Open access peer-reviewed chapter

CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation and Fines Mobilization

Written By

Yen A. Sokama-Neuyam, Muhammad A.M. Yusof and Shadrack K. Owusu

Submitted: 22 February 2022 Reviewed: 07 April 2022 Published: 28 May 2022

DOI: 10.5772/intechopen.104854

From the Edited Volume

Carbon Sequestration

Edited by Suriyanarayanan Sarvajayakesavalu and Kannan Karthikeyan

Chapter metrics overview

332 Chapter Downloads

View Full Metrics

Abstract

Climate change is now considered the greatest threat to global health and security. Greenhouse effect, which results in global warming, is considered the main driver of climate change. Carbon dioxide (CO2) emission has been identified as the largest contributor to global warming. The Paris Agreement, which is the biggest international treaty on Climate Change, has an ambitious goal to reach Net Zero CO2 emission by 2050. Carbon Capture, Utilization and Storage (CCUS) is the most promising approach in the portfolio of options to reduce CO2 emission. A good geological CCUS facility must have a high storage potential and robust containment efficiency. Storage potential depends on the storage capacity and well injectivity. The major target geological facilities for CO2 storage include deep saline reservoirs, depleted oil and gas reservoirs, Enhanced Oil Recovery (EOR) wells, and unmineable coal seams. Deep saline formations have the highest storage potential but challenging well injectivity. Mineral dissolution, salt precipitation, and fines mobilization are the main mechanisms responsible for CO2 injectivity impairment in saline reservoirs. This chapter reviews literature spanning several decades of work on CO2 injectivity impairment mechanisms especially in deep saline formations and their technical and economic impact on CCUS projects.

Keywords

  • CO2 injectivity
  • mineral dissolution
  • salt precipitation
  • fines mobilization

1. Introduction

Since last decade, there has been a growing concern of the negative impacts of global climate change. In the last century, scientists believe that carbon dioxide (CO2) emission is has been the main component responsible for approximately three-quarters of global greenhouse gas emission. A roadmap developed to combat climate change has outlined 10 scalable solutions clustered into categories of social transformative, governance improvement, market and regulation-based solutions, technological innovation and transformation, and lastly natural and ecosystem management. While some proposed mitigation techniques focus on reduction of CO2 emission, Carbon Capture, Utilization and Storage (CCUS) technology can aim at achieving lower CO2 amount in the atmosphere by capturing and storing the anthropogenic gas in a geological storage. Geological storage of CO2 in depleted oil and gas reservoirs, deep saline reservoirs, unmineable coal seams or injected into active oil and gas reservoirs for Enhanced Oil Recovery (EOR) are currently a well-accepted method of storing CO2. For economic reasons, CO2 is being injected at the highest possible rates through limited number of wells. This could trigger injectivity-related issues due to complex interactions between CO2, brine and rock initiated in the aquifer. This makes CO2 injectivity not only a technical challenge but also an economic consideration.

This chapter presents a comprehensive discussion on how the various mechanisms contributed by the fluid-rock interactions during CO2 sequestration affect CO2 injectivity. The chapter begins by laying out the theoretical dimensions of CO2 sequestration. This is followed by a brief overview of different CO2 injectivity impairment mechanisms, focusing on the two main themes: salt precipitation and fines migration. The experimental findings from previous researchers have also been discussed and some findings remarks made. The insights gained from this study may be valuable to the rapidly expanding field of carbon sequestration.

Advertisement

2. Climate change, a global challenge

Climate Change is now considered the greatest threat to global health and security. Greenhouse effect, which propels global warming, has been identified as the main driver of Climate Change. The rising of global temperature is intricately linked with many other environmental concerns such as fragile ecosystem, melting glaciers, increasing sea level, acidification of sea water and increased flooding and droughts [1]. This climate challenge is also affecting the social community which can lead to immigration and conflicts over borders and natural resources such as water. More importantly, it could severely threaten food security that may affect about 3 billion of poor people in terms of access to food supply. These series of concerns are recognized as climate change and it is well accepted that to prevent its occurrence, greenhouse gas emission has to be reduced significantly over the twenty-first century [2]. The gases which are mainly responsible for the greenhouse effect include methane, carbon dioxide (CO2), nitrous oxide, water vapor, and fluorinated gases.

CO2 generated mainly from anthropogenic activities is the largest contributor to global warming. By 2020, the concentration of CO2 in the atmosphere had risen to 48% above its pre-industrial level [3, 4]. An increase of 2°C above pre-industrial average temperature could induce serious negative impacts on the natural environment and human health. The Paris Agreement, which is the biggest international treaty on Climate Change is determined to limit global warming to about 1.5°C, compared to pre-industrial levels, with an ambitious goal to reach NetZero CO2 emission by 2050 [5, 6, 7].

The anthropogenic activities with highest carbon footprint include the burning of fossil fuel for power generation and the production of materials. Power generation from fossil fuels is responsible for over 70% of the global CO2 emissions [1]. Cumulatively, fossil fuel contributed about 84% of the World’s primary energy consumption by 2019 and the world is expected to rely heavily on fossil fuels for its energy needs, at least within the short to medium term. Another major source of CO2 emission is the production of materials with high carbon and energy footprint. The notable of such materials is Portland cement which is the main building material used in most countries in the world. Portland cement production is responsible for about 5% of global CO2 emission [8]. About 2% of the total global energy consumption is used to produce Portland cement. Widespread use of energy efficient power generators, investing in renewable energy, Carbon Capture, Utilization and Storage (CCUS) remains the best options for reducing CO2 emission from burning of fossil fuels and achieving a faster transition to green energy.

Advertisement

3. Geological storage of CO2

CCUS is considered a viable option to reduce CO2 emission, sustain exploration and production of fossil fuel for the short to medium term and eventually transition to a full green energy in the long term [9, 10]. Among the proposed CO2 emission reduction strategies, CCUS provides the highest emission reduction potential [11]. Generally, CCUS involves the (1) capture of CO2 from large industrial emission sources and direct air capture points (2) the transportation of the captured gas to utilization, conversion, or storage facilities and (3) the utilization of the gas as feedstock in industrial processes, conversion to other products or the injection of the gas into geological storage facilities. In terms of geological storage, the injected CO2 may be stored in depleted oil and gas reservoirs, deep saline reservoirs, unmineable coal seams or injected into active oil and gas reservoirs for Enhanced Oil Recovery (EOR) [12, 13].

CCUS system, although simple in concept, would require significant investment of capital, new technology and time [14]. Besides, many current policies also need to be revised and new legal and regulations framework has to be introduced that require support from local authorities, governments and international bodies [15]. Investigation by the International Energy Agency (IEA) have shown that CCUS can contribute up to about 14% reduction in global greenhouse gas emissions required to limit global warming to 2°C by 2050 [16].

3.1 Storage in saline aquifers

Saline aquifer refers to a deep, large geological formation consisting permeable sedimentary or carbonate rock types that are saturated with formation water or brines, non-potable water, containing high concentration of dissolved salts [17]. It is buried under a layer of non- or low-permeability rocks that serve as a cap rock to prohibit the fluid flowing upwards to the surface. The saline aquifer can be located both onshore and offshore and normally found at depth greater (more than 800 metres) than aquifers that contain potable water [18]. Deep saline formations have enormous potential for CO2 storage in terms of volumetric storage capacity [19, 20]. On a global scale, deep saline reservoirs have the capacity to hold between 20 and 500% of the projected CO2 emissions by 2050 [9, 21, 22]. Thus, worldwide CO2 storage potential of deep saline reservoirs ranges from 400 to 10,000 Gt CO2. Deep saline aquifers, usually at depths between 700 and 1000 m, hold large quantities of high salinity formation brines [23].

