The Effect of Completion Fluids on Gas/Condensate Reservoir Productivity
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94256, “Impact of Completion Fluids on Productivity in Gas/Condensate Reservoirs,” by H.A. Al-Anazi, SPE, T.M. Okasha, SPE, M.D. Haas, SPE, N.H. Ginest, SPE, and M.G. Al-Faifi, Saudi Aramco, prepared for the 2005 SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 17–19 April.

Gas wells in tight reservoirs often have poor deliverability after drilling and completion operations. This is partially attributed to completion-fluid penetration into the near-wellbore region. This increase in liquid saturation can play a significant role in blocking tight rock because of high capillary forces and vapor pressure. The full-length paper details an investigation of the effect of completion fluids on gas productivity in carbonate and sandstone reservoirs and the feasibility of using various solvents to remove or minimize liquid-blocking effects.

Introduction

Water blocking is a significant issue in horizontal carbonate gas wells where low initial drawdown keeps trapped completion fluids in place for longer periods, reducing productivity. The adverse effect of water blocking increases in the presence of condensate blockage when the bottomhole flowing pressure is below the dewpoint pressure. Water blocking also may reduce gas productivity in fractured gas wells because of fracture-fluid leakoff into the fracture faces. Many fractured wells take a long time to clean up completion fluids.

Also of concern is the potential for water blocking to affect the ability to restore well potential after mechanical workovers. It has been common practice to pump large quantities of low-salinity brine into gas wells during stimulation and remedial work. This practice may require review, especially in horizontal wells and partially depleted areas of the reservoir.

Experimental Procedure

Coreflood Experiments. A gas coreflood apparatus was designed to simulate water blockage occurring in the near-wellbore region in gas wells. Positive-displacement pumps were used to deliver fluids at constant flow rates as high as 400 cm3/min and pressures as high as 10,000 psi. Accumulators with floating pistons rated up to 10,000 psi and 350°F were used to store gases and fluids. The core holder used can accommodate a core plug with a 1.5-in. diameter and a 3-in. length. Pressure transducers were used to measure pressure drop across the core. The flow was downward to eliminate gravity-segregation effects. Two backpressure regulators were used to control the flowing pressure upstream and downstream of the core. The core holder, backpressure regulators, fluid accumulators, and flowlines were inside a temperature-controlled, forced-air-circulation oven.

The core was loaded into the coreholder, and end caps were screwed in place. An over-burden pressure of 4,000 psig was applied. The coreholder was placed inside the oven and incubated for 5 hours to ensure that it reached the desired temperature. Pressure of the backpressure regulators was adjusted to 1,500 psig. Flowlines were pressurized by nitrogen to the desired flowing pressure.

Gas permeability was measured using nitrogen at 1,500 psig flowing pressure and 230°F. Several completion fluids and solvents were stored in a separate rodded-piston accumulator. Each accumulator was placed vertically inside the oven and connected to a pump. The core then was flooded with a completion fluid to establish an initial liquid saturation. Nitrogen gas was flowed to displace the liquid from the core and determine the effect of liquid saturation on core permeability.