Experimental Analysis of CO2 Injection on Permeability of Vuggy Carbonate Aquifers

2012 ◽  
Vol 135 (1) ◽  
Author(s):  
Ibrahim M. Mohamed ◽  
Jia He ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Flow Rate ◽  
Initial Permeability ◽  
Co2 Injection ◽  
Reaction Products ◽  
The Core ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Injection Scheme ◽  
Core Permeability ◽  
Permeability Alteration

Reactions of CO2 with formation rock may lead to an enhancement in the permeability due to rock dissolution, or damage (reduction in the core permeability) because of the precipitation of reaction products. The reaction is affected by aquifer conditions (pressure, temperature, initial porosity, and permeability), and the injection scheme (injection flow rate, CO2:brine volumetric ratio, and the injection time). The effects of temperature, injection flow rate, and injection scheme on the permeability alteration due to CO2 injection into heterogeneous dolomite rock is addressed experimentally in this paper. Twenty coreflood tests were conducted using Silurian dolomite cores. Thirty pore volumes of CO2 and brine were injected in water alternating gas (WAG) scheme under supercritical conditions at temperatures ranging from 21 to 121 °C, and injection rates of 2.0–5.0 cm3/min. Concentrations of Ca++, Mg++, and Na+ were measured in the core effluent samples. Permeability alteration was evaluated by measuring the permeability of the cores before and after the experiment. Two sources of damage in permeability were noted in this study: (1) due to precipitation of calcium carbonate, and (2) due to migration of clay minerals present in the core. Temperature and injection scheme don't have a clear impact on the core permeability. A good correlation between the initial and final core permeability was noted, and the ratio of final permeability to the initial permeability is lower for low permeability cores.

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.

Effects of CO2/Rock/Formation Brine Parameters on CO2 Injectivity for Sequestration

SPE Journal ◽  
2020 ◽  
pp. 1-14
Author(s):  
Muhammad Aslam Md Yusof ◽  
Mohamad Arif Ibrahim ◽  
Mazlin Idress ◽  
Ahmad Kamal Idris ◽  
Ismail Mohd Saaid ◽  
...  
Keyword(s):  
Co2 Injection ◽  
Co2 Flooding ◽  
Rock Permeability ◽  
X Ray ◽  
The Core ◽  
Core Samples ◽  
Injection Scheme ◽  
Principal Factors ◽  
Carbon Dioxide Co2 ◽  
Permeability Alteration

Summary The injection of carbon dioxide (CO2) into saline aquifers is highlighted as an effective technique to permanently secure anthropogenic gas produced from high CO2 gas fields in the Southeast Asia region. However, previous studies indicate that CO2 injectivity can be impaired primarily due to the interactions between CO2/brine/rock. In this paper, we investigate the effect of a CO2 injection scheme, rock permeability, brine type, and salinity on CO2 injectivity, which is presented by permeability alteration. A CO2 coreflood experiment and the characterization of the rock and effluent produced are presented. Furthermore, core samples with different permeabilities of the typical geological storage for sequestration were selected and analyzed using X-ray fluorescence (XRF), X-ray diffraction (XRD), and field-emission scanning electron microscopy equipped with energy dispersive X-ray spectroscopy (FESEM-EDX). The cores were then saturated with synthetic brine composed of 6,000, 30,000 or 100,000 parts per million (ppm) of either sodium chloride (NaCl), potassium chloride (KCl), or calcium chloride (CaCl2). Subsequently, the core samples were injected by either supercritical CO2 (scCO2), CO2-saturated brine, or CO2-saturated brine followed by scCO2. The fines particles from the collected effluent were separated for further analysis. The results indicate that a CO2 injection scheme, injection flow rate, brine salinity, and initial rock permeability are the principal factors that contribute to the permeability alteration of the core samples. It was also found from FESEM-EDX analysis of the produced fines that the precipitated salt, silica grains, and kaolinite migrated during scCO2 injection, suggesting the dissolution and precipitation of minerals. This phenomenon led to the migration of particles, some of which plugged the pore spaces and reduced the permeability. Besides, the core saturated with CaCl2 brine was the only sample with improvement in permeability after the CO2 flooding experiment.

scholarly journals Evaluation of the impact of viscosity, injection volume, and injection flow rate on subcutaneous injection tolerance

2015 ◽  
pp. 473 ◽  
Author(s):  
Florence Schwarzenbach ◽  
Cecile Berteau ◽  
Orchidee Filipe-Santos ◽  
Tao Wang ◽  
Humberto Rojas ◽  
...  
Keyword(s):  
Flow Rate ◽  
Subcutaneous Injection ◽  
Injection Volume ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
The Impact

scholarly journals Effect of Injection Flow Rate on Product Gas Quality in Underground Coal Gasification (UCG) Based on Laboratory Scale Experiment: Development of Co-Axial UCG System

