Mehdi Zeidouni

Analytical solution to evaluate salt precipitation during CO2 injection in saline aquifers

Abstract Carbon dioxide sequestration in deep saline aquifers is a means of reducing anthropogenic atmospheric emissions of CO 2 . Among various mechanisms, CO 2 can be trapped in saline aquifers by dissolution in the formation water. Vaporization of water occurs along with the dissolution of CO 2 . Vaporization can cause salt precipitation, which reduces porosity and impairs permeability of the reservoir in the vicinity of the wellbore, and can lead to reduction in injectivity. The amount of salt precipitation and the region in which it occurs may be important in CO 2 storage operations if salt precipitation significantly reduces injectivity. Here we develop an analytical model, as a simple and efficient tool to predict the amount of salt precipitation over time and space. This model is particularly useful at high injection velocities, when viscous forces dominate. First, we develop a model which treats the vaporization of water and dissolution of CO 2 in radial geometry. Next, the model is used to predict salt precipitation. The combined model is then extended to evaluate the effect of salt precipitation on permeability in terms of a time-dependent skin factor. Finally, the analytical model is corroborated by application to a specific problem with an available numerical solution, where a close agreement between the solutions is observed. We use the results to examine the effect of assumptions and approximations made in the development of the analytical solution. For cases studied, salt saturation was a few percent. The loss in injectivity depends on the degree of reduction of formation permeability with increased salt saturation. For permeability-reduction models considered in this work, the loss in injectivity was not severe. However, one limitation of the model is that it neglects capillary and gravity forces, and these forces might increase salt precipitation at the bottom of formation particularly when injection rate is low.

Monitoring above-zone temperature variations associated with CO2 and brine leakage from a storage aquifer

Abstract CO2 injection in saline aquifers induces temperature changes owing to processes such as Joule–Thomson cooling, endothermic water vaporization, exothermic CO2 dissolution besides the temperature discrepancy between injected and native fluids. CO2 leaking from the injection zone, in addition to initial temperature contrast due to the geothermal gradient, undergoes similar processes, causing temperature changes in the above zone. Numerical simulation tools were used to evaluate temperature changes associated with CO2 leakage from the storage aquifer to an above-zone monitoring interval and to assess the monitorability of CO2 leakage on the basis of temperature data. The impact of both CO2 and brine leakage on temperature response is considered for three cases (1) a leaky well co-located with the injection well, (2) a leaky well distant from the injector, and (3) a leaky fault. A sensitivity analysis was performed to determine key operational and reservoir parameters that control the temperature signal in the above zone. Throughout the analysis injection-zone parameters remain unchanged. Significant pressure drop upon leakage causes expansion of CO2 associated with Joule–Thomson cooling. However, brine may begin leaking before CO2 breakthrough at the leakage pathway, causing heating in the above zone. Thus, unlike the pressure which increases in response to both CO2 and brine leakage, the temperature signal may differentiate between the leaking fluids. In addition, the strength of the temperature signal correlates with leakage velocity unlike pressure signal whose strength depends on leakage rate. Increasing leakage conduit cross-sectional area increases leakage rate and thus increases pressure change in the above zone. However, it decreases leakage velocity, and therefore, reduces temperature cooling and signal. It is also shown that the leakage-induced temperature change covers a small area around the leakage pathway. Thus, temperature data will be most useful if collected along potential leaky wells and/or wells intersecting potential leaky faults.

Analytical Solution to Evaluate Salt Precipitation during CO2 Injection in Saline Aquifers

Abstract The amount of salt precipitation and the region in which it occurs are important parameters in CO 2 storage management. For this study, an analytical model, as a simple and efficient tool to predict the amount of salt precipitation over time and space, is developed. The analytical model is then extended to evaluate the effect of salt precipitation on permeability in terms of a timedependent skin factor. The analytical model is applied to a specific problem with available numerical solution, where a close agreement is observed. This is used to evaluate the effect of assumptions made in development of the analytical solution.

Identification of above-zone pressure perturbations caused by leakage from those induced by deformation

Pressure changes in the above zone, i.e., the overlying aquifer of an injection zone separated by a sealing caprock, are usually attributed to leakage through wells. However, pressure changes can be induced geomechanically due to rock deformation without any hydraulic connection between the injection zone and the above zone where the pressure change is observed. To account for these two causes of pressure change in the above zone, we develop an analytical solution to evaluate the deformation-induced pressure changes and we derive an asymptotic analytical solution for pressure perturbations caused by leaking wells. The analytical models compare well with available numerical/analytical solutions. Using the analytical solutions for the deformation- and leakage-induced pressure changes, we propose a graphical diagnostic plot to determine the cause of pressure change. Considering that the pressure change is caused by leakage, we then use the asymptotic solution to develop an easy-to-use fully graphical methodology to characterize leaking wells. This methodology improves a previous analysis methodology that was based on an inverse modeling algorithm that can be highly instable and computationally expensive. Based on the graphical method presented here, the slopes and intercepts of the proposed line-fitted graphs are used to determine the leak location and transmissibility. We apply the graphical method to an example problem to illustrate its application procedure and effectiveness in differentiating deformation-induced pressure changes from leaking wells. Overall, the diagnostic plot proposed here proves to be useful to determine the cause of the above-zone pressure change.