Although the natural content of these reservoirs has no direct commercial value, the chemical composition of the formation brine makes them suitable for CO2 mineralization. In deep saline aquifers, the injected CO2 could be sequestered through hydrodynamic trapping where the gas is trapped beneath a caprock, residual trapping where the rock contains residual saturation of CO2, solubility trapping where the gas dissolves in the formation brine and mineral trapping where CO2 reacts with Ca, Fe or Mg to form stable carbonate precipitates [24, 25]. Lack of additional economic benefits except carbon tax incentives in some countries, makes CO2 storage in saline aquifers less attractive to the oil and gas industry.

3.2 CO2 enhanced oil recovery

CO2-EOR is a tertiary oil recovery technique where CO2 and usually other fluids such as water or brine is injected into the reservoir to achieve miscibility with the oil and recover residual oil. In addition to extraction of residual oil, the injected gas provides pressure support and could remain stored permanently after the recovery process. Under subsurface conditions, CO2 mixes with oil above a certain minimum miscibility pressure (MMP), reducing the capillary effect that retain the oil in place [26, 27, 28]. There are four main underlying mechanisms of CO2-EOR as outlined by Rojas and Ali [29] and Tunio et al. [30] which include (1) oil swelling; (2) reduction of oil viscosity; (3) reduction of oil and water density; and (4) extraction of oil components.

Alternative forms of CO2-EOR have been developed over the past years, including continuous CO2 injection, continuous CO2 injection followed by water, water-alternating gas (WAG) and WAG followed by gas or water [31, 32, 33]. To improve sweep efficiency, carbonated water injection has also been used as a viable alternative [34, 35]. Other emerging injection schemes include CO2 low salinity water alternating gas (CO2-LSWAG) injection under miscible CO2 displacement conditions [36, 37, 38]. Depleted oil and gas reservoirs are also attractive candidates for CO2 storage due to the potential to reuse some of the production equipment and geological data collected over the producing life of the reservoirs to lower exploration cost and reduce the risk associated with CO2 storage. It has been reported that depleted oil and gas reservoirs could hold about 45% of the projected CO2 emissions by 2050 [9].

3.3 CO2 injection into unconventional reservoirs

The two main unconventional formations where CO2 injection is promising are coal seams and shale gas reservoirs. CO2 enhanced coalbed methane recovery (CO2-ECBM) has the potential to store large volumes of CO2 in deep unmineable coal seams while improving the efficiency of coal bed methane recovery [39, 40]. The injected CO2 displaces methane and remain sequestered in the coal seams as CO2 is preferentially adsorbed onto coal seams, thus releasing the coal bed methane which can then be produced as free gas [41]. Based on the simple assumption that, for every CH4 molecule, two molecules of CO2 can be stored, IEA-GHG [42] estimated that about 220 GT of CO2 could be stored in deep unmineable coal formations worldwide.

The potential to store CO2 in organic-rich gas shales is attracting increasing interest, especially in countries that have extensive shale deposits [43, 44, 45]. Although still in early-stage research, CO2 injection into organic-rich gas shales could provide dual benefits: an economic benefit from the incremental recovery of adsorbed methane, and an environmental benefit of secure CO2 storage.

Advertisement

4. The prerequisites of CCUS

A viable candidate for CCUS must meet a threshold well injectivity required to inject large volumes of CO2 at high injection rates through a minimum number of wells, adequate storage capacity to hold large volumes of CO2 and robust containment to permanently isolate the sequestered gas from the environment [16]. Storage capacity and well injectivity defines the storage potential of a geological storage facility [11, 46, 47].

4.1 Storage capacity

Implementation of CCUS technology require accurate estimation of the pore space available in the reservoir rock to hold the injected CO2 [48, 49, 50, 51]. The storage capacity estimated can be of different levels of certainty and cost depending on the scale and resolution. The various CO2 trapping mechanisms in deep saline aquifers, namely structural and stratigraphic trapping, residual gas trapping, solubility trapping, mineral trapping and hydrodynamic trapping, which occur at different times during the storage, must be considered in the estimation to obtain a representative estimate [51]. Other parameters that affect the storage capacity include in situ pressure, injectivity, temperature, permeability, and rock compressibility.

The volume of CO2 that can be commercially sequestered in a reservoir within a specific period, using available technology, under current economic conditions, operating methods and governmental regulations has been termed the CO2 storage reserve [11, 48]. The USDOE [52] has developed a simplified model to quantify the storage capacity of deep saline formations which is given by:

MCO2=VAϕTρCO2EsE1

In Eq. (1), MCO2 is the mass of CO2 that can be stored, VA is the bulk volume of the aquifer, ϕT is the effective porosity of the aquifer, ρCO2 is the density of CO2 at reservoir conditions and Es is the storage efficiency. The storage efficiency expresses the degree of filling the reservoir [11], also defined as the ratio of the volume occupied by CO2 to the total accessible pore volume of the reservoir [53]:

Es=VCO2VporeE2

In Eq. (2), VCO2 is the volume of injected CO2 and Vpore is the accessible reservoir pore volume available for CO2 storage. Eq. (1) and (2) can be coupled to estimate the volumetric CO2 storage capacity of a given deep saline reservoir. CO2 storage efficiency in deep saline formations depends on the reservoir rock properties (porosity, permeability, net to gross, thickness and area), the efficiency of water displacement by injected CO2 and the degree of conformance of the aquifer [11].

Bachu et al. [54] have also proposed a model to estimate the theoretical CO2 storage capacity of depleted oil and gas reservoirs, based on the assumption that the entire pore space originally occupied by hydrocarbons can be filled by CO2 and that CO2 can be injected until the reservoir pressure reaches the original pressure of the virgin reservoir. These assumptions can be valid if the reservoir is not in contact with an aquifer or already flooded during secondary and tertiary recovery. For practical purposes, an effective storage capacity could be defined to incorporate other important parameters such as displacement efficiency, gravity effects, residual oil and water saturation, reservoir heterogeneity, rock-fluid interactions, and formation damage.

4.2 Well injectivity

The injectivity of a reservoir measures the amount of CO2 an injection well can receive without fracturing the formation [11]. Well injectivity can be expressed with an injectivity index, I, often defined as the ratio of volumetric injection flow rate to the pressure drop [55, 56]. For a homogeneous and isotropic reservoir, the steady-state CO2 well injectivity index can be expressed as:

I=qp=ρCO2,resρCO2,sc2πkhlnrerw+sμCO2E3

In Eq. (3), q is the volumetric injection flow rate, p is the pressure drop, ρCO2,res is the density of CO2 under reservoir conditions, ρCO2,sc is the density of CO2 under standard conditions, kh is the permeability-thickness product, re is the radius of the reservoir boundary, rw is the well radius, s is the skin factor and μCO2is the viscosity of CO2 under reservoir conditions. Well injectivity determines the number of wells required to inject a specific quantity of CO2 into the reservoir. This makes injectivity an important factor for both technical and economic evaluation of CO2 storage projects [56, 57].

4.3 Containment efficiency

Containment efficiency characterizes the assurance of containment of the injected CO2. The ultimate objective of a CCUS project is to permanently isolate the sequestered CO2 from the environment. Since formation water is denser than supercritical CO2, the CO2 plume tends to rise to the top of the reservoir, where it accumulates beneath the caprock. The containment efficiency of a geological trap is therefore strongly dependent on the seal potential or the ability of the caprock to confine the injected gas and prevent leakage into overlying formations and eventually back into the atmosphere [58]. The caprock must have the lateral extent and geomechanical strength to retain the full CO2 column height.

