Effects of Formation-Water Salinity, Formation Pressure, Gas Composition, and Gas-Flow Rate on Carbon Dioxide Sequestration in Coal Formations

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1530-1541 ◽  
Author(s):  
Ahmed Farid Ibrahim ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Relative Permeability ◽  
Flow Rate ◽  
Water Permeability ◽  
Co2 Sequestration ◽  
Absolute Permeability ◽  
Co2 Injection ◽  
Permeability Reduction ◽  
Formation Pressure ◽  
Coal Surface ◽  
Effective Water

Summary Carbon dioxide (CO2) sequestration in coal seams combines CO2 storage with enhancing methane (CH4) recovery. The efficiency of CO2 sequestration depends on the coal-formation properties and the operating conditions. This study investigated the effects of the sodium chloride (NaCl) salinity of coal-seam water, injection flow rate, injected-gas composition, and CO2 state (formation pressure) on CO2 sequestration in coal formations. Coreflood tests were conducted on nine coal cores to simulate the injection of CO2 into coal formations. The change in the effective water/coal permeability after CO2 injection was measured. A commercial simulator was used to match the pressure drop across the core from the experimental study by adjusting the relative permeability curves. Moreover, permeability dynamic measurements were conducted to estimate the absolute permeability reduction caused by coal swelling. The effective water permeability in the tested coal decreased during CO2 injection because of its adsorption onto the coal surface, coupled with a reduction in the relative water permeability. As salt concentration increased, the change in the pressure drop across the core increased, but this effect decreased as the formation pressure increased. Higher formation pressure and lower nitrogen (N2) concentrations led to further permeability reduction as a result of the higher CO2 adsorption onto the coal surface. Furthermore, as the injection flow rate increased, the contact time of CO2 at the coal surface decreased. Hence, the CO2 adsorption to the coal matrix decreased, and thus the difference in the effective water permeability slightly decreased. CO2 injectivity in fully water-saturated formations increased initially as the gas relative permeability increased, then the injectivity decreased as a result of matrix swelling and absolute permeability reduction. Moreover, the water salinity in coal formations decreased the overall gas relative permeability and increased the water relative permeability. Similar behavior occurred in the presence of N2. It is derived from these observations that the injection of CO2 into highly volatile bituminous coal seams for CO2 sequestration purpose is more efficient as the salt concentration increases, especially at high injection pressures.

scholarly journals A LABORATORY SYSTEM FOR INVESTIGATING OF FLUIDS FLOW CAPACITY THROUGH UNCONSOLIDATED SAND SAMPLES

2020 ◽  
Vol 17 (36) ◽  
pp. 634-645
Author(s):  
Izzat Niazi SULAIMAN ◽  
Yahya Jirjees TAWFEEQ
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Steady State ◽  
Relative Permeability ◽  
Flow Rate ◽  
Pressure Difference ◽  
Absolute Permeability ◽  
Sand Sample ◽  
Flow Capacity ◽  
State Process

Practically all studies of reservoir engineering involve detailed knowledge of fluid flow characteristics. The fluid flow performance in porous media is affected by pressure, flow rate, and volume of single fluid phases. Permeability is a measure of how well a porous media allows the flow of fluids through it. Permeability and porosity form the two significant characteristics of reservoir rocks. This research aimed to present the design of laboratory equipment to test the ability of fluid flow through different sandstone samples. Two sand core samples (coarse sand sample and fine sand sample) were tested. The laboratory findings measurements of porosity, saturation, total permeability, effective permeability, and relative permeability were evaluated. The laboratory tests were performed on partially saturated, unconsolidated core sand for two-phase fluid flow. The experimental work was developed for measuring the flow capacity achieved under the steady-state conditions method. Various grain sizes sands were selected as a porous medium to determine petrophysical properties and fluid flow capacity of the rock sample. Nitrogen and air were utilized as gas-phases, and, for liquid-phases, water was chosen as an injection fluid. The steady-state process method was used to determine the permeability and relative permeability of unconsolidated sands to water flow. Different flow rates were measured for different pressure gradients in a viscose flow. As the flow rate increases, the pressure difference also increased. It can be observed that there are a direct correlation and relationship between the flow rate and the pressure difference. The core plug's absolute permeability was measured using Darcy Equation. Absolute permeability does not depend on fluid characteristics but only on media properties. The sample container contains a more significant amount of sand, decrease the permeability, and therefore requires high pressure for fluid flowing within the sample.