Semi-Analytical Model of Pressure Perturbations Induced by Fault Leakage in Multilayer System

AbstractLateral and vertical migration capacity of faults has been studied for applications related to fluid extraction and injection from and into the subsurface. Fluid exchange between formations connected by a fault can cause pressure perturbations in nonoperating formations. An analytical model was previously developed to evaluate the leakage rates through a fault in a multilayer system. However, the effect of the fault’s lateral resistance to flow was neglected and therefore the model was not applicable in evaluating the pressure changes caused by fault leakage. Pressure perturbations induced by fault leakage are important to determine the safety of injection operations near faults and/or in characterizing and remediating fault leakage. Here, the previous model on fault leakage to evaluate the pressure changes is extended by accounting for the lateral resistance to flow in all modeling components. As a result, the leakage rates at the two sides of the fault are no longer identical. Also, the model pr...

Analytical Model for Multifractured Systems in Liquid-Rich Shales with Pressure-Dependent Properties

One of today’s challenges in reservoir management of liquid-rich shales is to accurately forecast production performance based on pressure/rate transient analyses. The need for large pressure gradients to produce from shale reservoirs through multifractured horizontal wells (MFHWs) may induce considerable changes in rock and fluid properties that can largely affect transient bottom-hole pressure response which can result in inaccurate predictions for well performance. Therefore, the assumption of constant properties in shale reservoirs may not be safe when modeling MFHW performance. This paper presents a nonlinear analytical MFHW performance model for single-phase systems based on the five-region model (Stalgorova and Mattar in SPE Reserv Eval Eng 16(03):246–256, 2013) that accounts for pressure-dependent rock and fluid properties in liquid-rich shales. Properties are assumed to vary exponentially with pressure. Because of this, the resulting nonlinear diffusivity equation is linearized by means of an exponential transformation. The nonlinear MFHW performance model is benchmarked against numerical simulation data for a number of case studies. The proposed analytical solution is able to accurately capture transient bottom-hole pressure response while delivering a highly accurate estimation of depletion time. In this study, it was found that nonlinear diffusion processes in liquid-rich shales, under the assumption of exponential changes in properties with pressure, are fully described by the porous medium equation (PME). The PME is presented along with a straightforward application to identify and forecast flow regimes in the reservoir (fast, normal or slow diffusion). Finally, a brief review on diagnostic plots for systems with pressure-dependent properties concludes this work.

Risk Based Approach to Identify the Leakage Potential of Wells in Depleted Oil and Gas Fields for CO 2 Geological Sequestration

The selection of depleted oil and gas fields as potential CO2 geological storage sites has both positive and negative aspects that need to be considered. The positives are that the storage capacity or pore volume can be reliably estimated from field’s production history, and reservoir characterization can be performed with more readily available well, log or seismic data without additional expenses. The main drawback is the presence of wells in the field, as each well may provide a leakage pathway for injected CO2. The leakage potential of a well is a function of its proximity to injection wells, cement coverage in the potential storage zone, well abandonment conditions including cementing of the annular space, and the nature of any barriers to prevent CO2 leakage to the surface. Qualitative and quantitative risk-based approaches can be used to identify the wells that have comparatively higher leakage probabilities in comparison to other wells. The objective of this study is to use a risk-based approach to identify and categorize wells based on their leakage potential in depleted oil and gas fields. This will not only help in planning injection strategies but may also help in selection of remediation strategies. The model may be presented well by using the Fault Tree Analysis (FTA) technique. It implements screening criteria and a tier-based approach in which wells are screened and categorized into different tiers based on different well characteristics. The well characteristics include the physical distance from injection wells, the quality and portion of cement coverage of wells in the target zone, the regulations at the time of well completion, the leakage potential of sealing barriers for the targeted zone, the number of overlying shale and sand intervals and leakage of either CO2 or brine to shallower wells, the nature and quality of permanent or temporary well abandonment procedures, and the quality and length of annular space covered with cement for shallower well casings or sections. Existing models for well leakage are used to quantitatively estimate the leakage rate. The risk of leakage is presented qualitatively and quantitatively in the form of leaked CO2 volume to shallow aquifers or to the atmosphere. The approach is used for a representative depleted oil and gas field in southern Louisiana to show an example application of the process. The developed model provides a means to systemically identify the wells that are more likely to leak and have high consequences. Due to the reduced order nature of the tool, it should prove to be a useful tool in the planning and execution phase of the CO2 sequestration process.

