How to Drill Mature, Depleted Reservoirs Without Downhole Losses Using Engineered Drilling Fluids

Abstract

Invert emulsion drilling fluids designed with an optimised range of pre-determined sized particulates have been used successfully to eliminate or minimise losses to the formation while drilling depleted reservoirs. Sands can be penetrated with up to 600 bar overbalance without encountering losses or differential sticking. Further, the wells have been drilled at pressures above their natural gradient. Selectively designing these fluids has also made it possible to successfully drill high-angle step-out sections through mature, depleted reservoirs. This paper describes the development and implementation of this technology.Fluid Design Phase - The selection and optimization of type, size and amount of particulates required takes place during the planning stage of the well based on the rock mechanics of the formations to be drilled, drilling fluid properties and the practicalities at the rig site.Execution Phase - Once the fluid design has been finalized, processes and procedures are developed to help ensure that during the project the fluid functions are designed taking account of the practicalities of the actual drilling phase. Recent case histories of the application of this technology are discussed in detail: the first case highlights a severely depleted reservoir in an extreme high-pressure, high-temperature (HPHT) field and the second case relates to extended reach wells drilled through mature reservoirs which can be segmentally depleted. Introduction Drilling severely depleted, mature reservoirs without encountering excessive mud losses, differential sticking or wellbore collapse is a considerable challenge. It can often be the case that reservoir depletion has lowered the fracture initiation gradient (FIG) to less than the mud weight required to prevent wellbore breakout in the cap rock or interbedded reservoir shales where formation pressures are at or near virgin pressure. This means that the operating mud weight window, between the applied drilling fluid pressures and the FIG, either no longer exists or is so vastly diminished that it is no longer possible to operate and remain within it. In order to meet this drilling challenge, wellbore strengthening (stress cage theory) was applied to re-create an operating mud weight window. Much has been written on this subject and it is not this paper's aim to go into great detail on the theory but instead to highlight how this technology was successfully used by a major operator in the UK sector of the North Sea. The two wells that are discussed demonstrate the flexibility of the technology from its utilization on an extreme HPHT well with a severely depleted reservoir to a long step-out well with a segmentally depleted reservoir. Losses on both these wells were viewed as high risk threats, possibly inevitable, yet the correct application of the wellbore strengthening technology helped to ensure that no significant downhole losses were observed. The application of wellbore strengthening technology (Fig. 1) involved the addition of sized particulates to the oil-based drilling fluid. These particulates consisted of graded ground marble (CaCO3) and sized resilient graphitic material (RGM) and were selected (designed) based on the rock mechanics and architecture of the individual well. The strategy was to pre-treat the drilling fluid with the selected particulates before entering the depleted formation and to maintain its designer properties throughout the section. The key to the success of this process depends upon it being preventative, i.e., the particulates have to be present in the correct size range and concentration before fractures are initiated by the excessive circulating pressures.