Energies ◽  
2017 ◽  
Vol 10 (2) ◽  
pp. 238 ◽  
Author(s):  
Akihiro Hamanaka ◽  
Fa-qiang Su ◽  
Ken-ichi Itakura ◽  
Kazuhiro Takahashi ◽  
Jun-ichi Kodama ◽  
...  
Keyword(s):  
Flow Rate ◽  
Coal Gasification ◽  
Laboratory Scale ◽  
Underground Coal Gasification ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Product Gas ◽  
Scale Experiment

scholarly journals Characterization of venturi injector using dimensional analysis

2019 ◽  
Vol 23 (7) ◽  
pp. 484-491 ◽  
Author(s):  
Luiz R. Sobenko ◽  
José A. Frizzone ◽  
Antonio P. de Camargo ◽  
Ezequiel Saretta ◽  
Hermes S. da Rocha
Keyword(s):  
Dimensional Analysis ◽  
Flow Rate ◽  
Injection Rate ◽  
Operating Conditions ◽  
Functional Tests ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Hydraulic Conditions ◽  
Fluid Properties ◽  
Pi Theorem

ABSTRACT Venturi injectors are commonly employed for fertigation purposes in agriculture, in which they draw fertilizer from a tank into the irrigation pipeline. The knowledge of the amount of liquid injected by this device is used to ensure an adequate fertigation operation and management. The objectives of this research were (1) to carry out functional tests of Venturi injectors following requirements stated by ISO 15873; and (2) to model the injection rate using dimensional analysis by the Buckingham Pi theorem. Four models of Venturi injectors were submitted to functional tests using clean water as motive and injected fluid. A general model for predicting injection flow rate was proposed and validated. In this model, the injection flow rate depends on the fluid properties, operating hydraulic conditions and geometrical characteristics of the Venturi injector. Another model for estimating motive flow rate as a function of inlet pressure and differential pressure was adjusted and validated for each size of Venturi injector. Finally, an example of an application was presented. The Venturi injector size was selected to fulfill the requirements of the application and the operating conditions were estimated using the proposed models.

Acid Stimulation Used in In-Situ Leaching Uranium

2010 ◽  
Author(s):  
Wen-sheng Liao ◽  
Li-min Wang ◽  
Yi-xuan Yao ◽  
Guo-ping Jiang ◽  
Hai-jun Zhao ◽  
...  
Keyword(s):  
Formic Acid ◽  
Injection Rate ◽  
Low Permeability ◽  
Reaction Products ◽  
Treatment Results ◽  
The Core ◽  
Fluid Systems ◽  
Core Permeability ◽  
Significant Production

Acidization was studied on a uranium sandstone deposit in Inner Mongolia with low–permeability and heavy calcium cementation. Acid dissolving test indicates that hydrochloric acid, formic acid and mud acid can easily dissolve formation minerals. With proper volumes and concentrations of acids used, the risk of precipitation of reaction products could be minimized. Core flow acidizing trial shows that the acidic fluid systems of hydrochloride acid, formic acid or acetic acid can significantly improve the core permeability. The average permeability has increased by 763 percent for the above three systems. But mud acid didn’t increase the core permeability; on the contrary, it caused formation damage, and led to lowering permeability. In the pilot test, the injection rate has improved by 118 percent for 6 wells. The acid treatment results indicate that a significant production enhancement of wellfields can be achieved by acid stimulation.

scholarly journals Influence of mineralization and injection flow rate on flow patterns in three-dimensional porous media

2019 ◽  
Vol 21 (27) ◽  
pp. 14605-14611 ◽  
Author(s):  
R. Moosavi ◽  
A. Kumar ◽  
A. De Wit ◽  
M. Schröter
Keyword(s):  
Porous Media ◽  
Flow Field ◽  
Flow Rate ◽  
Three Dimensional ◽  
Flow Patterns ◽  
Low Flow ◽  
Flow Rates ◽  
Injection Flow Rate ◽  
Injection Flow

At low flow rates, the precipitate forming at the miscible interface between two reactive solutions guides the evolution of the flow field.