The integrity of the caprock could be compromised by mechanical deformation induced by pressure from CO2 injection or through geochemical CO2-rock-brine interactions which may dissolve or precipitate minerals to increase the permeability of the caprock [59]. Wells have also been identified as probable leakage pathways. Therefore, robust wellbore integrity is important to prevent leakage through wells.

Advertisement

5. CO2 well injectivity impairment mechanisms

CO2 injectivity impairment is a technical and economic constraint on geological storage of CO2 [12, 60, 61]. Under typical storage conditions, several factors could influence CO2 injectivity because of the complex interplay of chemical and physical phenomena in the reservoir, especially in the injection area of the wellbore [46, 62, 63]. The injection area of the wellbore has the highest flactuations of temperature, pressure and flux, making it one of the most important sections of the formation for well injectivity impairment analysis. Lombard et al. [64] identified three main mechanisms responsible for CO2 injectivity impairment: Geochemical, geomechanical and transport phenomena (Figure 1). Later Torsaeter et al. [65] did an extensive review on other CO2 injectivity impairment mechanisms that they recommend should be given close attention in addition to salt precipitation effects. The geochemical mechanisms involve CO2-brine-rock interactions, mineral dissolution, and precipitation. The transport effects include drying of the reservoir rock and fines mobilization. The geomechanical effects, which include borehole deformation has not been given enough research attention compared to the geochemical and transport mechanisms. These phenomena depend on the physical and chemical properties of injected CO2 which are in turn driven by reservoir conditions and rock properties.

Figure 1.

CO2 injectivity impairment mechanisms (after Lombard et al., [64]).

5.1 Geochemical effects

5.1.1 Effect of mineral dissolution

Mineral dissolution and salt precipitation are the two main geochemical CO2 injectivity impairment mechanisms [64]. The injected CO2 could dissolve in formation brine at the CO2-brine interface, altering the concentration of aquifer fluid, thus leading to precipitation. Regardless of rock composition, the progressive dissolution of CO2 in the brine (formation water) forms carbonic acid that leads to a reduction in pH to about 3–5 [66, 67]. The following reactions occur at the interface between both media

CO2g+H2OlH2CO3aqH2CO3aqHaq++HCO3aqE4

Interactions between CO2 and brine forms carbonic acid and then bicarbonates. In the presence of CaCO3, MgCO3 and FeCO3, the following reactions would lead to formation of water-soluble bicarbonates.

H2O+CO2+CaCO3CaHCO32
H2O+CO2+MgCO3MgHCO32E5
H2O+CO2+FeCO3FeHCO32

Moreover, the bicarbonates could react with cations in the rock and formation water to form stable carbonates which later could aggregate into small particles or form a scale on the pore walls [68, 69, 70]. CO2-brine-rock batch reaction under typical storage conditions have shown various amounts of dissolved minerals in solution [70, 71, 72, 73].

Wang et al. [74] investigated mineral dissolution and precipitation in dolomite samples saturated with carbonated water at 93°C and 34.5 Mpa under static conditions. They found that mineral dissolution is predominant in highly permeable pathways in the reservoir rock. Zou et al. [75] conducted CO2–brine–rock reactions under different conditions to investigate the changes of porosity and permeability during sCO2 – fracturing in shale reservoir. They reported that CO2–brine–rock reaction could occur rapidly (in less than 0.5 h), precipitating minerals such as calcite, dolomite, K-feldspar, and albite into solution. Zhang et al. [76] investigated CO2-brine-rock reaction in a tight sandstone reservoir under conditions of 75°C and 32 MPa. They found that the dissolution of supercritical CO2 in brine created an acidic environment which induced the dissolution of minerals into the brine, leading to precipitation of iron minerals and kaolinite. Tang et al. [77] studied the impact of CO2-brine-rock interaction on formation properties in gas zone and water zones of a reservoir under static and dynamic conditions. They found that CO2-brine-rock interaction occurs in both gas zones and water zones. Aminu et al. [78] investigated the effect of CO2 and the presence of impurities (NO2, SO2, H2S) on reservoir permeability in static CO2-brine-rock reactions. They found that the presence of impurities affacts the impact of mineral dissolution on rock permeability. Okhovat et al. [79] investigated the effect of CO2-water-rock interaction on rock permeability and oil recovery during CO2 injection into a carbonate rock. They found that the extent of damage induced was a function of the injection rate.

Under static conditions, mineral dissolution could increase rock permeability temporally as new pore spaces are etched and old pore channels could be widened [64]. However, mineral precipitates could aggregate into fine particles in the pore fluid which could form a scale on the pore walls and reduce the flow area.

Sokama-Neuyam et al. [80] conducted experiments to investigate the effect of mineral dissolution on CO2 injectivity using clay-rich Bentheimer Sandstone cores. The cores were flooded with carbonated water at 80 bar and 60°C with about 25 pore volumes (PV) of carbonated water at 0.25 mL/min. Pressure drop profiles recorded during the flooding is shown in Figure 2 and SEM-EDS analysis of effluent samples collected are shown in Table 1.

Figure 2.

Pressure drop profile recorded during injection of carbonated water into a Bentheimer core at flow rate of 0.25 mL/min at 80 bar and 60°C [80].

Elementwt.%
O33.56
Fe7.78
Ni5.02
Na17.53
Mg0.74
Al2.53
Si0.35
Cl29.79
Ca2.52
Co0.17
Total100.00

Table 1.

EDS elemental analysis of effluent samples collected during carbonated water flooding into Bentheimer core.

Figure 2 shows a period of immiscible displacement, where pressure drop decreased sharply from about 0.1 bar to about 0.04 bar after the core was flooded with about 3 PV of carbonated water. As the displaced FW is replaced with the less dense carbonated water, the pressure drop falls sharply until carbonated water breakthrough at the effluent end of the core. Pressure drop was stabilized from about 3 PV to about 7 PV. In this period, the core is fully saturated with carbonated water, leading to stable flow. Unstable flow sets in from about 7 PV to the end of the test. In this period, the pressure drop is seen to rise sharply and fall to a rather haphazard behavior towards the end of the test. The EDS results in Table 1 shows the effluent sample is composed predominantly of Na (17.53%) and Cl (29.79) which are probably the components of the effluent brine. The results also reveal the presence of minerals such as Fe, Si, Al, Ni, and Co which were not present in the saturating brine and the injected carbonated water. Therefore, Fe, Si, Al, Ni, and Co were most likely dissolved from the Bentheimer core through the interaction of the carbonated water and the rock minerals. The EDS analysis show low amounts of Fe, Si, Al, Ni, and Co, because only few particles were likely to be washed out of the core.

5.1.2 Effect of salt precipitation

Salt precipitation is an existing injectivity challenge in natural gas wells. Kleinitz et al. [81] reported field observation of severe halite-scaling during natural gas production. Similar field experiences have been reported during injection, storage and production of natural gas [82, 83, 84]. In the context of field CO2 injection, Baumann et al. [85] and Grude et al. [86] have reported evidence of salt precipitation effects in the Ketzin pilot reservoir and the Snøhvit field, respectively. More recently, Talman et al. [87] investigated drying and salt precipitation effects in a CO2 injection well at the Aquistore site. Downhole images taken from the injection well, together with recovered samples revealed that scales of salts have formed on the inside of the injection well.

Miri and Hellevang [12] identified the processes leading to salt precipitation as: (1) immiscible two-phase CO2-brine displacement; (2) vaporization of brine into the flowing CO2 stream; (3) capillary back-flow of brine towards the inlet; (4) diffusion of dissolved salt in the porewater; (5) gravity override of CO2; and (6) salt self-enhancing. While results from numerical modeling work reported by Roels et al. [88] suggested that precipitated salt could accumulate far from the wellbore, several research works [89, 90, 91] show that precipitated salt accumulates near the wellbore. Permeability impairment between 13 and 83% and porosity reduction between 2 and 15% have been reported from laboratory core-flood experiments [92, 93, 94, 95, 96, 97]. These experimental findings have been found to be consistent with theoretical and numerical simulations [61, 98, 99, 100].

