Near-well Region Research Articles

Evaluation of underground gas storage capacity in the depleted gas reservoir with water evaporation and salt precipitation

Water evaporation and salt precipitation will occur in gas reservoirs and underground gas storage (UGS) with high-salinity formation water during production and operation. This phenomenon seriously affects the efficient and safe operation and gas storage capacity. This work focuses on quantitatively evaluating the UGS capacity based on depleted gas reservoirs considering water evaporation and salt precipitation. The core flooding experiments are conducted to analyze the influence of water evaporation and salt precipitation on rock properties under different water salinity during multi-cycle injection-production. A numerical model considering water evaporation is established to determine the salt precipitation radius around the gas well. According to the experimental and simulation results, a new analytical model is developed to calculate the underground natural gas storage capacity based on material balance principles. The field case study is presented to show the practical potential of the established model. Both formation porosity and permeability in near-well region may be finally improved by water evaporation and salt precipitation under irreducible water condition. In the presence of movable-water, formation porosity and permeability of the near-well region may be firstly improved and finally reduced due to continuous salt precipitation in porous media. Salt-precipitation radius achieves 28.5 m after ten cycles. The UGS capacity is 101.11 × 108 m3 without considering salt precipitation, 1.11% higher than original geological reserves. The UGS capacity considering both irreducible-water evaporation and salt precipitation is 101.03 × 108 m3. However, when the moveable-water evaporation volume increases to 15Virr, the final UGS capacity is further decreased to 98.55 × 108 m3. The UGS capacity has decreased by 0.82%, 1.64%, and 2.45% compared with irreducible water. The continuous evaporation of movable water and salt deposition will reduce the gas storage capacity and cause damage to the UGS. This work provides an effective method to investigate the quantitative impact of water evaporation and salt precipitation on UGS capacity.

Modelling and optimization of shallow underground thermal energy storage

Shallow geothermal reservoirs are excellent candidates for low-enthalpy energy storage, and can serve as heat batteries providing constant discharge of base heat, as well as rapid discharge of heat in periods of high demand. Recharging can be done by pumping down hot water, heated using excess heat from e.g. waste incinerators. In addition to having a very low carbon footprint, such systems also require limited surface infrastructure, and can easily be placed near or under the end-user, such as below residential buildings. The geological setting is typically complex, with horizons, faults, and intertwined patterns of natural fractures, and the nearwell region is often hydraulically fractured to enhance inter-well communication. Therefore, in order to fully utilize the potential of shallow geothermal heat storage, numerical simulations are imperative. In this work, we show how to practically model such systems, including generation of computational grids with a large number of wells and fractures, numerical discretizations with discrete fractures, and complex storage strategies with multiple wells working together under common group targets. We also discuss how adjoint-based methods can be used to tune model parameters (e.g. well injectivities, rock properties, and hydraulic fracture conductivities) so that the model fits observed data, and to find well controls (e.g. rates and temperatures) that optimize storage operations. The methodology is demonstrated using one artificial and two real underground thermal energy storage projects currently under development, and we highlight important challenges and our suggested solutions related to each of them. Thematic collection: This article is part of the Earth as a thermal battery: future directions in subsurface thermal energy storage systems collection available at: https://www.lyellcollection.org/topic/collections/thermal-energy

Post-frac evaluation of deep shale gas wells based on a new geology-engineering integrated workflow

The development of shale gas reservoir is now shifting focus from mid-shallow reservoirs to deep reservoirs in the southern Sichuan Basin. For such reservoirs with high temperature, pressure, and stress difference, along with multiple folds, faults, and complex fracture networks, improving the stimulation performance of shale gas wells is the ultimate challenge. This study presents a new geology-engineering integrated workflow coupling hydraulic fracture simulation and reservoir simulation together with artificial intelligence to perform post-frac evaluations. A two-step calibration workflow of fracturing and reservoir simulations generated an ensemble of representative models, and a confidence interval of estimated ultimate recovery forecast were obtained. Four deep shale gas wells with two different completion versions (version 1.0 and version 2.0) in Y101 study area were evaluated. Some of the key learnings include: (1) the ratio of stimulated rock volume and drained rock volume is quantified to 8%–25% for the four characterized deep shale gas wells; (2) the version 2.0 completion design is able to stimulate the near-well region more effectively than version 1.0; (3) this novel geology-engineering integrated workflow performed the first reliable, robust and quantifiable post-frac evaluation in the southern Sichuan Basin deep shale reservoir.

