SPE Production & Operations
Volume 25, Number 1, February 2010, pp. 40-49

Summary

Drilling the U-formation (shale and sandstone) in Saudi Arabia requires high drilling fluid density (±95 lbm/ft³) to mechanically stabilize the shale and balance the reservoir pressure. Two fluids have been used to drill this formation: KCl/BaSO₄/CaCO₃ and potassium formate/CaCO₃ drilling fluids. Barite is added in the first fluid with CaCO₃ to reduce the amount of solids needed to formulate the drill-in fluid. However, BaSO₄ is insoluble in acids and requires chelating agents (DTPA) to remove it from the formation. Formate drill-in fluids with low solids content can be used, but they are expensive and corrosive at pH values less than 7–8. A third drilling fluid was developed recently by Al-Yami et al. (2007) to overcome some of the problems associated with these two systems.

The objectives of this study are to determine solids invasion and damage characteristics for the three fluids. Coreflood tests were conducted using reservoir cores at bottomhole conditions. The cores were then examined by environmental-scanning-electron-microscope (ESEM) analysis to investigate solids invasion, solids type, and location of damage.

The three drilling fluids examined did damage the core plugs either through external filter cake, internal filter cake, or both. The ESEM images showed that the least damage occurred when Mn₃O₄ water-based drill-in fluid was used. The highest damage was observed when barite/CaCO₃ mud was examined. This was followed by the potassium formate drill-in fluids. Kaolinite booklets were not attacked by the filtrate of the three drill-in fluids examined. The damage that was noted with potassium formate mud resulted from incompatibility of mud filtrate with the formation brine where potassium chloride crystals were noted in the cores.

Introduction

There are six scenarios in which drilling fluids can cause damage to the formation (Bishop 1997):

1. Fluid-to-fluid incompatibilities (e.g., emulsions generated between invading oil-based-mud filtrate and formation water).
2. Rock-to-fluid incompatibilities (e.g., contact of potentially swelling smectite clay or deflocculatable kaolinite clay by nonequilibrium aqueous fluids, such as fresh water, that have the potential to reduce near-wellbore permeability severely).
3. Solids invasion (e.g., the invasion of weighting agents or drilling cuttings into the formation).
4. Phase trapping/blocking (e.g., the invasion and entrapment of water-based fluids in the near-wellbore region of gas wells).
5. Chemical adsorption/wettability alteration (e.g., changes in the wettability and fluid-flow characteristics in the critical near-wellbore area because of emulsifier adsorption).
6. Biological activity (e.g., the introduction of bacteria into the formation during drilling and the subsequent generation of slimes, which reduce permeability).

Moreover, in overbalanced drilling, solids invade the formation. The invading particles, which are suspended in the drilling fluid, tend to plug pore throats and cause formation damage. To minimize formation damage, properly sized bridging material should be large enough not to invade the formation, and it should form an effective filter cake to prevent solids and mud-filtrate invasion (Bailey et al. 1999). Zain et al. (2001) developed a model to show that solids particles with smaller diameter than pore-throat size will enter the rock and reduce permeability. The depth of invasion by solids in drill-in fluids will indicate the required flow-initiation pressure.

In the present study, three water-based drilling fluids were examined using sandstone reservoir cores. Potassium chloride was added to the three fluids to control clay swelling and fines migration. The objective of this work is to examine solids invasion and damage characteristics that can occur with the three drilling fluids. ESEM analysis was used extensively to determine the nature and depth of the damage.

© 2009. Society of Petroleum Engineers

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History

• Original manuscript received: 13 August 2008
• Meeting paper published: 11 October 2008
• Revised manuscript received: 5 March 2009
• Manuscript approved: 20 March 2009
• Published online: 25 November 2009
• Version of record: 1 March 2010