Pruess and Muller [89] suggested that pre-flush of the injection region with freshwater could reduce salt precipitation. However, Kleinitz et al., [81] have shown that freshwater injection could not mitigate salt precipitation if the flow area is completely plugged by solid salt. Fresh water also has a high tendency to react with rock minerals, leading to other injectivity impairment challenges such as clay swelling.

Sokama-Neuyam [101] grouped the mechanisms of salt precipitation into two successive processes: salt cake development at the injection inlet and drying effects. Salt cake forms on the surface of the core inlet during early stages of brine vaporization prior to drying. As drying commences, salt precipitates into pore spaces in the dry-out zone.

Sokama-Neuyam [101] investigated the development of salt cake on the surface of the injection inlet. They flooded a Bentheimer sandstone saturated with about 120 g/L NaCl brine with about 100 PV of dry supercritical CO2 at a rate of 1 mL/min. Figure 3 shows photographs of the rock taken during inspection. In Figure 3A, we observe that no salt was formed at the core outlet. Figure 3B shows massive salt cake deposition at the core inlet and Figure 3C shows that the entire length of the core was still wet. They reported that salt cake formation at the injection inlet was caused by (1) High brine salinity and (2) Poor brine displacement at the injection inlet.

Figure 3.

Photographs of Bentheirmer core after CO2 was injected at 1 mL/min into the core initially saturated with 120 g/L NaCl brine. (A) No salt cake observed at the core outlet. (B) Massive salt cake found at the injection inlet. (C) the entire core remains wet [101].

Furthermore, there are similarities between the increasing trend of injectivity impairment expressed by salt precipitation in Sokama-Neuyam [101] and those described by Yusof et al. [102, 103]. In their study, they examined the effects of brine salinity and brine type on CO2 injectivity changes. They found that the injectivity reduction increased almost linearly between 6 and 27.3% as the brine salinity increases from zero to 100,000 ppm. The increasing growth of salt precipitation which reduced the porosity and effective flow area was identified as the main cause of the downtrend of CO2 injectivity. It was also reported that the sandstone core saturated with monovalent salt such as NaCl and KCl was heavily impaired by salt precipitation as compared to the sandstone core filled by the divalent salt system (CaCl2). However, these findings may be somewhat limited by constant brine salinity of 30,000 ppm.

Moreover, to investigate the effect of drying, Sokama-Neuyam [101] flooded a Berea sandstone core initially saturated with NaCl brine with about 300 PV of supercritical CO2 at a rate of 1 mL/min until the core was completely dried. The permeability of the core after drying was measured and a relative injectivity indexβ which measures the injectivity of the core before and after impairment was calculated. They then repeated the test at injection flow rate of 5 mL/min and 10 mL/min, keeping all other parameters constant, to study the effect of injection flow rate. Figure 4 shows results of injectivity impairment induced by drying and salt precipitation at varying CO2 injection flow rates.

Figure 4.

Effect of drying and salt precipitation on CO2 injectivity. Injectivity impairment, β increased with decreasing CO2 injection rate.

From Figure 4, it was observed that CO2 injectivity was impaired by about 36% for drying rate of 1 mL/min. Injectivity impairment decreased from 36% to about 25% when drying rate was increased to 5 mL/min and remained practically unchanged when the drying rate was further increased to 10 mL/min. Several researchers [94, 96, 104, 105] have earlier reported CO2 injectivity impairment within a range (13–83%) that is in agreement with the these figures. During drying and brine vaporization, when the concentration of brine exceed supersaturation, salt precipitates into the pores in the dry-out region as also observed by Zuluaga et al. [106]. The deposited salts reduce the CO2 flow area, impairing permeability and injectivity.

As drying progresses, a saturation gradient is established which draws more brine into the dry-out region through capillary backflow. Capillary backflow of brine leads to more salt deposition in the dry-out region. The capillary backflow of brine increases with decreasing drying rate because at high CO2 injection flow rates, viscous forces overcome capillary forces. Therefore, less salts are precipitated in the dry-out region at high injection flow rates, inducing low injectivity impairment as observed in Figure 4. Injectivity impairment did not change when drying rate was further increased from 5 mL/min to 10 mL/min because at these injection flow rates, the resident brine is quickly swept out of the core, leaving out only immobile brine for salt precipitation.

During injection of dry supercritical CO2 into brine-saturated sandstone cores, the dry-out region close to the injection inlet, extends into the core as more CO2 is injected. The effect of extension of the dry-out zone on CO2 injectivity is vital for understanding the underlying mechanisms of brine vaporization and salt precipitation. Sokama-Neuyam et al. [107] conducted experimental and theoretical study to investigate the development of the dry-out zone and estimate the impact of extension of the dry-out region on CO2 injectivity. Figure 5 shows the impact of the advancing dry-out zone quantified by a dimensionless dry-out length, ld on CO2 injectivity impairmentβ. From Figure 5, CO2 injectivity impairment peaked at the onset of drying. Injectivity impairment decreased to a minimum atld of about 0.45 and then rose slightly as the dry-out zone approached the core effluent end. At the start-up of drying, two mechanisms could impair CO2 injectivity: salt precipitation and relative permeability effects. Brine vaporization rate is at its highest close to the inlet region because of the high capillary driven back-fluxes. As more brine is vaporized, more salt is precipitated into the pores which in turn increased the resistance to flow in this region. As the drying front advances into the core, brine vaporization and salt precipitation decreased as most of the brine were drawn into the inlet region by capillary backflow, leaving the remaining section of the core with less amount of brine available for salt precipitation. When the core is almost completely dried, brine vaporization and salt precipitation in around the effluent end of the core are almost negligible.

Figure 5.

The impact of the dry-out length (Ld) on CO2 injectivity impairment (β) induced by salt precipitation. Magnitude of injectivity impairment increased when brine salinity was doubled from 75 g/L to 150 g/L but successive changes in injectivity impairment was not influenced by change in brine salinity [107].

To meet the global CO2 emission reduction target, large injection rates will be required. Thus, after salt precipitation, there is continuous injection of CO2 into the reservoir. The effect of drag forces on the deposited salt was studied by Sokama-Neuyam et al. [108]. A Berea core sample was initially vacuum saturated with FW and vaporized to complete dryness to precipitate salt into the pores. The liquid CO2 permeability of the core and pressure drop across two sections of the core were measured with a pressure-tapped core holder. The core was then flooded with about 150 PV of supercritical CO2 at a constant injection rate of 2.5 mL/min. During this period of CO2 injection, drag forces were expected to act on the precipitated salts. Permeability and pressure drop across the same sections of the core was measured after CO2 flooding. Figure 6 shows permeability change induced by the effect of drag forces on precipitated salts at varying injection rates.

Figure 6.

The impact of CO2 injection flow rate on the effect of drag on permeability after salt precipitation. Permeability change is the difference between the core permeability after salt precipitation and before drag test and the permeability after drag test [108].

The net drag force exerted by supercritical CO2 on precipitated salts depends strongly on the volumetric injection flow rate (v), increasing with increase in flow rate. The precipitated salts are held to the pore walls mostly by gravitational and electrostatic forces offered by the complex pore structure and rock minerals. If drag forces overcome these attractive forces, the accumulated salts could be dislodged or redistributed in the pores, altering the permeability as a result. The magnitude of permeability change should therefore be proportional to the drag force which in tend depends on the injection flow rate.

