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Gases can migrate into the cemented annulus of a wellbore during early gelation when hydrostatic pressure within the cement slurry drops. Different means to describe hydrostatic-pressure reduction have been proposed and reported in the literature. Among them, static gel strength (SGS) is the most widely accepted concept in describing the strength development of hydrating cement. The classic shear-stress theory uses SGS to quantify the hydrostaticpressure reduction in the cement column. Approaches derived from the concept of SGS have contributed to understanding mechanisms of gas migration and methods of minimizing it. Unfortunately, these approaches do not accurately predict gas migration. Although SGS was originally adopted to describe the shear stress at interfaces, it has also been used to estimate the shear resistance required to deform slurry during the hydration period. Before early gelation, the hydrostatic pressure will overcome the formation gas pressure and prevent gas migrations. During gelation, the cement develops enough rigidity to withstand the gas invasion. This critical hydration period is defined as the transition time. API STD 65-2 (API 2010a) provides standards for determining the transition time by use of the concept of SGS. Current industry practice is to reduce the transition time, thereby lowering the potential for invading gas introducing migration pathways in the cemented annulus. This approach, although certainly helpful in reducing the risk for gas migration, does not eliminate its occurrence. Experimental results presented in this study demonstrate that the relationship between SGS and hydrostatic-pressure reduction is not linear. Characteristics of the transition-time endpoints depend on slurry properties and downhole conditions. Moreover, SGS is not able to characterize the gas-tight property of a cement slurry. When slurry gels, the mechanical properties are governed by its growing solid fraction. The gel can deform under shear loading, but gases and other fluids will need to break or fracture the bond between solids and push them aside for pathways to form within the cement/matrix domain at this point. To fully understand this process, the bond strength between solid particles and the compressibility of the cement matrix are needed. The bond strength and compressibility are mechanical properties dependent on the changing rigidity of the gelling cement. However, SGS does not address these important properties and, therefore, SGS is limited in its ability to predict gas-migration potential. A better means to characterize the cement/matrix strength by use of fundamental concepts and variables for replacing SGS is desired. [ABSTRACT FROM AUTHOR]

Experiments were conducted to investigate the rates of H2S and CO2 alteration of pozzolan-amended wellbore cement (35 vol% pozzolan-65 vol% cement), so as to evaluate the potential impact of H2S and CO2 induced degradation of existing cemented wells present at acid gas co-sequestration sites. In the exposure experiments, pozzolan-amended cement samples were mixed, cured and exposed to mixtures of H2S and CO2 under lab-simulated geologic sequestration conditions (50 °C and 15.2 MPa) for 2.5, 9, 28 and 90 days. Measurement of the carbon alteration front was used to calculate the rate of CO2 alteration of pozzolan-amended cement exposed to a mixture of 79 mol% CO2 and 21 mol% H2S under geologic sequestration conditions in exposure periods of 0-90 days. Average CO2 alteration rates (rate of movement of CaCO3 precipitation front) were 3.3 x 10-3 mm/day and 3.2 x 10-3 mm/day for cement samples exposed to a 1% NaCl solution saturated with CO2 and H2S, and those in contact with a supercritical mixture of CO2 and H2S, respectively. Two scenarios were considered for measuring and quantifying alteration caused by H2S over the exposure periods of 0-90 days: sulfur-rich zone thickness, and sulfur alteration index. The average rate of H2S alteration determined by sulfur-rich zone thickness divided by exposure duration was 4.3 x 10-3 mm/day for cement exposed to 1% NaCl solution saturated with CO2 and H2S, and the average rate of H2S alteration determined by sulfur alteration index divided by exposure duration was 8.2 x 10-3 day-1. Cement exposed to a supercritical mixture of CO2 and H2S result in H2S alteration rates determined by sulfur-rich zone thickness divided by exposure duration of 3.1 x 10-3 mm/day, and average rates of H2S alteration determined by sulfur alteration index divided by exposure duration of 6.3 x 10-3 day-1. Sulfur alteration index results also show that H2S was able to penetrate to the core of pozzolan-amended wellbore cement after 2.5 days of exposure, though this was not readily apparent in the sulfur-rich zone thickness results. Sulfur-rich zone thickness is best used to describe high-level sulfur alteration in the rim of samples. The results indicate that (1) an aqueous environment is more favorable for H2S attack on pozzolan-amended cement than a supercritical CO2 and H2S environment; (2) for 90 days of exposure significant alteration induced by H2S and CO2 occurs at regions very close to the fluid/cement interface; (3) H2S penetrates pozzolan-amended cement more rapidly than CO2 in aqueous contact environments. In contrast, under supercritical liquid environment, H2S and CO2 have similar penetration rates in pozzolan-amended cement. [ABSTRACT FROM AUTHOR]