The pore-network modeling of gas-condensate flow: Elucidating the effect of pore morphology, wettability, interfacial tension, and flow rate

The gas-condensate flow in the near-well region is significantly influenced by phase behavior, flow regimes, and pore geometries. In conventional gas-condensate reservoirs the key pore-scale parameters affecting gas and condensate relative permeabilities include velocity (i.e., pressure gradient), interfacial tension (IFT), wettability, and pore structure. To examine the impact of these parameters, three-dimensional (3D) and two-dimensional (2D) pore-network models (PNMs) were developed. A proposed compositional model was used to implement the cyclic process of condensate corner flow (film flow for circular tubes) and condensate blockage. Response surface methodology (RSM) was employed to achieve high accuracy in phase equilibrium calculations and to enhance computational speed.The 3D PNM simulations of gas-condensate core-flood experiments confirmed the consistency and accuracy of the implemented methodology. A parametric study of governing factors such as pore shapes, wettability, IFT, and flow rate was conducted using the developed PNMs. The findings revealed that pore geometry and contact angle dictate the condensate meniscus curvature and snap-off process in pore throats. The unblocking of throats by condensate bridges was primarily controlled by contact angle, IFT, and pore cross-section. A shift to neutral wetting substantially improved gas-condensate flow in higher IFTs and angular pore shapes.The positive velocity effect on low-IFT gas-condensate flow, known as the coupling rate effect, was more pronounced in simulations with lower contact angles, and its impact was negligible at neutral wettability, similar to the IFT effect. The simulation results and findings underscore the influence of each factor and offer a method for incorporating the effects of pore shape (i.e., formation type and structure), contact angle, velocity, and IFT in continuum scale simulations.

Coupled Thermal-Hydraulic-Mechanical Modeling of Near-Well Stress Evolution in Naturally Fractured Formations during Drilling

Naturally fractured formations usually have strong heterogeneities. Drilling and production operations in such formations can involve unwanted formation failure risks such as wellbore collapse and wellbore fracturing. This study presents a coupled thermal-hydraulic-mechanical numerical model for near-well stress evolutions during drilling in naturally fractured formations. The evolution of pressure, temperature, and geo-mechanical responses on the wellbore wall and in the near-well region is simulated. The effects of wellbore pressure, internal friction angle, and natural fracture length on formation rock risks are discussed. A failure index is used to quantify the formation rock failure risks. The existence of natural fractures magnifies the heterogeneous system response induced by drilling. Increasing the wellbore pressure from a relatively low value can improve the support for the wellbore wall, which reduces the failure risks caused by shearing. In mechanically weak formations, the effect of natural fractures on formation rock failure becomes more significant. When the natural fracture length is large, the near-well region tends to have greater failure risks as the formations become more mechanically weak. This study provides a quantitative understanding of the effects of drilling and formation parameters on failure risks.

Numerical study on the heat extraction performance of enhanced geothermal systems with a well-fracture-reservoir combined model

Understanding the fluid flow and heat transfer process in the well-fracture-reservoir combined system is crucial for the development of Enhanced or Engineered Geothermal Systems (EGS). In this paper, a well-fracture-reservoir integrated numerical model is developed to study the heat extraction performance considering the interactions among the well boreholes, the fractures in the reservoir and the base rock reservoir itself. The wells and major fractures are precisely described by the direct modelling while the sub-fractures in the base rock are described by a permeability distribution. A novel method to improve the heat extraction performance of EGS by enhancing the permeability in the near-well region is proposed. Simulation results show that the fluid flow path is predominantly determined by the well layout and fracture network. The fluid pressure is non-linearly distributed between the injection and production wells in the fractures and reservoir. Further, an optimized scheme for heat extraction of an assumed geothermal site in Gonghe Basin is proposed based on the near-well enhancement approach. The overall heat extraction performance of the near-well enhanced case is improved by more than 15.0%. The present work provides a feasible improvement scheme for EGS to achieve a better heat extraction performance.