Predictive Modelling of CO2 Injectivity Impairment due to Salt Precipitation and Fines Migration During Sequestration

2021 ◽  
Author(s):  
Muhammad Aslam Md Yusof ◽  
Mohamad Arif Ibrahim ◽  
Muhammad Azfar Mohamed ◽  
Nur Asyraf Md Akhir ◽  
Ismail M Saaid ◽  
...  
Keyword(s):  
Flow Rate ◽  
Particle Concentration ◽  
Co2 Injection ◽  
Permeability Reduction ◽  
Salt Precipitation ◽  
Fines Migration ◽  
Change Models ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Brine Salinity

Abstract Recent studies indicated that reactive interactions between carbon dioxide (CO2), brine, and rock during CO2 sequestration can cause salt precipitation and fines migration. These mechanisms can severely impair the permeability of sandstone which directly affect the injectivity of supercritical CO2 (scCO2). Previous CO2 injectivity change models are ascribed by porosity change due to salt precipitation without considering the alteration contributed by the migration of particles. Therefore, this paper presents the application of response surface methodology to predict the CO2 injectivity change resulting from the combination of salt precipitation and fines migration. The impacts of independent and combined interactions between CO2, brine, and rock parameters were also evaluated by injecting scCO2 into brine saturated sandstone. The core samples were saturated with NaCl brine with salinity between 6,000 ppm to 100,000 ppm. The 0.1, 0.3, and 0.5 wt.% of different-sized hydrophilic silicon dioxide particles (0.005, 0.015, and 0.060 μm) were added to evaluate the effect of fines migration on CO2 injectivity alteration. The pressure drop profiles were recorded throughout the injection process and the CO2 injectivity alteration was represented by the ratio between the initial and final injectivity. The experimental results showed that brine salinity has a greater individual influence on permeability reduction as compared to the influence of particles (jamming ratio and particle concentration) and scCO2 injection flow rate. Moreover, the presence of both fines migration and salt precipitation during CO2 injection was also found to intensify the permeability reduction by 10%, and reaching up to threefold with increasing brine salinity and particle size. The most significant reductions in permeability were observed at higher brine salinities, as more salts are being precipitated out which, in turn, reduces the available pore spaces and leads to a higher jamming ratio. Thus, more particles were blocked and plugged especially at the slimmer pore throats. Based on comprehensive 45 core flooding experimental data, the newly developed model was able to capture a precise correlation between four input variables (brine salinity, injection flow rate, jamming ratio, and particle concentration) and CO2 injectivity changes. The relationship was also statistically validated with reported data from five case studies.

scholarly journals Effect of the Flow Rate on the Relative Permeability Curve in the CO2 and Brine System for CO2 Sequestration

2021 ◽  
Vol 13 (3) ◽  
pp. 1543
Author(s):  
Gu Sun Jeong ◽  
Seil Ki ◽  
Dae Sung Lee ◽  
Ilsik Jang
Keyword(s):  
Relative Permeability ◽  
Flow Rate ◽  
Flow Behavior ◽  
Co2 Injection ◽  
Displacement Efficiency ◽  
Two Phase ◽  
Flow Rates ◽  
Injection Flow ◽  
Wide Range ◽  
Co2 Flow

The relative permeabilities of CO2 and brine are important parameters that account for two-phase flow behavior, CO2 saturation distribution, and injectivity. CO2/brine relative permeability curves from the literature show low endpoint CO2 permeability values and high residual brine saturation values. These are the most distinguishing aspects of the CO2/brine relative permeability from oil/water and gas/oil. In this study, this aspect is investigated experimentally by employing a wide range of CO2 injection flow rates. As a result, all the measurements align with previous studies, having low endpoint relative permeability and high residual brine saturation values. They have obvious relationships with the changes in CO2 flow rates. As the CO2 flow rate increases, the endpoint relative permeability increases, the residual brine saturation decreases, and they converge to specific values. These imply that a high CO2 injection flow rate results in high displacement efficiency, but the improvement in efficiency decreases as the flow rate increases. The reasons are identified with the concept of the viscous and capillary forces, and their significance in the CO2 injection into a reservoir is analyzed.