Highlights: [•] The effects of CO2 and H2S attack on pozzolan-amended wellbore cement under geologic carbon storage conditions are examined. [•] Iron-rich particles from pozzolan additives make pozzolan-amended wellbore cement prone to H2S attack. [•] 35 pozzolan vol% wellbore cement is more resistant to CO2 and H2S attack than 65 pozzolan vol% wellbore cement. [•] CO2 and H2S alteration of pozzolan-amended wellbore cement does not indicate mechanical strength loss. [Copyright &y& Elsevier]

Abstract: The solvent and swelling effects of supercritical CO2 on coal structure and porosity were examined using high-resolution field-emission scanning electron microscopy (FE-SEM) and surface area techniques to investigate any irreversible CO2 induced alterations of the micro-, meso-, and macropores. Dry, 1in. unconfined cores of Pittsburgh and Sewickly bituminous coals were exposed to supercritical CO2 at 15.3MPa (2200psig) and 328K (55°C) for 104days. Prior to CO2 exposure, coal structure and porosity – specifically macropores (>50nm) – were imaged using FE-SEM. After CO2 exposure, the imaged features were relocated, reimaged, and analyzed for structural changes. Brunauer–Emmett–Teller (BET) surface areas were evaluated from the adsorption isotherms of N2 at 77K and P/P 0 =0.1–0.3. Micropore surface areas were determined from the low-pressure adsorption isotherms of CO2 at 293K using the Dubinin–Polanyi equation. FE-SEM analysis indicated that there were no significant changes observed in the pore areas in all coal samples after CO2 exposure. Meso- and micropore characteristics were slightly affected by supercritical CO2 exposure. [Copyright &y& Elsevier]

Abstract: Laboratory experiments were performed in order to determine the alteration in cement exposed to acid gas (H2S–CO2) and pure CO2 under simulated reservoir conditions. Cement samples were exposed for a period of 28 days at a temperature of 50°C and a pressure of 15MPa using pure CO2 and H2S–CO2 (21mol% H2S) to simulate acid gas. The cement samples were partially submerged in aqueous solutions to include both saturated aqueous and supercritical CO2 phases. The cement exposed to pure CO2 was identical in alteration to those previously tested and described in that they exhibited the typical carbonation rims which result from the CO2/cement interaction. The H2S–CO2 exposed cement exhibited a carbonated zone similar to the CO2-only samples and underwent an additional sequence of oxidation–reduction and sulfidation reactions. Ettringite was observed in the interior region of the cement, and pyrite in the carbonated rim of the cement exposed to H2S–CO2. The mineralogical changes and alteration front are believed to be controlled by local porewater pH buffering. Although the process of secondary ettringite formation subsequent to the hardening of cement can lead to strength loss and degradation, ettringite induced mechanical damage was not observed in the samples. [Copyright &y& Elsevier]

Abstract: Acid gas (mixed CO2 and H2S) injection into geological formations is increasingly used as a disposal option. For example, more than 40 acid gas injection projects are currently operating in Alberta, Canada . In contrast to pure CO2 injection, there is little understanding of the possible effects of acid gases under geological sequestration conditions on exposed materials ranging from reactions with reservoir minerals to the stability of proppants injected to improve oil recovery to the possible failure of wellbore cements. The number of laboratory studies investigating effects of acid gas has been limited by safety concerns and the difficulty in preparing and maintaining single-phase H2S/ CO2 mixtures under the experimental pressures and temperatures required. In an effort to address the lack of experimental data addressing the potential effects of acid gas injection, the Plains CO2 Reduction Partnership (PCOR) in the United States has developed approaches using conventional syringe pumps (ISCO 260D pumps) and reactor vessels (Parr Instruments) to prepare and maintain H2S/ CO2 mixtures under relevant sequestration conditions of temperature, pressure, and exposure to water and dissolved salts. Exposures up to several months can be conducted at temperatures and pressures up to 350 °C and 414 bar (6000 psi) using any desired H2S/ CO2 mole ratio. Up to 16 individual samples racked in separate glass vials can be exposed at one time, and the use of separate glass vessels allows different salt brine concentrations to be evaluated. In addition to performing static exposure experiments, the pumps and vessels are sufficiently leakfree that reaction rates can be determined by monitoring mass flow at the pumps. Interestingly, this is much easier to perform for reactions with H2S than with CO2, because H2S is much less compressible and has lower Joule–Thompson heating/cooling effects than CO2. Thus, obtaining accurate values for the mass of CO2 used during an experiment based on pump volume is much more difficult than for H2S, although controlling the pump cylinder temperature with a water jacket allows reasonable measurements to be made. These systems have been used to determine reaction rates of model systems, such as the formation of magnesium carbonate from magnesium silicate and the formation of pyrite from iron oxide (Fe3O4). For example, the use of H2S (as measured at the pump) was steady at ca. 0.5 grams per day (for 18.6 grams of Fe3O4) until the reaction was complete. The half-life of the reaction was 20 days, and the mass balance (0.54 moles H2S actual compared to 0.48 moles theoretical) was reasonable. [Copyright &y& Elsevier]