Modelling CO2 plume spreading in highly heterogeneous rocks with anisotropic, rate-dependent saturation functions: A field-data based numeric simulation study of Otway

In this field-data-based simulation study, we apply novel rate-dependent, anisotropic saturation functions curve-fitted to match the flow behaviour of laminated sand- and siltstones from the CO2CRC's Otway International Test Centre (Australia), in well-spot simulations of plume spreading at the site. Scenario analysis is conducted by performing simulations on various stochastic model realisations under different conditions, investigating what controls plume migration. Results indicate that high-permeability streaks and intraformational baffles determine plume spreading in flat-lying stratigraphy. Displacement of CO2 is unstable and focussed by high-permeability streaks, leading to multi-layer plumes. In inclined stratigraphy, buoyancy forces control plume migration channelling it up dip. However, high-permeability streaks still influence plume shape. Comparisons for different injection rates show that heterogeneity-induced fingering dominates at high injection rates, whereas gravity override and vertical movement of the plume are prominent at low injection rates. Continuous build-up of fluid pressure in the storage horizon influences the properties of CO2 when no-flow (closed) lateral boundary conditions are applied. By contrast, a marked pressure drop occurs in the near-well region for hydrostatic (open) lateral boundary conditions. These also foster uneven heterogeneity-fingering of the plume. Since flow velocity in the highly heterogeneous Paaratte formation varies over many orders of magnitude, force balances range between the capillary and the viscous limit even at some distance to the injector. A comparison with simulations based on standard Brooks-Corey saturation functions shows that taking flow-rate dependence and anisotropy into account leads to significant differences in the shape of the evolving CO2 plume and the saturation within.

Effects of Thermal Stress in Hot Dry Rock Fracturing

Summary China has rich geothermal hot dry rock (HDR) resources, but the development and usage of its thermal energy are still at an early stage. At present, few studies have investigated the variation law for fracturing pressure on the borehole wall and fracture wall under the influence of thermal stress. This study investigates the fracturing pressure around the borehole wall based on rock mechanics and thermal stress analysis. Two models were developed: one for borehole wall fracturing pressure with consideration for thermal stress and the other for temperature difference conditions related to the automatic opening of fractures. By analyzing the temperature variation in the fracture wall, the mechanism for the opening of branch fractures at the fracture wall was investigated based on rock mechanics, the theory of fracture extension in hydraulic fracturing, and the theory of thermal stresses. We developed a computational model for tensile or shear damage related to branch fractures in the fracture wall with consideration for thermal stress, as well as a model for temperature difference conditions for the automatic opening of branch fractures. The simulation results show that the fracturing pressure decreased significantly when thermal stress was considered. Under normal geostress and temperature conditions, large temperature difference conditions are needed for the HDR borehole wall to break naturally because of thermal stress alone. During fracture extension, branch fractures on the fracture wall are more likely to form because of thermal stress. Irrespective of the type of damage (tensile or shear), branch fractures on the fracture wall closer to the borehole required lower net fracturing pressure. The decline in the net fracturing pressure was greater in response to shear damage than to tensile damage. In a high-temperature thermal reservoir, when branch fractures in the fracture wall were subjected to the temperature difference conditions for automatic opening, shear damage was more likely to occur than tensile damage. From the results, the following conclusions were obtained: The developed mechanical model of fracture opening reflects the mechanism of fracturing at the borehole wall and the fracture wall during HDR fracturing, thereby revealing the mechanism of the formation of fracture networks under thermal stress. For HDR fracturing, thermal stress promotes the formation of branch fractures in the fracture wall and increases the occurrence of complex fractures in the near-well region. Under thermal stress, the main fractures are less likely to extend in the optimal direction but instead tend to develop into complex fractures, which is not conducive to fracture connectivity between wells.