CO2 alternating Low Salinity Water Flooding (CO2-LSWAG) is a promising EOR technique [37, 38, 109, 110]. Sokama-Neuyam et al. [97] investigated CO2 alternating low salinity water injection as a potential technique to mitigate salt precipitation effects on CO2 injectivity. After salt precipitation, a slug of diluent was injected to dissolve the precipitated salts, thus temporarily improving CO2 injectivity. The diluent used was low salinity water (LSW) which was prepared by diluting FW to lower brine salinity. Figure 7 shows injectivity improvement obtained as a function of mass fraction of salt (Xs) in the diluent brine.

Figure 7.

Effect of diluent brine salinity on CO2 injectivity change induced by alternate injection of supercritical CO2 and LSW [111].

In general, CO2 injectivity improved from 8.66 to 31.62% when the mass fraction of salt in the diluent,Xs was decreased stepwise from 8.44 to about 2.11. The solubility of precipitated minerals in the diluent LSW increased with decreasing brine salinity, because, as the brine is further diluted, more free water molecules become available to interact with the precipitated salts. AtXs=1.06, injectivity dropped significantly and the experimental data deviates dramatically from the simulation results, signifying additional injectivity impairment other than salt precipitation. At this point, the diluent starts to interact chemically with the rock minerals. Interaction between rock minerals and the diluent could induce clay swelling and colloidal transport, which have the tendency to aggravate CO2 injectivity impairment.

5.2 Transport effects

The mechanisms of fines migration and the impact of particle transport on the petrophysical properties of reservoir rocks have been previously researched. Khilar and Fogler [112] presented the mechanisms of colloidal and hydrodynamic induced release of fine particles in porous media. Muecke [113] investigated parameters controlling the movement of fine particles within the pore spaces. They identified the pH and salinity of formation brine, flow rate and temperature as some of the underlying parameters. Khilar and Fogler [114] asserted the existence of a critical salt concentration below which the pore fluid could weaken the Van der Waal’s forces holding fine particles to the pore walls. Gruesbeck and Collins, [115] investigated the effect of hydrodynamic forces on the release and transport of fines. They identified a minimum interstitial velocity for fines entrainment. The effect of two-phase flow and rock wettability on fines entrainment has been experimentally investigated by Sarkar and Sharma [116]. They found that, the wettability of the core could affect the extent and rate of permeability impairment induced by migratory fines. Analytical models have been developed by Sharma and Yortsos [117] to investigate the mechanisms of size exclusion and quantify the effect of particle entrapment on rock permeability. Many other studies of fines migration in porous media under various conditions have been reported [118, 119, 120]. A thorough analysis of formation damage induced by migratory fines can be found in Civan [121].

We have already discussed that geochemical CO2-brine-rock reaction could generate secondary minerals into the pore fluid [73, 122, 123]. In addition, CO2-brine interactions could alter the pH of formation fluid which could induce the release of formation fines from the pore walls [115, 124]. While flowing with the injected fluid, the mineral particles could clog pore channels and impair injectivity. Whether entrapment or piping of fines will dominate the flow depends on characteristics of the generated fine particles, the porous medium and the permeating fluid in which the particles are suspended [125, 126, 127]. Pore structure, the size and concentration of the minerals and the hydrodynamic and colloidal conditions of the suspending medium could also affect their impact on CO2 injectivity. Under radial flow conditions, plugging effects could be limited to the near well region where fluxes are highest.

The general mechanisms of fines mobilization in porous media have been well researched and understood. However, the unique properties of supercritical CO2 including its gas-like viscosity and liquid-like density [128] coupled with the expected high CO2 injection rates required to meet global emission reduction targets and the drying effect of supercritical CO2 makes fines mobilization under CO2 injection conditions a unique challenge that must be investigated separately. Adaptation and extension of previous general findings on fines migration is required to understand the mechanisms and impact of fines migration within the context of CO2 injection.

Sokama-Neuyam [80] conducted core-flood experiments to measure the effect of dissolution on injectivity. A Berea sandstone core sample with known permeability was initially saturated with FW, and then flooded with about 25 PV of carbonated water at 80 bar and 60°C at constant injection rate of 0.25 mL/min to release and mobilize fine particles in the rock. The permeability of the core after carbonated water flooding was measured, and injectivity impairment index, β, was calculated. The experiment was then repeated at injection flow rates of 0.5 mL/min and 1.0 mL/min. Figure 8 shows injectivity impairment decreased with increasing carbonated water injection flow rate.

Figure 8.

Effect of injection flow rate on injectivity impairment induced by fines plugging. Injectivity impairment decreased with increasing carbonated water injection flow rate [80].

As injection flow rate is increased, the resident time of carbonated water in the rock is shortened. The number of fines generated will then decrease as the injection flow rate is increased. In addition, at high injection flow rate, hydrodynamic forces could lift smaller particles out of the core with the effluent fluid. The number of fines available to plug the rock, and therefore the chances of injectivity impairment, will reduce as carbonated water injection flow rate is increased. Up to 26% injectivity impairment was induced by mineral dissolution and fines mobilization during carbonated water injection into the Berea sandstone cores. Injectivity impairment decreased as injection flow rate was increased.

Sokama-Neuyam et al. [129] attempted to quantify and compare the individual effects of fines mobilization and salt precipitation on CO2 injectivity. Mono-disperse colloid solutions were used to represent the pore fluid containing particles after mineral dissolution. A Berea sandstone core sample was initially saturated with mono-disperse colloid solution with average particle size of 0.08 μm and particle concentration of 0.3 wt.% and flooded with about 40 PV of supercritical CO2 at 5 mL/min to complete dryness. The relative injectivity change, β, was calculated from the permeability of the core measured before and after it was exposed to mineral impairment. The experiment was repeated for particle concentrations of 0.5 and 1.0 wt.%. Figure 9 shows injectivity impairment induced as a function of composition of the pore fluid.

Figure 9.

The relative impact of fines mobilization and salt precipitation on CO2 injectivity. Fines migration had a more severe impact on injectivity compared to salt precipitation [129].

In Figure 9, while salt precipitation reduced injectivity by about 26.8%, particle concentration of 0.3 wt.% impaired injectivity by 74.9% through fines mobilization. About 1.0 wt.% of particles in the pore fluid almost plugged the rock. When CO2 invades the pores, the mono-disperse particles could plug the narrow pore channels through bridging, surface deposition, or multi-particle blocking. As particle concentration increases, the distance between suspended particles shortens, enhancing multi-particle blocking of the invaded pores. On the other hand, precipitated salts coat the pore walls to reduce the flow area. While salt precipitation reduces the flow area, fines entrapment could plug and isolate the flow path, making them inaccessible to fluid flow. The results suggest that, under linear flow conditions, fines mobilization could induce severe CO2 injectivity impairment comparable to the impact of salt precipitation.

5.3 The coupled effect of salt precipitation and fines mobilization

Preliminary theoretical studies suggests that fines mobilization could compound CO2 injectivity impairment induced by salt precipitation [80, 101]. After salt precipitation, the deposited salt reduces the pore spaces, increasing the jamming ratio of particles being transported in the flowing stream. A schematic diagram that summarizes the role of mineral dissolution, salt precipitation and fines migration mechanisms on CO2 injectivity impairment is shown in Figure 10. Salt precipitation increases the susceptibility of the rock to fines entrapment. Sokama-Neuyam et al. [131], developed a dynamic core-scale model based on experimental observations to investigate the coupled effect of fines mobilization and salt precipitation on CO2 injectivity. The effect of brine salinity, initial core permeability and the order of coupling were studied. Figure 11 shows injectivity impairment induced by the combined effect of particle entrapment and salt precipitation compared to the effect of only fines mobilization.

Figure 10.