Steady-State Gas Flow from Tight Shale Matrix Subject to Water Blocking

SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Pål Østebø Andersen
Keyword(s):  
Pressure Drop ◽  
Relative Permeability ◽  
Flow Rate ◽  
Gas Flow ◽  
Gas Production ◽  
Permeability Reduction ◽  
Gas Flow Rate ◽  
Matrix Compression ◽  
Water Blocking ◽  
Matrix Subject

Summary This work studies 1D steady-state flow of gas from compressible shale matrix subject to water blocking toward a neighboring fracture. Water blocking is a capillary end effect causing wetting phase (e.g., water) to accumulate near the transition from matrix to fracture. Hydraulic fracturing is essential for economical shale gas production. Water is frequently used as fracturing fluid, but its accumulation in the matrix can reduce gas mobility and production rate. Gas transport is considered at a defined pressure drop. The model accounts for apparent permeability (slip), compressibility of gas and shale, permeability reduction, saturation tortuosity (reduced relative permeability upon compaction), and multiphase flow parameters like relative permeability and capillary pressure, which depend on wettability. The behavior of gas flow rate and distributions of gas saturation, pressure, and permeability subject to different conditions and the stated mechanisms is explored. Water blockage reduces gas relative permeability over a large zone and reduces the gas flow rate. Despite gas flowing, strong capillary forces sustain mobile water over the entire system. Reducing drawdown gave lower driving force and higher resistance (by water blockage) for gas flow. The results show that 75% reduction of drawdown made the gas flow rate a couple orders of magnitude lower compared to if there was no blockage. The impact was most severe in more water-wetsystems. The blockage caused most of the pressure drop to occur near the outlet. High pressure in the rest of the system reduced effects from gas decompression, matrix compression, and slip-enhanced permeability, whereas rapid gradients in all these effects occurred near the outlet. Gas decompression resulted in an approximately 10 times higher Darcy velocity and pressure gradient near the outlet compared to inlet, which contributed to removing blockage, but the added resistance reduced the gas production rate. Similarly, higher gas Corey exponent associated gas flow with higher pressure drop. The result was less blockage but lower gas production. Slip increased permeability, especially toward the outlet, and contributed to increase in gas production by 16%. Significant matrix compression was associated with permeability reduction and increased Corey exponent in some examples. These effects reduced production and shifted more of the pressure drop toward the outlet. Upstream pressure was more uniform, and less compression and permeability reduction were seen overall compared to a system without water blockage.

scholarly journals Numerical Simulation and Optimization of CO2 Sequestration in Saline Aquifers

2012 ◽  
Author(s):  
Zheming Zhang ◽  
Ramesh Agarwal
Keyword(s):  
Numerical Simulation ◽  
Co2 Sequestration ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Injection Well ◽  
Co2 Injection ◽  
Great Promise ◽  
Saline Aquifer ◽  
Simulation And Optimization ◽  
Co2 Plume