Pore scale modeling and evaluation of clogging behavior of salt crystal aggregates in CO2-rich phase during carbon storage

The optimal CO2 storage operation requires high permeability in the near-well region in order to keep it safe and cost-efficient. Nucleation and growth of salt crystals driven by the evaporation of formation water into under-saturated (dry) super-critical CO2 streams result in the changes in porosity and permeability of the near well-bore area. Permeability reduction is one of the main reasons for injectivity losses in the context of CO2 storage in saline aquifers. According to recent studies, during CO2 storage, salt crystals grow in two different forms: 1) single, large crystals in the aqueous phase, and 2) aggregates of micro-meter size salt crystals in the CO2-rich vapor phase. All previous numerical studies at pore-scale have addressed the formation of single, large crystals in the aqueous phase. In this work we have developed a 3D pore-scale reactive transport solver based on a D3Q19 advection-diffusion Lattice-Boltzmann model. The model takes for the first time salt nucleation into consideration via a new probabilistic approach to simulate the formation of micro-meter size salt crystal aggregates in the CO2-rich phase and their effect on changes in pore morphology and permeability. Comparing the results of porosity-permeability relations with some of the well-known clogging models, confirms the need for a new clogging model to capture the permeability reduction caused by salt aggregates.

Toward Probabilistic Modeling of Halite Nucleation and Growth during Carbon Storage Process: Pore Scale Modeling

To maximize safety and cost-efficiency of CO2 storage, it is necessary to understand how a high permeability in the near-well region is maintained. Nucleation and growth of salt crystals driven by the evaporation of formation water into under-saturated (dry) super-critical CO2 stream results in the changes in the porosity and permeability of the near well-bore area. Permeability reduction is the main reason of the injectivity loss in the context of CO2 storage in saline aquifers. According to recent studies, during CO2 storage, salt crystals form in two different forms: 1) single, large crystals in the aqueous phase, and 2) aggregates of micrometer size salt crystals in the gas phase. All the previous numerical studies at pore-scale addressed the formation of single, large crystals in the aqueous phase. In this work, we developed a 3D pore-scale reactive transport solver (a D3Q19 advection-diffusion Lattice-Boltzmann model) and took nucleation process into account via a new probabilistic approach to simulate the formation of micro-meter size salt crystals in the gas phase and their effect on changes in pore morphology and permeability for the first time. Comparing the results of porosity-permeability relation with some of the well-known clogging models, confirms the need for a new clogging model to capture the permeability reduction caused by salt aggregates.

Experimental and Numerical Evaluation of Hydraulic Fracturing under High Temperature and Embedded Fractures in Large Concrete Samples

In order to study the mechanism of hydraulic fracturing in enhanced geothermal systems, we analyzed the influence of high temperatures and embedded fractures on the initiation and propagation of hydraulic fractures using a laboratory test and numerical simulation. The analysis was conducted via large-scale true triaxial hydraulic fracturing tests with acoustic emission monitoring. Moreover, we discussed and established the elastic-plastic criterion of hydraulic fracturing initiation. The corresponding fracturing procedure was designed and embedded into the FLAC3D software. Then, a numerical simulation was conducted and compared with the laboratory test to verify the accuracy of the fracturing procedure. The influence of high temperatures on hydraulic fracturing presented the following features. First, multi-fractures were created, especially in the near-well region. Second, fracturing pressure, extension pressure, and fracture flow resistance became larger than those at room temperature. 3D acoustic fracturing emission results indicated that the influence of the spatial distribution pattern of embedded fractures on hydraulic fracturing direction was larger than that of triaxial stress. Furthermore, the fracturing and extension pressures decreased with the increase of embedded fracture density. For hydraulic fracturing in a high temperature reservoir, a plastic zone was generated near the borehole, and this zone increased as the injection pressure increased until the well wall failed.

Continuum scale modelling of salt precipitation in the context of CO2 storage in saline aquifers with MRST compositional

Carbon capture and storage (CCS) would contribute considerably towards climate change mitigation, if it would be implemented on a very large scale; at many storage sites with substantial injection rates. Achieving high injection rates in deep saline aquifers requires a detailed assessment of injectivity performance and evaluation of the processes that alter the permeability of the near-well region. One of the most common forms of the injectivity loss in the context of CO2 storage in saline aquifers is salt precipitation driven by the evaporation of brine into the relatively dry injected CO2 stream. We present a novel compositional transport formulation based on overall-composition variables which models salt as a separate solid phase which could potentially form through two essentially different ways, i.e., kinetic or equilibrium. To model formation drying-out and subsequent halite-precipitation, an accurate and reliable fluid model ePC-SAFT, which can effectively account for ionic effects, is applied. In addition, a volume balance approach (i.e., depending on how far the salt saturation is from the solubility limit) is implemented to estimate solid saturation in a simulation cell. The resulting simulator is benchmarked against several well-known examples, with analytical solutions demonstrating the ability of the code to cover a variety of physical mechanisms. Finally, injection of dry CO2 into a brine-saturated core-scale domain is simulated and sensitivity analyses over various parameters are performed. We show that the new model is capable to quantitatively represent the physics of salt precipitation (for example salt self-enhancing) under different reservoir conditions.