Schematic diagram of mineral dissolution, salt precipitation and fines migration mechanisms during CO2 injection into saline aquifer [130].

Figure 11.

Effect of fines mobilization compared to coupled effect of salt precipitation and particle entrapment [131].

Generally, injectivity impairment induced by particle entrapment increases with average particle size in the inlet fluid, rp. For the base case (No salt), particles less than the average pore radius (6 μm) did not induce significant injectivity impairment. These particles generally piped through the pores as they have a jamming ratio less than 1.0. As rp increases, more pores attain a jamming ratio greater than 1.0 and are plugged and isolated. As more pores are plugged and isolated, the flow area available to injected CO2 decreases, impairing the injectivity. Figure 11 also shows that coupling particles entrapment and salt precipitation increases CO2 injectivity impairment significantly with the severity of impairment increasing with initial brine salinity. The deposited salt reduces the pore spaces and increases the jamming ratio. Particles that could pipe through the clean pores would be entrapped after salt precipitation. Thus, salt precipitation could compound the effect of fines mobilization on CO2 injectivity.

Advertisement

6. Challenges and opportunities

Reviewing the previous works on CO2 injectivity has thrown up many questions in need of further investigation. Some of the highlighted concerns are as follows.

  • Most of previous studies that have been made in the context of CO2 storage have focused on salt precipitation. Little experimental work has been performed to better understand near-well rock compaction, impact of temperature and operational parameters (drilling mud, residual hydrocarbons in pores). To give research-based advice on injectivity loss it is necessary to take geology and geomechanics into account. These cannot be reliably assessed without studying radial flow of CO2 (both injection and backflow) under true subsurface stress conditions. Temperature issues should also be considered for the cases such as injection of cold CO2 with potential to fracture the near-well rock and thus increase the permeability.

  • Further work is required to enable direct pore-scale, real-time visualization of fluid-solid interactions with representative pore-geometry and realistic surface interactions between injectant, reservoir fluids and the formation rock.

  • Current research approach to understand the reaction mechanism of CO2-brine-rock for CO2 sequestration are mainly limited to pure CO2. However, due to high cost of gas purification, industrially sourced injection stream CO2 contain impurities such as SO2 which when dissolved in formation water will increase acidity beyond that of carbonic acid formed through CO2 dissolution alone and may also have different reaction mechanism towards rock minerals present in subsurface CO2 storage. Therefore, there is a need for a study to evaluate the effect of CO2 and impurities in brine solution on chemical and physical rock properties.

  • Majority of the dynamic CO2 injection experiments are conducted within a limited time considering the limitation of available equipment. Therefore, there is an argument among the researchers on the sufficient CO2 solubility into the brine and establishment of acidic environment that is critical in geochemistry study. Any future work to extend the CO2 exposure time is highly recommended to identify the extended scale accumulation, mineral dissolution, and fines migration problems.

  • Recent work on wettability during CO2 injection has focused on the wettability changes of glass micromodel and shows that with increasing ionic strength, contact angle increases with increasing residence time. However, with understanding that fine particles released during CO2 injection, may have not been exposed if the surface of the rock, its wettability may be slightly different or remain unaffected. Investigating the wettability of the released fines particles may provide insight on the behavior in which the fines particles migrate and accumulate.

  • When it comes to mechanical stability, initial studies have shown that cyclic injection and shut-in may influence borehole deformation. This is probably exacerbated if some drawdown is experienced upon shut in. Shut-in cycle frequency effect on the amount of borehole deformation should be studied in more detail.

  • Available field data and observation reports indicate the occurrence of injectivity loss. However, detail investigation analysis on the main issues that caused the problem is limited to certain fields. While there are more than 20 active fields worldwide, it should not be challenging to share their findings since the CO2 mitigation would require collaboration.

Advertisement

7. Conclusion

In this chapter, a review of the current literature indicates that dissolution, precipitation, and fines mobilization are the main mechanisms that cause CO2 injectivity impairments especially in deep saline reservoirs. Dissolution of carbonate minerals due to CO2-brine-rock reaction is dominant and could increase the porosity and permeability of sandstone core samples. On the other hand, detachment, precipitation of salt and clay minerals and deposition of fines particles would decrease the permeability and even clog the flow paths despite net dissolution. The effect of these two seemingly opposing processes on CO2 injectivity has been clearly demonstrated through numerous experimental studies supported by some field reports. However, the results are case dependent and lack generality in terms of quantifying the petrophysical damage.

There are many underlying parameters with positive and negative impacts on CO2 injectivity. It has been highlighted that injection scheme (flow rate, time frame), mineral composition (clay content, sensitive minerals), particulate process in porous media (pore geometry, particle, and carrier fluid properties), and thermodynamic conditions (pressure, temperature, salinity, CO2, and brine composition) have substantial effect on fines migration during CO2 injection. However, there is abundant room for further progress in determining the impact of different fluid-rock mechanisms on CO2 injectivity.