With recent concerns on CO2 emissions from coal fired electricity generation plants; there has been major emphasis on the development of safe and economical Carbon Dioxide Capture and Sequestration (CCS) technology worldwide. Saline reservoirs are attractive geological sites for CO2 sequestration because of their huge capacity for sequestration. Over the last decade, numerical simulation codes have been developed in U.S, Europe and Japan to determine a priori the CO2 storage capacity of a saline aquifer and provide risk assessment with reasonable confidence before the actual deployment of CO2 sequestration can proceed with enormous investment. In U.S, TOUGH2 numerical simulator has been widely used for this purpose. However at present it does not have the capability to determine optimal parameters such as injection rate, injection pressure, injection depth for vertical and horizontal wells etc. for optimization of the CO2 storage capacity and for minimizing the leakage potential by confining the plume migration. This paper describes the development of a “Genetic Algorithm (GA)” based optimizer for TOUGH2 that can be used by the industry with good confidence to optimize the CO2 storage capacity in a saline aquifer of interest. This new code including the TOUGH2 and the GA optimizer is designated as “GATOUGH2”. It has been validated by conducting simulations of three widely used benchmark problems by the CCS researchers worldwide: (a) Study of CO2 plume evolution and leakage through an abandoned well, (b) Study of enhanced CH4 recovery in combination with CO2 storage in depleted gas reservoirs, and (c) Study of CO2 injection into a heterogeneous geological formation. Our results of these simulations are in excellent agreement with those of other researchers obtained with different codes. The validated code has been employed to optimize the proposed water-alternating-gas (WAG) injection scheme for (a) a vertical CO2 injection well and (b) a horizontal CO2 injection well, for optimizing the CO2 sequestration capacity of an aquifer. These optimized calculations are compared with the brute force nearly optimized results obtained by performing a large number of calculations. These comparisons demonstrate the significant efficiency and accuracy of GATOUGH2 as an optimizer for TOUGH2. This capability holds a great promise in studying a host of other problems in CO2 sequestration such as how to optimally accelerate the capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.

Modelling and Upscaling Unstable Miscible Displacement Processes: Characterisation of Physical Instabilities

2021 ◽  
Author(s):  
Precious Ogbeiwi ◽  
Karl Stephen
Keyword(s):  
Relative Permeability ◽  
Transport Coefficients ◽  
Miscible Displacement ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Fine Grid ◽  
Flow Models ◽  
Reservoir Models ◽  
Flood Simulations ◽  
Physical Instabilities

Abstract The compositional simulations are required to model CO2 flooding are computationally expensive particularly for fine-gridded models that have high resolutions, and many components. Upscaling procedures can be used in the subsurface flow models to reduce the high computation requirements of the fine grid simulations and accurately model miscible CO2 flooding. However, the effects of physical instabilities are often not well represented and captured by the upscaling procedures. This paper presents an approach for upscaling of miscible displacements is presented which adequately represents physical instabilities such as viscous and heterogeneity induced fingering on coarser grids using pseudoisation techniques. The approach was applied to compositional numerical simulations of two-dimensional reservoir models with a focus on CO2 injection. Our approach is based on the pseudoisation of relative permeability and the application of transport coefficients to upscale viscous fingering and heterogeneity-induced channelling in a multi-contact miscible CO2 injection. Pseudo-relative permeability curves were computed using a pseudoisation technique and applied in combination with transport coefficients to upscale the behaviour of fine-scale miscible CO2 flood simulations to coarser scales. The accuracy of the results of the pseudoisation procedures were assessed by applying statistical analysis to compare them to the results of the fine grid simulations. It is observed from the results that the coarse models provide accurate predictions of the miscible displacement process and that the fingering regimes are adequately captured in the coarse models. The study presents a framework that can be employed to represent the dynamics of physical instabilities associated with miscible CO2 displacements in upscaled coarser grid reservoir models.

scholarly journals The Role of Coal Mechanical Characteristics on Reservoir Permeability Evolution and Its Effects on CO2 Sequestration and Enhanced Coalbed Methane Recovery

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-28
Author(s):  
Hao Han ◽  
Shun Liang ◽  
Yaowu Liang ◽  
Xuehai Fu ◽  
Junqiang Kang ◽  
...  
Keyword(s):  
Elastic Modulus ◽  
Coal Seam ◽  
Coalbed Methane ◽  
Co2 Sequestration ◽  
Mechanical Characteristics ◽  
Co2 Adsorption ◽  
Co2 Injection ◽  
Permeability Change ◽  
Coal Seams ◽  
Enhanced Coalbed Methane