Numerical Analysis of the Effects of Apparent-Permeability Modeling and Secondary-Fracture Distribution for Hydraulic-Fractured Shale-Gas Production Analysis

Summary Complex flow mechanisms, such as Knudsen diffusion, are encountered in the shale matrix because of the presence of nanopores. Numerous apparent-permeability models have been proposed to capture the ensuing non-Darcy flow behavior. However, these models are not readily available in most commercial reservoir simulators, and ignoring these mechanisms can potentially underestimate the overall matrix conductivity. This work implements an explicit coupling strategy for integrating a pressure-dependent apparent-permeability model in reservoir simulation. The numerical models are subsequently used to study the effects of apparent-permeability modeling and natural-fracture distribution on gas production and water loss during flowback. The effects of multiphase-flow functions on fluid retention are also assessed. A set of 3D reservoir models are constructed using field data obtained from the Horn River shale-gas reservoir. First, stochastic 3D discrete-fracture-network (DFN) models are scaled up into equivalent continuum dual-porosity/dual-permeability models. An apparent-permeability (Kapp) model accounting for contributions of slip flow, Knudsen diffusion, and surface pore roughness is applied at each gridblock. A novel coupling scheme is formulated to facilitate the updating of Kapp after a certain specified time interval, capturing the pressure dependency of the Kapp. The sensitivity of the updating frequency is analyzed. The results reveal that incorporating these additional flow mechanisms by means of the apparent-permeability formulation could potentially increase the overall gas-production prediction by up to 11%, depending on the average pore radius, reservoir pressure, and several other matrix or fluid properties. The implications of Kapp modeling in water-loss mechanisms are further examined through a set of sensitivity analyses, where the effects of multiphase-flow functions and DFN distributions are systematically investigated. The following interesting findings are observed: Ignoring Kapp modeling could overestimate water recovery. Fracturing-fluid propagation and long-term water recovery are strongly affected by the secondary-fracture intensity; increase in secondary-fracture intensity would enhance water loss during flowback. Gas production is highly affected by the amount of water in the near-well region. In a gas/water system, compressibility of the in-situ fluids renders the effects of countercurrent imbibition and water retention to be more complex from those observed in similar water/oil systems. This work offers a novel, yet practical, scheme for representing the pressure-dependent matrix apparent permeability in the flow simulation of shale reservoirs. The proposed method captures the non-Darcy flow behavior caused by the complex transport mechanisms occurring in nanosized pores. Most importantly, this coupling procedure can be implemented in existing commercial reservoir-simulation packages. The results have revealed a few interesting insights regarding the potential implications in fracturing design and estimation of stimulated reservoir volume.

Foam Generation in Flow Across a Sharp Permeability Transition: Effect of Velocity and Fractional Flow

Summary Foam reduces gas mobility and can help improve sweep efficiency in an enhanced-oil-recovery (EOR) process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that the local pressure gradient exceed a critical value (▿Pmin). Normally, this happens only in the near-well region. Away from wells, these requirements might not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (Rossen 1999). The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of fractional flow on this process. This article is an extension of a recent study (Shah et al. 2018) investigating the effect of permeability contrast on this process. In this study, the effects of fractional flow and total superficial velocity are described. Coreflood experiments were performed in a cylindrical sintered-glass porous medium with two homogeneous layers and a sharp permeability jump in between, representing a lamination or cross lamination. Unlike previous studies of this foam-generation mechanism, in this study, gas and surfactant solution were coinjected at field-like velocities into a medium that was first flooded to steady state with gas/brine coinjection. The pressure gradient is measured across several sections of the core. X-ray computed tomography (CT) is used to generate dynamic phase-saturation maps as foam generates and propagates through the core. We investigate the effects of velocity and injected-gas fractional flow on foam generation and mobilization by systematically changing these variables through multiple experiments. The core is thoroughly cleaned after each experiment to remove any trapped gas and to ensure no hysteresis. Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, and it then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities. Foam was generated in all cases, at all the injected conditions tested; however, at the lowest velocity tested, strong foam did not propagate all the way to the outlet of the core. Although foam generation was triggered across the permeability boundary at this velocity, it appeared that, for our system, the limit of foam propagation, in terms of a minimum-driving-force requirement, was reached at this low rate. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate—probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ▿P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injection rate.