The rate and mechanism of reaction of pozzolan-amended Class H cement exposed to both supercritical CO2 and CO2-saturated brine were determined under geologic sequestration conditions to assess the potential impact of cement degradation in existing wells on CO2 storage integrity. The pozzolan additive chosen, Type F flyash, is the most common additive used in cements for well sealing in oil-gas field operations. The 35:65 and 65:35 (v/v) pozzolan-cement blends were exposed to supercritical CO2 and CO2-saturated brine and underwent cement carbonation. Extrapolation of the carbonation rate for the 35:65 case suggests a penetration depth of 170-180 mm for both the CO2-saturated brine and supercritical CO2 after 30 years. Despite alteration in both pozzolan systems, the reacted cement remained relatively impermeable to fluid flow after exposure to brine solution saturated with CO2, with values well below the American Petroleum Institute recommended maximum well cement permeability of 200 μD. Analyses of 50: 50 pozzolan-cement cores from a production well in a sandstone reservoir exhibited carbonation and low permeability to brine solution saturated with CO2, which are consistent with our laboratory findings. [ABSTRACT FROM AUTHOR]

Experiments were conducted to study the degradation of hardened cement paste due to exposure to CO2 and brine under geologic sequestration conditions (T= 50 °C and 30.3 MPa). The goal was to determine the rate of reaction of hydrated cement exposed to supercritical CO2 and to CO2-saturated brine to assess the potential impact of degradation in existing wells on CO2 storage integrity. Two different forms of chemical alteration were observed. The supercritical CO2 alteration of cement was similar in process to cement in contact with atmospheric CO2 (ordinary carbonation), while alteration of cement exposed to CO2-saturated brine was typical of acid attack on cement. Extrapolation of the hydrated cement alteration rate measured for 1 year indicates a penetration depth range of 1.00 ± 0.07 mm for the CO2-saturated brine and 1.68 ± 0.24 mm for the supercritical CO2 after 30 years. These penetration depths are consistent with observations of field samples from an enhanced oil recovery site after 30 years of exposure to CO2-saturated brine under similar temperature and pressure conditions. These results suggest that significant degradation due to matrix diffusion of CO2 in intact Class H neat hydrated cement is unlikely on time scales of decades. [ABSTRACT FROM AUTHOR]

Experiments were conducted to assess the durability of cements in wells penetrating candidate formations for geologic sequestration of CO2. These experiments showed a significant variation in the initial degradation (9 days of exposure) based on the curing conditions. The high-temperature (50 °C) and high-pressure (30.3 MPa) curing environment increased the degree of hydration and caused a change in the microstructure and distribution of the Ca(OH)2(s) phase within the cement. Cement cured at 50 °C and 30.3 MPa (representing sequestration conditions) proved to be more resistant to carbonic acid attack than cement cured at 22 °C and 0.1 MPa. The cement cured at 50 °C and 30.3 MPa exhibited a shallower depth of degradation and displayed a well-defined carbonated zone as compared to cement cured under ambient conditions. This is likely due to smaller, more evenly distributed Ca(OH)2(s) crystals that provide a uniform and effective barrier to CO2 attack. [ABSTRACT FROM AUTHOR]

Understanding the rheological behavior of cement slurries is important in cement and petroleum industries. In this paper, we study the fully developed flow of a cement slurry inside a wellbore. The slurry is modeled as a non-linear fluid, where a constitutive relation for the viscous stress tensor based on a modified form of the second grade (Rivlin–Ericksen) fluid is used;we also propose a diffusion flux vector for the concentration of particles. The one-dimensional forms of the governing equations and the boundary conditions are made dimensionless and solved numerically. A parametric study is performed to present the effect of various dimensionless numbers on the velocity and the volume fraction profiles. [ABSTRACT FROM AUTHOR]