References

  1. 1. Pachauri RK, Allen MR, Barros VR, Broome J, Cramer W, Christ R, et al. Climate change 2014: Synthesis report. Contribution of working groups I, II and III to the fifth assessment report of the intergovernmental panel on climate change. IPCC. 2014
  2. 2. Shi Y, Wang C. Pore pressure generation in sedimentary basins: Overloading versus aquathermal. Journal of Geophysical Research—Solid Earth. 1986;91:2153-2162
  3. 3. Baumert KA, Pershing J, Herzog T. Climate data: A sectoral perspective. Pew center on global. Climate Change. 2005
  4. 4. Herzog T, Pershing J, Baumert KA. Navigating the Numbers. Washington D.C, USA: World Resources Institute; 2005
  5. 5. Rogelj J, Den Elzen M, Höhne N, Fransen T, Fekete H, Winkler H, et al. Paris agreement climate proposals need a boost to keep warming well below 2 C. Nature. 2016;534:631-639
  6. 6. Horowitz CA. Paris agreement. Int Leg Mater. 2016;55:740-755
  7. 7. Savaresi A. The Paris agreement: A new beginning? Journal of Energy and Natural Resources Law. 2016;34:16-26
  8. 8. Ritchie H, Roser M. CO₂ and greenhouse gas emissions. Our World Data. 2020
  9. 9. Davison J, Freund P, Smith A. Putting carbon back in the ground. IEA Greenhouse Gas R & D Programme. 2001
  10. 10. IEA. CO2 Capture and Storage in Geological Formations. OECD/IEA. Paris, France: International Energy Agency; 2003
  11. 11. Miri R. Effects of CO2 -Brine-Rock Interactions on CO2 Injectivity – Implications for CCS. Oslo: Uniersity of Oslo; 2015
  12. 12. Miri R, Hellevang H. Salt precipitation during CO2 storage—A review. International Journal of Greenh Gas Control. 2016;51:136-147. DOI: 10.1016/j.ijggc.2016.05.015
  13. 13. Leung DYC, Caramanna G, Maroto-Valer MM. An overview of current status of carbon dioxide capture and storage technologies. Renewable and Sustainable Energy Reviews. 2014;39:426-443. DOI: 10.1016/j.rser.2014.07.093
  14. 14. Huaman RNE, Jun TX. Energy related CO2 emissions and the progress on CCS projects: A review. Renewable and Sustainable Energy Reviews. 2014;31:368-385
  15. 15. Gibbins J, Chalmers H. Carbon capture and storage. Energy Policy. 2008;36:4317-4322
  16. 16. IEA. Technology roadmap—Carbon capture and storage. Technol Roadmap. 2013:59. DOI: 10.1007/SpringerReference_7300
  17. 17. Metz B, Davidson O, De Coninck HC, Loos M, Meyer L. IPCC Special Report on Carbon Dioxide Capture and Storage. Cambridge: Cambridge University Press; 2005
  18. 18. Bentham M, Kirby M. CO2 storage in saline aquifers. Oil & Gas Science and Technology. 2005;60:559-567
  19. 19. Baines SJ, Worden RH. Geological Storage of Carbon Dioxide. London: Geological Society, Special Publications; 2009;233(1):1-6
  20. 20. Gunter WD, Wong S, Cheel DB, Sjostrom G. Large CO2 sinks: Their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Applied Energy. 1998;61:209-227
  21. 21. Eccles JK, Pratson L, Newell RG, Jackson RB. Physical and economic potential of geological CO2 storage in saline aquifers. Environmental Science & Technology. 2009;43:1962-1969
  22. 22. Kumar A, Noh M, Pope GA, Sepehrnoori K, Bryant S, Lake LW. Reservoir Simulation of CO2 Storage in Deep Saline Aquifers. SPE/DOE Symp. Improv. OnePetro: Oil Recover; 2004
  23. 23. Singh N. Deep Saline Aquifiers for Sequestration of Carbon Dioxide. Oslo: International Geological Congress; 2008
  24. 24. Potdar RS, Vishal V. Trapping mechanism of CO2 storage in deep saline aquifers: Brief review. Geological Carbon Sequestration. 2016:47-58
  25. 25. Reichle D, Houghton J, Kane B, Ekmann J. Carbon Sequestration Research and Development. Oak ridge National lab., TN (US); National Energy Technology lab, Pittsburgh, PA (US); National Energy Technology lab., Morgantown, WV (US); 1999
  26. 26. Gozalpour F, Ren SR, Tohidi B. CO2 Eor and Storage in Oil Reservoir Mendeley. 2005;60:537-546. DOI: 10.2516/ogst:2005036
  27. 27. Núñez-López V, Moskal E. Potential of CO2-EOR for near-term decarbonization. Frontiers in Climate. 2019;1:5
  28. 28. Ettehadtavakkol A, Lake LW, Bryant SL. CO2-EOR and storage design optimization. International Journal of Greenhouse Gas Control. 2014;25:79-92
  29. 29. Rojas G, Ali SM. Scaled model studies of carbon dioxide/brine injection strategies for heavy oil recovery from thin formations. Journal of Canadian Petroleum Technology. 1986;25
  30. 30. Tunio SQ, Tunio AH, Ghirano NA, El Adawy ZM. Comparison of different enhanced oil recovery techniques for better oil productivity. International Journal of Applied Science and Technology. 2011;1
  31. 31. Jarrell PM. Practical aspects of CO2 flooding. Richardson, Tex.: Henry L. Doherty Memorial Fund of AIME. Society of Petroleum Engineers. 2002
  32. 32. Hill LB, Li X, Wei N. CO2-EOR in China: A comparative review. International Journal of Greenh Gas Control. 2020;103:103173
  33. 33. Talebian SH, Masoudi R, Tan IM, Zitha PLJ. Foam assisted CO2-EOR: A review of concept, challenges, and future prospects. Journal of Petroleum Science and Engineering. 2014;120:202-215
  34. 34. Esene C, Rezaei N, Aborig A, Zendehboudi S. Comprehensive review of carbonated water injection for enhanced oil recovery. Fuel. 2019;237:1086-1107
  35. 35. Bisweswar G, Al-Hamairi A, Jin S. Carbonated water injection: An efficient EOR approach. A review of fundamentals and prospects. Journal of Petroleum Exploration and Production Technologies. 2020;10:673-685
  36. 36. Dang C, Nghiem L, Chen Z, Nguyen N, Nguyen Q. CO2 Low Salinity Water Alternating Gas: a New Promising Approach for Enhanced Oil Recovery. OnePetro: SPE Improv. Oil Recover. Symp; 2014
  37. 37. Teklu TW, Alameri W, Graves RM, Kazemi H, AlSumaiti AM. Low-salinity water-alternating-CO2 EOR. Journal of Petroleum Science and Engineering. 2016;142:101-118
  38. 38. Chaturvedi KR, Ravilla D, Kaleem W, Jadhawar P, Sharma T. Impact of low salinity water injection on CO2 storage and oil recovery for improved CO2 utilization. Chemical Engineering Science. 2021;229:116127
  39. 39. Stanton R, Flores R, Warwick PD, Gluskoter H, Stricker GD. Coal bed sequestration of carbon dioxide. In: 1st Natl. Conf. Carbon Sequestration. Washington, USA; 2001
  40. 40. Perera MSA. Influences of CO2 injection into deep coal seams: a review. Energy & Fuels. 2017;31:10324-10334
  41. 41. Reeves SR. Enhanced CBM recovery, coalbed CO2 sequestration assessed. Oil & Gas Journal. 2003;101:49-53
  42. 42. IEA. Storing CO2 in Unminable Coal Seams. IEAGHG n.d
  43. 43. Jia B, Tsau J-S, Barati R. A review of the current progress of CO2 injection EOR and carbon storage in shale oil reservoirs. Fuel. 2019;236:404-427
  44. 44. Godec M, Koperna G, Petrusak R, Oudinot A. Enhanced gas recovery and CO2 storage in gas shales: A summary review of its status and potential. Energy Procedia. 2014;63:5849-5857
  45. 45. Rani S, Padmanabhan E, Prusty BK. Review of gas adsorption in shales for enhanced methane recovery and CO2 storage. Journal of Petroleum Science and Engineering. 2019;175:634-643
  46. 46. Cinar Y, Riaz A, Tchelepi HA. Experimental study of CO2 injection into saline formations. In: SPE Annu. Tech. Conf. Exhib. Society of Petroleum Engineers; Washington D.C., USA: Society of Petroleum Engineers; 2007
  47. 47. Yang F, Bai B, Tang D, Shari D-N, David W, Fang Y, et al. Characteristics of CO2 sequestration in saline aquifers. Petroleum Science. 2010;7:83-92. DOI: 10.1007/s12182-010-0010-3
  48. 48. Bachu S. Review of CO2 storage efficiency in deep saline aquifers. International Journal of Greenh Gas Control. 2015;40:188-202. DOI: 10.1016/j.ijggc.2015.01.007