Salt clogging during supercritical CO2 injection into a downscaled borehole model

Injection of CO2 into saline storage aquifers is often accompanied by drying of the formation water and salt precipitation. Subsequent salt clogging of a well bore and the near wellbore rock matrix may lead to injectivity impairment. In this paper we present medium-scale experiments on salt precipitation in the near-well region during a dry CO2 injection. In an effort to better simulate the geometry and the flow conditions in the field situation our purpose-designed experimental setup enables (1) realistic radial geometry of CO2 flow, and (2) opened boundary conditions for brine inflow allowing capillary and diffusive flux of brine components from and to practically infinite source of formation water.During the course of injection, no significant pressure build-up was observed across the rock specimen, indicating that permeable flow paths were not completely clogged. Post-test analysis of the specimen included X-ray computed tomography, powder X-ray diffraction and scanning electron microscopy in order to quantify fluid saturation, brine salinity and halite precipitation. The analysis provided indication of the most probable flow patterns of supercritical CO2 and CO2 rich brine in the system. The resulting drying and precipitation is discussed in light of the different drying regimes created under the present flow conditions.

Effect of reducing irreducible water saturation in a near-well region on CO2 injectivity and storage capacity

Fossil fuels currently supply 80% of the world’s energy demands and are primarily responsible for increasing carbon concentration in the atmosphere and the associated climate change. Achieving internationally discussed goals for reducing carbon emission will be either impossible or involve significant costs without implementing the CO2 capture and storage (CCS). The volumetric CO2-storage capacity of a brine aquifer is among the most critical factors for the economically-viable & large-scale geologic CO2-storage projects. The maximum sustainable injection rate or CO2 injectivity is another important criterion that depends on many reservoir properties. Based on previous experimental studies, we hypothesized that if the sweep efficiency of CO2 is improved by using suitable additives, then a higher end-maximum CO2 saturation can be achieved that, in turn, can increase the CO2 injectivity. In this regard, a strategy to enhance the CO2 injectivity was proposed by reducing the irreducible water saturation in a near-well region. In this study, the influence of reducing the irreducible water saturation and thus improving the relative permeability of CO2 on the CO2 injectivity and storage capacity is investigated in depth. A series of numerical simulations involving two test models – a hypothetical horizontal aquifer and a pilot test site in South Korea – were conducted to examine our assumptions with the concentration of surfactants confirmed from the previous experimental study. The results help to ascertain the applicability and effectiveness of the proposed injectivity-enhancing strategy. It was observed that the pre-injection of surfactant solution slows down the well-bottom-hole pressure and increases the total CO2 injection capacity, with the effect deemed proportional to the quantity of surfactant for a hypothetical flat aquifer. However, a nonlinear relationship between the surfactant quantity and the injectivity was found in the case of the pilot test site, which revealed that the surfactant pre-injection influences the migration of CO2-plume and solubility trapping as well.

Modeling of Liquid Injectivity in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery

SummarySurfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity.In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator's results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor.The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.

Applications of fully coupled well/near-well modeling to reservoir heterogeneity and formation damage effects