Static and Dynamic CO 2 Storage Capacity Estimates of a Potential CO 2 Geological Sequestration Site in Louisiana Chemical Corridor

The close proximity of large CO2 emitters and depleted oil and gas reservoirs in the Louisiana Chemical Corridor (LCC) provide unique opportunities for CO2 geological sequestration in coastal Louisiana. The identification of sites with good storage capacity and retention characteristics is of prime importance for successful CO2 storage projects. In this study, the Bayou Sorrel field area located within close proximity of some of the large CO2 emitters in the LCC, is analyzed as a potential candidate site for aquifer storage. The results of static and dynamic aquifer storage capacity estimates are presented in this study. A volumetric approach is used to estimate the static storage capacity, and reservoir simulations are performed to compute dynamic storage capacity. The field and well data from publically available data sources are compiled to characterize the sands for prospective CO2 sequestration intervals (i.e., non-productive sands), and pressure and temperature conditions. Information of total areal extent, gross formation thickness, and total porosity are used along with a storage efficiency factor to find the pore volume available for storage. The upper depth limit for CO2 injection is dictated by the pressure and temperature conditions at which CO2 exists in a supercritical state. The Peng-Robinson (PR) equation of state is used in conjunction with subsurface pressure and temperature to determine the minimum depth at which CO2 is supercritical. Multiple geological realizations are used for a realistic site specific storage capacity estimate. The reservoir simulations capture the transient nature of the process and provide estimation of storage capacity under dynamic conditions. The sensitivity of injection location and boundaries is also evaluated in the dynamic storage capacity estimates. The results of the dynamic storage capacity estimate for a 1,000 ft thick interval at an average depth of 7,100 ft show that reasonable values of storage efficiency factors for this region are in the range of 1.14 to 2%. The results of the dynamic model also show that the nature of the storage zone boundary type, end point saturation and injection rate play significant role in estimation of dynamic storage capacity. These factors may induce more than 30% change in estimated dynamic storage value. The calculated storage efficiency factor may be applicable to other potential sites in this region, having similar geological characteristics.

Pressure Transient Analysis for Characterization of Lateral and Vertical Leakage through Faults

A fault is a potential pathway for fluid leakage, which can contaminate underground water resources. In addition, fault leakage can affect hydrocarbon production. This study aims to develop a type-curve-based methodology to characterize a fault both laterally and vertically using pressure transient analysis. We develop an analytical model to assess the pressure perturbations corresponding to production/injection from/into a reservoir with a leaky fault. Displacement of layers during the fault displacement may cause alteration of the reservoir properties across the fault. This alteration is accounted for by considering different properties on the two sides of the fault. The reservoir is divided into two regions separated by the fault, which are in hydraulic communication with one another and with the overlying/underlying permeable layers. The governing system of differential equations and corresponding boundary conditions are solved using Fourier and Laplace transforms. At early times of the fault leakage, the recorded well pressure changes are mostly affected by the fault properties and the effects of resistance from the upper zone emerge later. In this model, we neglect the resistance to leakage flow caused by the overlying zone to focus on the pressure changes at early times of the fault leakage. We show that these assumptions are

Tracer test to constrain CO2 residual trapping and plume evolution

AbstractCO2 residual trapping, post-injection plume extent, and time for plume stabilization for CO2 geological storage highly depend on the hysteresis process which is the discrepancy between drainage and imbibition processes. CO2 flow in the injection zone during the injection period is mainly controlled by the drainage process during which the non-wetting CO2-rich phase replaces the wetting aqueous phase. Using data collected over the injection period may be insufficient in constraining the hysteresis parameters required to predict the post-closure plume evolution. Long-term data collection over the post-injection period to determine the residually trapped CO2 and to predict the CO2 plume evolution and stabilization can be very expensive. Here, we introduce a tracer test to enable the determination of the residually trapped CO2 and prediction of the CO2 plume evolution and stabilization in a temporal manner. The tracer test is introduced at the end of an injection period to obtain information on the residual trapping parameters including imbibition/drainage discrepancy (hysteresis) and critical CO2-rich phase saturation. The sensitivity of the proposed tracer test to residual trapping parameters is evaluated with respect to the tracers’ peak times at the injection well (which serves as observation well during post-injection period) as well as an offset location at an updip distance from the injection well. The effect of residual trapping on the plume evolution and tracer test response is studied considering reservoir properties representative of a real project.