Application of a new reduced‐complexity assessment tool to estimate CO₂ and brine leakage from reservoir and above‐zone monitoring interval (AZMI) through an abandoned well under geologic carbon storage conditions

Abstract

This study employs a combination of detailed simulations and reduced‐complexity models in the Well Leakage Analysis Tool (WLAT), developed by the National Risk Assessment Partnership (NRAP), US Department of Energy, to investigate how the rates of CO2 and brine leakage through an abandoned well under geologic CO2 storage conditions are affected by various factors. The factors considered in this study include depth of well penetration into the storage system, location relative to the point of injection, and effective permeability of the abandoned well. Location is the primary factor used to identify high‐ and low‐risk abandoned wells. For the typical CO2 injection scenario considered in this study, the potential impact of CO2 and brine leakage through an abandoned well is very low if the abandoned well is 6.2 km or further away from the CO2 injector. Due to the buoyancy of CO2 relative to formation brine, wells intersecting (i.e., accepting flow from) the top of the above‐zone monitoring interval (AZMI), which is the interval immediately above the seal, have a higher chance to become a pathway for CO2 than wells intersecting the bottom of the AZMI. If the permeability of an abandoned well is 10−14 m2 or less, the risk of CO2 and brine leakage through the well becomes very low. Due to the combined effect of pressure increase and buoyancy, the CO2 leakage rate is higher than brine leakage rate within the CO2 plume extent. Specific values reported in this study are site‐specific results and cannot be regarded as general findings. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

Experimental Investigation on the Effects of CO2 Displacement Methods on Petrophysical Property Changes of Ultra-Low Permeability Sandstone Reservoirs Near Injection Wells

“…The experimental results of core HU24-1 indicate that the injection flow rate do not induce velocity sensitivity, and the brine do not cause the expansion of clay minerals under the experimental conditions, eliminating the interference of brine on the experimental results during the flooding process. The permeability of the cores HU24-2 and HU24-3 decrease after flooding, but the porosity is unchanged, which is similar to the results of previous experiments [9,15,19,[35][36][37][38]. Those studies believe that CO 2 is injected into the core and dissolved into brine to form carbonic acid, which triggers CO 2 -brine-rock interactions.…”

“…Due to the significant oil displacement characteristics of CO 2 , the injection of CO 2 into oil reservoirs for storage not only significantly increases the production of oil, but is also an effective means of controlling CO 2 emissions to reduce the greenhouse effect. Among the displacement methods, CO 2 flooding and CO 2 -WAG flooding are two common displacement methods used in oilfields, CO 2 -WAG flooding is superior to CO 2 flooding in sweep efficiency and has a better effect on EOR, but the injection of fluid is more difficult [1][2][3][4][5][6][7][8][9]. However, no matter which displacement method is used, when CO 2 is injected into the formation, a series of physical and chemical reactions (CO 2 -brine-rock interactions) are triggered, changing the physical properties of the reservoirs [10][11][12][13][14][15].…”

Field‐scale well leakage risk assessment using reduced‐order models

“…Consequences of leakage can be presented in the form of leaked volume to shallow fresh water aquifers or to the atmosphere. Researchers have also used numerical modeling techniques for well leakage analysis . Nogues et al .…”

“…1,6,7 The benefits and drawbacks of selecting a depleted oil and gas field as a potential storage site should be Depending on the structure of a well, its proximity to injection wells, the storage zone's pressure buildup, and the nature of the CO 2 spread in the field, wells coming into contact with the CO 2 plume may act as possible leakage pathways. 8,[12][13][14][15][16] The nature of the leakage pathways in a well, e.g., fractures in the cement sheath or along the cement-casing interface, corroded casing, and/or rock damaged by drilling activities, 17 can significantly affect the leakage potential of a well. 9,[17][18][19][20] For brine leakage, the pressure differential and a wellbore offering the least resistant path to flow may be the only necessary conditions for leakage to occur.…”

“…Researchers have also used numerical modeling techniques for well leakage analysis. 9,16,46,[52][53][54][55][56][57][58][59][60][61][62] Nogues et al 46 proposed a simplified formulation to estimate leakage along old wells and pointed out that there could be high uncertainties associated with different parameters in the estimation of maximum probable leakage. Gaurina-Međimurec and Mavar 63 investigated the CO 2 leakage risk from a storage zone looking at different leakage sources and categorized the leaks according to their severity.…”