Applications of a new well/near-well fluid flow modeling scheme to heterogeneous reservoirs and formation damage are presented in this paper. This well/near-well model is based on an analytically solution of an axial-radial productivity model for steady state flow in wells and near-well reservoirs, in which wellbore hydraulics and heterogeneity in the near-well region are incorporated. The numerical model includes a reservoir region describing both radial and axial reservoir flow. It can be used as a stand alone simulator, or it can be coupled with a reservoir simulator, using a new iterative coupling scheme described in this paper. When coupling with the reservoir simulator, the reservoir region in the well/near-well model is shared by and computed in both models, which ensures the stability and convergence of the iterative coupling scheme. A new coupling approach is presented without needing to determine any partial derivatives.The capabilities of the modeling methodology are demonstrated through applications in three challenging cases: highly heterogeneous reservoir, well/reservoir crossflow, and formation damaged reservoirs. In the highly heterogeneous near-well reservoir case, results show that the model is stable for a wide range of permeabilities with large contrasts. The detailed permeability information from well logging can be fully taken into account in this model. The model determines pressure distribution and volumetric flow rates including flow directions, therefore enabling the model to estimate crossflow as negative flow rates, for example when the well is producing from several non-communicating regions. Furthermore, the well/near-well model is iteratively coupled with a reservoir simulator such that the well completion effects are taken into consideration in large scale simulations. The transient case of this coupling to evaluate formation damage along a horizontal well is then presented. The model is not limited to single phase flow. A two phase flow example coupling the well/near-well model and a streamline reservoir model is finally presented.

The Effect of Brine Supply on CO2 Injectivity Impairment Due to Salt Precipitation

Salt clogging has been recognized as an important factor for injectivity impairment in the CO2 injection wells. While only a small amount of field experience with salt clogging has been reported to date, a large number of experimental and numerical studies have been published on the topics of injectivity impairment, drying mechanisms in porous media and salt precipitation due to CO2 or gas injection. The motivation for our work was to provide a better insight into which combinations of petrophysical properties and operational parameters would enable long term CO2 injection with minimal injectivity impairment caused by salt precipitation. Two supercritical CO2 injection experiments into brine-saturated Berea sandstone cores were performed in a core flooding setup at reservoir conditions. Salt concentration was moderate, at around 10 wt%. X-ray computed tomography scanning of the cores was performed prior to and after the flooding experiments. We focused on recreating conditions in the near-well region where CO2 injection rate is high, and brine back-flow rate is low, and thus evaporative regime is expected. The novelty in our experimental approach was that we introduced a continuous brine supply through a thin borehole in the outlet end of the core. This mimics a situation where the dry-out zone close to the injection well is (partially) replenished by brine from the surrounding reservoir. Complete salt clogging occurred in both experiments. The main difference between the two experiments was that CO2 injection rate was higher in the second experiment. In the first experiment, CT-imaging shows that salt precipitated in sheets with a helical structure mostly in the lower half of the core. In the second experiment, the salt accumulation was displaced further towards the core outlet and concentrated around the brine injection borehole. The average permeability across the core samples decreased substantially in both cases: by 99 % in the first experiment and by 96 % in the second. Our results confirm that salt clogging is a complex process where different parameters, such as salinity, CO2 and brine injection rates, permeability, pressure and temperature, can have significant effect on whether injectivity impairment occurs.

Local capillary trapping in carbon sequestration: Parametric study and implications for leakage assessment

Local capillary trapping (LCT) is the trapping of CO2 by local capillary barriers. It occurs during buoyancy-driven migration of bulk phase CO2 within a saline aquifer exhibiting spatially varying properties (permeability and capillary entry pressure). The benefit of LCT, in the context of CO2 sequestration, is that local capillary trapped CO2 is not susceptible to leakage through failed seals. However, it is unclear how the petrophsyical/geological properties and flow dynamics influence LCT. Thus, the objective of this work is to evaluate the degree to which potential local capillary traps are filled and quantify the extent of immobilization persisting after loss of seal integrity. This paper presents a systematic and thorough study of the influential parameters of LCT. Fine-scale capillary pressure fields are generated by using geostatistical permeability realizations and applying the Leverett j-function. Multiple factors are examined, including injection rate, anisotropy, formation dip, aquifer types, residual gas saturation, and capillary hysteresis. Leakage representative of wellbore failure is simulated, and LCT after leakage is evaluated and compared to other trapping mechanisms. The results show that local capillary traps in the near-well region can be fully filled during injection. Moreover, they remain filled after post-injection buoyancy-driven flow ends. The filling efficiency of local capillary traps increases with the decrease in gravity number (ratio of buoyant force over viscous force). As a result, maximizing LCT in carbon sequestration in porous reservoirs may be achievable with the implementation of appropriate injection strategies.