses the key issues in designing and monitoring the new drill-in fluid during the field applications. Introduction One of the keys to optimizing wellbore connectivity and retaining the natural reservoir rock permeability is to ascertain and quantify the complex, often interdependent physical interactions and chemical reactions occurring downhole between the reservoir rock fluid and minerals and the drill-in / completion fluids used 1,2,3. Some of the most common ways of damaging a formation include pay zone invasion and plugging by fine particles, formation clay swelling, commingling of incompatible fluids, movement of dislodged formation pore-filling particles, changes in reservoir rock wettability, and formation of emulsions or water blocks. Once one of these damage mechanisms diminishes the permeability of a reservoir, it is seldom possible to restore it to its original condition. Reservoir characterization and sensitivity studies were carried out to identify and quantify the geologic parameters that could influence the producibility of the Miocene sandstone gas reservoirs in an offshore field in Egypt. The field is located in the Mediterranean Sea, 35 miles north of Port Said City, at the northern entrance to the Suez Canal (Figure 1) The fluid sensitivity study included thorough examination of the rock morphological and mineralogical composition 4,5. Core analysis data was generated by specialized core laboratories for core plugs from carefully selected sections of the gas zones. The natural reservoir fluid was also analyzed to establish their chemical make-up. These data helped determine the reservoir's potential for formation damage problems. Based on the information and the reservoir rock data, a brine-based drill-in and completion fluid was designed and tested, under simulated downhole conditions. These tests were conducted in Baroid's Houston lab, Baroid's Cairo lab, and Eni E&P Milan lab to ensure reproducibility of the lab test data and verify the non damaging characteristics of the selected additives and fluid formulation.