Elastic modulus is an important parameter affecting the permeability change in the process of coalbed methane (CBM)/enhanced coalbed methane (ECBM) production, which will change with the variable gas content. Much research focuses on the constant value of elastic modulus; however, variable stiffness of coal during CO2 injection has been considered in this work. The coupled thermo-hydro-mechanical (THM) model is established and then validated by primary production data, as well as being applied in the prediction of CO2/N2-ECBM recovery. The results show that the harder coal seam is beneficial to primary production, while the softer coal seam results in greater CO2/N2-ECBM recovery and CO2 sequestration. N2 and CO2 mixture injection could be applied to balance early N2 breakthrough and pronounced matrix swelling induced by CO2 adsorption, and to prolong the process of effective CH4 recovery. Besides, reduction in stiffness of coal seam during CO2 injection would moderate the significant permeability loss induced by matrix swelling. With the increase of the weakening degree of coal seam stiffness, CO2 cumulative storage also shows an increasing trend. Neglecting the weakening effect of CO2 adsorption on coal seam stiffness could underestimate the injection capacity of CO2. Injection of hot CO2 could improve the permeability around injection well and then enhance CO2 cumulative storage and CBM recovery. Furthermore, compared with ECBM production, injection temperature is more favorable for CO2 storage, especially within hard coal seams. Care should be considered that significant permeability change is induced by mechanical characteristics alterations in deep burial coal seams in further study, especially for CO2-ECBM projects.

Use of Transient Data To Calculate Absolute Permeability and Average Fluid Saturations

2010 ◽  
Vol 13 (02) ◽  
pp. 306-312 ◽  
Author(s):  
Medhat M. Kamal ◽  
Yan Pan
Keyword(s):  
Relative Permeability ◽  
Reservoir Simulation ◽  
Surface Flow ◽  
Absolute Permeability ◽  
Phase Flow ◽  
Simulation Studies ◽  
Flow Rates ◽  
Reservoir Performance ◽  
Transient Data ◽  
Relative Permeability Curves

Summary A new well-testing-analysis method is presented. The method allows for calculating the absolute permeability of the formation in the area influenced by the test and the average saturations in this area. Traditional pressure-transient-analysis methods have been developed and are completely adequate for single-phase flow in the reservoir. The proposed method is not intended for these conditions. The method applies to two-phase flow in the reservoir (oil and water or oil and gas). Future expansion to three-phase flow is possible. Current analysis methods yield only the effective permeability for the dominant flowing phase and the "total mobility" of all phases. The new method uses the surface-flow rates and fluid properties of the flowing phases and the same relative permeability relations used in characterizing the reservoir and predicting its future performance. The method has been verified by comparing the results from analyzing several synthetic tests that were produced by a numerical simulator with the input values. Use of the method with field data is also described. The new method could be applied wherever values of absolute permeability or fluid saturations are used in predicting well and reservoir performance. Probably, the major impact would be in reservoir simulation studies in which the need to transform welltesting permeability to simulator input values is eliminated and additional parameters (fluids saturations) become available to help history match the reservoir performance. This work will also help in predicting well flow rates and in situations in which absolute permeability changes with time (e.g., from compaction). Results showed that the values of absolute permeability in water/oil cases could be reproduced within 3% of the correct values and within 5% of the correct values in gas/oil cases. Errors in calculating the fluid saturations were even lower. One of the main advantages of this method is that the relative permeability curves used in calculating the absolute permeability and average saturations, and later on in numerical reservoir simulation studies, are the same, ensuring a consistent process. The proposed method does not address the question of which set of relative permeability curves should be used. This question should be answered by the engineer performing the reservoir engineering/simulation study. The proposed method mainly is meant to provide consistent results for predicting the reservoir performance using whatever relative permeability relations that are being used in the reservoir simulation model. The method does not induce any additional errors in determining the average saturation or absolute permeability over what may result from using these specific relative permeability curves in the reservoir simulation study. The impact of this study will be to expand the use of information already contained in transient data and surface flow rates of all phases. The results will provide engineers with additional parameters to improve and speed up history matching and the prediction of well and reservoir performances in just about all studies.

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