CO2-Energized-Acid Treatment Reduces Freshwater Use, Boosts Well Performance

Abstract

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 172620, “Successful Implementation of CO2-Energized-Acid Fracturing Treatment in Deep, Tight, and Sour Carbonate Gas Reservoir in Saudi Arabia That Reduced Freshwater Consumption and Enhanced Well Performance,” by Ataur R. Malik, SPE, Alaa A. Dashash, Saad M. Driweesh, SPE, and Yousef M. Noaman, SPE, Saudi Aramco, and Eduardo Soriano, SPE, and Alfredo Lopez, Halliburton, prepared for the 2015 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 8–11 March. The paper has not been peer reviewed. Carbon dioxide (CO2) with 30% foam quality (FQ) has been introduced for the first time during acid fracturing treatments in a tight, sour, high-pressure/high-temperature carbonate gas reservoir in Saudi Arabia to reduce consumption of fresh water, minimize reservoir damage, reduce the flowback period, and eliminate the need for nitrogen lifting with coiled tubing. The addition of liquid CO2 to hydrochloric acid (HCl) in quantities sufficient to produce emulsion allows live acid to retard and penetrate much deeper than HCl alone. Introduction Gases were introduced to the oil and gas industry primarily as an aid to recover pumped stimulation fluids. This application still accounts for the majority of use of nitrogen and CO2. Special applications, such as foaming stimulation fluids, have reduced consumption of the liquid phase significantly. Stimulation activities have been increasing dramatically in Saudi Arabia. During each stage of fracturing stimulation in Saudi Arabia, up to 3,000 bbl of groundwater is used. Up to 70% of that groundwater consumption can be reduced through the CO2-foam fracturing treatment. The application of CO2 also reduces the flowback period and eliminates the need to perform coiled-tubing nitrogen lifting, which is a unique requirement for tight and depleted reservoirs. The addition of liquid CO2 to HCl in quantities sufficient to produce viscous foam (emulsion) is one of the more significant improvements in recent years. The addition of CO2 to acid accomplishes the following: It increases the viscosity of the commingled fluid. It controls leakoff of acid. Most CO2 foamed-acid treatments are performed at matrix rates. It can easily be pumped at fracturing rates. The fracture length is determined by acid reaction rate, injection rate, fracture width, and rate of fluid loss from the fracture to the formation. It dramatically increases the efficiency of HCl. Laboratory testing with cores from the canyon reef formation indicates an improvement in penetration of live acid of almost ninefold over a conventional acid system. It cleanses the formation. Many formations are only partially soluble in HCl. The energy and viscosity of the foamed acid aid in removal of these undissolved fines from the formation. The CO2 also strips hydrocarbon from the rock, exposing it to dissolution by the acid. It improves formation permeability by the removal of stimulation and connate fluids. It dissolves more rock. An 80%-quality foam (only 20% of the volume is acid) has been proved to remove as much rock as when the entire solution is acid. It reduces or eliminates the need for swabbing. The load to recover is significantly lower than a conventional-treatment volume. The balance of the treatment (the CO2) will vaporize and aid in the recovery of undissolved fines, spent acid, and flush volumes. Because CO2 at the surface is above the critical pressure (1,071 psi) but below the critical temperature (87.8°F), CO2 is pumped into the wellbore as a liquid. It remains a liquid until heated by the formation downhole. Conversion of CO2 to a gas downhole causes no disruption of the two-phase fluid because supercritical CO2 has a high density and no abrupt expansion of CO2 occurs.