An Investigation of Near-Wellbore Flow Properties Using Sonic Scanner Measurements and Interval Pressure Transient Testing

Abstract

Wireline Formation Tester (WFT) pretest success ratio (good versus tight pressure points) has been traditionally low in East Kalimantan-Indonesia over decades despite technological advances. One possible reason has been postulated as alteration of near-wellbore formation properties during drilling operations. The relatively tight gas sands are drilled with significant overbalance due to a mix of depleted and virgin zone layers using oil based mud systems. To further investigate possible near formation alteration, an extensive evaluation program was undertaken, using new generation sonic logs, WFT-multi-probe interval pressure transient testing (IPTT) and coring. A Sonic Scanner* survey was conducted in Tunu field to investigate possible nearby formation alteration, followed by MDT*-multi-probe IPTT. The Sonic Scanner dipole radial profiling showed some radial property change at several zones. The altered zone radial extent was quantified. The MDT-IPTT tests quantified the, virgin zone effective gas permeability and permeability anisotropy as well as gave a fair idea of the open hole skin factor. Combination of the results gave altered zone radius, altered zone permeability, virgin zone permeability and anisotropy on a comparative basis between different zones. Moreover, the results from both dipole radial profiling and MDT-IPTT indicated that formation alteration not necessarily increases with overbalance. The results quantified nearby formation alteration, showed this as a possibility and can further help in selecting the best perforation strategy. Introduction In the tight and laminated sands of East Kalimantan, Indonesia, obtaining pressures with Wireline Formation Testers has always been difficult. This naturally affects the success of sampling and downhole fluid analysis performed subsequently after the probe pressure measurements. Until recently, higher temperatures, six inch hole size and Oil Based Mud (OBM) limited the use of dual packer tools in this environment, which could be a better solution depending on the number of test points desired. Though the fine laminations of the tight gas sands is a major reason for observing low success statistics of communicating with the formation, other possibilities have been postulated. One of the possibilities is the alteration of near formation properties due to drilling fluid invasion. Some mechanisms that can cause damage due to OBM invasion are:Emulsion blocking - emulsions may form between the filtrate, formation fluids and connate water.Relative permeability effects - most pronounced in tight, water-wet gas sands where oil based mud filtrate is the third phase introduced into a two-phase system, thereby reducing the relative permeability to gas. This usually results in longer cleanup times, especially in tight formations.iii. Fines migration - another reason for near wellbore formation alteration could be wettability change due to OBM invasion. Such drilling fluids usually have surfactants as additives, and an excess amount may change the wettability of water wet particles in the formation to oil wet. These particles, which are originally immobile may then be mobilized and can cause near wellbore formation damage.iv. Plugging by particulates, particularly fluid loss control additives -certain additives may cause damage by plugging pore throats in an irreversible manner.