The Coupling Model of Wellbore Conduit Flow, Throttled Flow and Formation Seepage in Water Injection Wells

2012 ◽  
Vol 594-597 ◽  
pp. 2486-2489
Author(s):  
Bao Jun Liu ◽  
Hai Xia Shi ◽  
Yun Sheng Cai
Keyword(s):  
Flow Rate ◽  
Water Injection ◽  
Coupling Model ◽  
Water Flooding ◽  
Finite Radius ◽  
Injection Wells ◽  
Conduit Flow ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Low Efficiency

Separate layer water flooding is adopted in most oilfields in China and the injection flow rate is controlled by the diameter of water nozzle of each layer. In order to ensure the effect of water injection, applicable water nozzles need to be adjusted to meet the requirements of injection flow rate. The adjustment is commonly realized according to experience, which leads to long adjustment time and low efficiency. To solve this problem, the coupling model of wellbore conduit flow, throttled flow and formation seepage was established based on theoretical analysis, which could provide theoretical basis for water nozzles adjustment. In the model, the Bernoulli Equation was adopted to analyze wellbore conduit flow; indoor experiments were done to research throttled flow; the research object of the seepage was finite radius well in homogeneous infinite formation.

Propagation and Retention of Viscoelastic Surfactants Following Matrix-Acidizing Treatments in Carbonate Cores

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 993-1001 ◽  
Author(s):  
M.. Yu ◽  
M.A.. A. Mahmoud ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Flow Rate ◽  
Injection Rate ◽  
Low Flow ◽  
Gas Wells ◽  
The Core ◽  
Injection Flow ◽  
Carbonate Cores ◽  
Glycol Monobutyl Ether ◽  
Viscoelastic Surfactants ◽  
Viscoelastic Surfactant

Summary Viscoelastic surfactants have been used extensively in the field. They have the ability to form long rod-like micelles with an increase in pH and calcium concentration, which results in increasing the viscosity and elasticity of partially spent acids. There is ongoing debate in the industry about whether the gel generated by these surfactants causes formation damage, especially in dry-gas wells. The objectives of the present study are to quantitatively determine surfactant retention in calcite cores and assess the benefits of using mutual solvents to break the surfactant gel formed inside the cores. Coreflood tests were performed using Pink Desert limestone cores (1.5 in. in diameter and 20 in. in length). The cores were injected with a surfactant-based acid that contained 15 wt% HCl, 7 vol% viscoelastic surfactant, and 0.3 vol% corrosion inhibitor. Coreflood tests were conducted at a constant injection flow rate ranging from 1.5 to 40 cm3/min. Surfactant and calcium concentrations were measured in the injected acid and core effluent. Mutual solvent (ethylene glycol monobutyl ether) was used in several tests to break surfactant gel. Propagation of viscoelastic surfactants in linear calcite cores was found to be a function of flow rate. Surfactant lagged calcium in the core effluent samples, especially at low flow rates. The volume of acid needed to break through the core and the amount of surfactant retained varied with acid injection rate, and exhibited a minimum at 10 cm3/min. A significant amount of surfactant was retained in the cores. Injection of 2 pore volumes (PV) of 10 vol% mutual solvent removed only 20% of the surfactant injected. Based on these results, there is a need to use internal breakers when surfactant-based acids are used in dry-gas wells or water injectors.

scholarly journals Seismic Response to Injection Well Stimulation in a High-Temperature, High-Permeability Reservoir

2021 ◽  
Author(s):  
C Hopp ◽  
Steven Sewell ◽  
S Mroczek ◽  
Martha Savage ◽  
John Townend
Keyword(s):  
High Temperature ◽  
Compressive Stress ◽  
Flow Rate ◽  
Matched Filter ◽  
Taupo Volcanic Zone ◽  
Valuable Insight ◽  
High Permeability ◽  
Injection Flow Rate ◽  
Well Stimulation ◽  
Injection Flow

©2019. American Geophysical Union. All Rights Reserved. Fluid injection into the Earth's crust can induce seismic events that cause damage to local infrastructure but also offer valuable insight into seismogenesis. The factors that influence the magnitude, location, and number of induced events remain poorly understood but include injection flow rate and pressure as well as reservoir temperature and permeability. The relationship between injection parameters and injection-induced seismicity in high-temperature, high-permeability reservoirs has not been extensively studied. Here we focus on the Ngatamariki geothermal field in the central Taupō Volcanic Zone, New Zealand, where three stimulation/injection tests have occurred since 2012. We present a catalog of seismicity from 2012 to 2015 created using a matched-filter detection technique. We analyze the stress state in the reservoir during the injection tests from first motion-derived focal mechanisms, yielding an average direction of maximum horizontal compressive stress (SHmax) consistent with the regional NE-SW trend. However, there is significant variation in the direction of maximum compressive stress (σ1), which may reflect geological differences between wells. We use the ratio of injection flow rate to overpressure, referred to as injectivity index, as a proxy for near-well permeability and compare changes in injectivity index to spatiotemporal characteristics of seismicity accompanying each test. Observed increases in injectivity index are generally poorly correlated with seismicity, suggesting that the locations of microearthquakes are not coincident with the zone of stimulation (i.e., increased permeability). Our findings augment a growing body of work suggesting that aseismic opening or slip, rather than seismic shear, is the active process driving well stimulation in many environments.

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