Abstract

This paper presents both field and laboratory data regarding leak off properties from Liquid CO2 and Liquid CO2 / N2 fracture treatments. The laboratory testing was performed by the Alberta Research Council using special equipment to handle the low viscosity low temperature frac fluid under pressure. Pressure transducers and thermocouples were placed along the core to specifically examine the effect of phase change leak off. Based on mechanisms identified by the experiments, numerical core flow studies were also performed to compare the ability of CO2 and natural gas to remove saline solution from the core and the corresponding permeability improvement. Field measurements were made on several fracture treatments using bottom hole pressure and temperature recorders.

Tests using the combined CO2 / N2 mixture showed that its leak off behavior is similar to that of 100% CO2 however lower values of "spurt loss" were indicated. The tests also showed that the majority of the pressure drop across the length of the core occurred where the liquid CO2 flashed to a vapor state. Thus the experiments confirmed that the expansion of CO2 from a liquid to a vapor was a significant mechanism in reducing the leak off under test conditions. Finally, the tests indicated that CO2 has the ability to reduce water saturation in porous rock beyond the connate level achieved with pure natural gas. This should enhance the increase in gas production obtained from the fracture treatment.

Introduction

A series of 8 experiments were performed at the Alberta Research Council to provide insight into CO2 leak off into the surrounding reservoir during Canadian Fracmaster's Liquid CO2 fracturing process. Core temperatures and pressures and the CO2 leak off rate were recorded during exposure of the core to liquid CO2 at 10 MPa for 5 minutes. The effects of reservoir properties (CH4 saturated cores versus cores containing water in addition to CH4), fracture fluid temperature, and fracture fluid type (Liquid CO2 versus Liquid CO2 /N2) were investigated.

Reservoir Characteristics

The experiments were based on fracturing operations on the Belly River Gas formation in SE Alberta. This formation is "predominantly interbedded mudstone to very fine grained sandstone1 " it has a permeability or 2 – 40 md, an average net pay of 10 m, and a depth of 550 m. Formation pressure during a typical Liquid CO2 fracture job is in the range 1 – 2 MPa.

Cores Used

The Berea sandstone cores were 3.8 cm in diameter and had a length of 30.48 cm and a volume of 347.5 cm3. The bulk density of the cores used was 2.18 g/cm3. The absolute permeability of the cores was 120 md. After a core was flooded with methane following saturation with saline solution (4300 PPM) its permeability to methane was 6 – 8 md. The water saturation following flooding with saline solution and CH4 was 49%. A NaCI concentration of 4300 PPM was selected to minimize fines movement during flooding (based on Khilar's experimental results2).

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