  49. 49. Bachu S, Bonijoly D, Bradshaw J, Burruss R, Holloway S, Christensen NP, et al. CO2 storage capacity estimation: Methodology and gaps. International Journal of Greenh Gas Control. 2007;1:430-443. DOI: 10.1016/S1750-5836(07)00086-2
  50. 50. Bradshaw J, Bachu S, Bonijoly D, Burruss R, Holloway S, Christensen NP, et al. CO2 storage capacity estimation: Issues and development of standards. International Journal of Greenh Gas Control. 2007;1:62-68. DOI: 10.1016/S1750-5836(07)00027-8
  51. 51. De Silva PNK, Ranjith PG. A study of methodologies for CO2storage capacity estimation of saline aquifers. Fuel. 2012;93:13-27. DOI: 10.1016/j.fuel.2011.07.004
  52. 52. USDOE. Carbon sequestration ATLAS of the United States and Canada. In: US Dep Energy, off Foss Energy. National Energy Technol Lab; Washington D.C., USA: US Department of Energy; 2007
  53. 53. Bachu S. Review of CO2 storage efficiency in deep saline aquifers. International Journal of Greenh gas Control. 2015;40. DOI: 10.1016/j.ijggc.2015.01.007
  54. 54. Bachu S, Shaw JC, Pearson RM. Estimation of oil recovery and CO2 storage capacity in CO2 EOR incorporating the effect of underlying aquifers. SPE/DOE Fourteenth Symp Improv Oil Recover. 2004;3:1-13. DOI: 10.2523/89340-MS
  55. 55. Dake LP. Fundamentals of Reservoir Engineering. Amsterdam, Netherlands: Elsevier; 1983
  56. 56. Schembre-McCabe JM, Kamath J, Gurton RM. Mechanistic studies of CO2 sequestration. International Petroleum Technology Conference. 2007. Conference paper number IPTC-11391-MS
  57. 57. Birkholzer JT, Oldenburg CM, Zhou Q. CO2 migration and pressure evolution in deep saline aquifers. International Journal of Greenh Gas Control. 2015;40:203-220
  58. 58. Kaldi J, Daniel R, Tenthorey E, Michael K, Schacht U, Nicol A, et al. Containment of CO2 in CCS: Role of Caprocks and faults. Energy Procedia. 2013;37:5403-5410. DOI: 10.1016/j.egypro.2013.06.458
  59. 59. Daniel RF, Kaldi JG. Evaluating Seal Capacity of Cap Rocks and Intraformational Barriers for CO2 Containment. Tulsa, Oklahoma, USA: American Association of Petroleum Geologists (AAPG); 2009
  60. 60. Peysson Y, André L, Azaroual M. Well injectivity during CO2 storage operations in deep saline aquifers-part 1: Experimental investigation of drying effects, salt precipitation and capillary forces. International Journal of Greenh Gas Control. 2014;22:291-300. DOI: 10.1016/j.ijggc.2013.10.031
  61. 61. Pruess K. Formation dry-out from co2 injection into saline aquifers: 2. Analytical model for salt precipitation. Water Resources Research. 2009;45:1-6. DOI: 10.1029/2008WR007102
  62. 62. Sundal A, Nystuen JP, Dypvik H, Miri R, Aagaard P. Effects of geological heterogeneity on CO2 distribution and migration—A case study from the Johansen formation, Norway. Energy Procedia. 2013;37:5046-5054
  63. 63. Cinar Y, South N, Riaz A, Tchelepi HA. Experimental study of CO2 injection into saline formations. SPE Journal. 2009;14(4):588-594. DOI: 10.2523/110628-MS
  64. 64. Lombard JM, Azaroual M, Pironon J, Broseta D, Egermann P, Munier G, et al. CO2 injectivity in geological storages: An overview of program and results of the GeoCarbone-Injectivity project. Oil & Gas Science and Technology. 2010;65:533-539. DOI: 10.2516/ogst/2010013
  65. 65. Torsæter M, Cerasi P. International journal of greenhouse gas control geological and geomechanical factors impacting loss of near-well permeability during CO2 injection. International Journal of Greenh Gas Control. 2018;76:193-199. DOI: 10.1016/j.ijggc.2018.07.006
  66. 66. Sigfusson B, Gislason SR, Matter JM, Stute M, Gunnlaugsson E, Gunnarsson I, et al. Solving the carbon-dioxide buoyancy challenge: The design and field testing of a dissolved CO2 injection system. International Journal of Greenh Gas Control. 2015;37:213-219
  67. 67. Md Yusof MA, Mohamed MA, Md Akhir NA, Ibrahim MA, Saaid IM, Idris AK, et al. Influence of brine–rock parameters on rock physical changes during CO2 sequestration in Saline Aquifer. Arabian Journal for Science and Engineering. 2021:1-15
  68. 68. Patton JT, Phelan P, Holbrook S. CO2 Formation Damage Study—First Annual Report. New Mexico: Las Cruces; 1981
  69. 69. Sayegh SG, Krause FF, Girard M, DeBree C. Rock/fluid interactions of carbonated brines in a sandstone reservoir: Pembina Cardium, Alberta, Canada. SPE Form Eval. 1990;5:399-405. DOI: 10.2118/19392-PA
  70. 70. Tobergte DR, Curtis S. Experimental perspectives of mineral dissolution and precipitation due to carbon dioxide-water-rock interactions. Journal of Chemical Information and Modeling. 2013;53:1689-1699. DOI: 10.1017/CBO9781107415324.004
  71. 71. Dawson GKW, Pearce JK, Biddle D, Golding SD. Experimental mineral dissolution in Berea sandstone reacted with CO2 or SO2-CO2 in NaCl brine under CO2 sequestration conditions. Chemical Geology. 2015;399:87-97. DOI: 10.1016/j.chemgeo.2014.10.005
  72. 72. Kaszuba JP, Janecky DR, Snow MG. Experimental evaluation of mixed fluid reactions between supercritical carbon dioxide and NaCl brine: Relevance to the integrity of a geologic carbon repository. Chemical Geology. 2005;217:277-293. DOI: 10.1016/j.chemgeo.2004.12.014
  73. 73. Ilgen AG, Cygan RT. Mineral dissolution and precipitation during CO2 injection at the Frio-I brine pilot: Geochemical modeling and uncertainty analysis. International Journal of Greenh Gas Control. 2016;44:166-174. DOI: 10.1016/j.ijggc.2015.11.022
  74. 74. Wang H, Alvarado V, Bagdonas DA, McLaughlin JF, Kaszuba JP, Grana D, et al. Effect of CO2-brine-rock reactions on pore architecture and permeability in dolostone: Implications for CO2 storage and EOR. International Journal of Greenh Gas Control. 2021;107:103283. DOI: 10.1016/j.ijggc.2021.103283
  75. 75. Zou Y, Li S, Ma X, Zhang S, Li N, Chen M. Effects of CO2–brine–rock interaction on porosity/permeability and mechanical properties during supercritical-CO2 fracturing in shale reservoirs. Journal of Natural Gas Science and Engineering. 2018;49:157-168. DOI: 10.1016/j.jngse.2017.11.004
  76. 76. Zhang X, Wei B, Shang J, Gao K, Pu W, Xu X, et al. Alterations of geochemical properties of a tight sandstone reservoir caused by supercritical CO2-brine-rock interactions in CO2-EOR and geosequestration. Journal of CO2 Utilization. 2018;28:408-418. DOI: 10.1016/j.jcou.2018.11.002
  77. 77. Tang Y, Hu S, He Y, Wang Y, Wan X, Cui S, et al. Experiment on CO2-brine-rock interaction during CO2 injection and storage in gas reservoirs with aquifer. Chemical Engineering Journal. 2021;413:127567. DOI: 10.1016/j.cej.2020.127567
  78. 78. Aminu MD, Nabavi SA, Manovic V. CO2-brine-rock interactions: The effect of impurities on grain size distribution and reservoir permeability. International Journal of Greenh Gas Control. 2018;78:168-176. DOI: 10.1016/j.ijggc.2018.08.008
  79. 79. Okhovat MR, Hassani K, Rostami B, Khosravi M. Experimental studies of CO2-brine-rock interaction effects on permeability alteration during CO2-EOR. Journal of Petroleum Exploration and Production Technologies. 2020;10:2293-2301. DOI: 10.1007/s13202-020-00883-8
  80. 80. Sokama-Neuyam YA, Forsetløkken SL, Lien J, Ursin JR. The coupled effect of fines mobilization and salt precipitation on CO2 Injectivity. Energies. 2017;10:1125. DOI: 10.3390/en10081125
  81. 81. Kleinitz W, Dietzsch G, Köhler M. Halite scale formation in gas-producing wells. Chemical Engineering Research and Design. 2003;81:352-358
  82. 82. Jasinski R, Sablerolle W, Amory M. ETAP: Scale Prediction and Control for the Heron Cluster. In: SPE Annu. Tech. Conf. Exhib. Society of Petroleum Engineers; Washington D.C. USA: Society of Petroleum Engineers. 1997
  83. 83. Golghanddashti H, Saadat M, Abbasi S, Shahrabadi A. Experimental investigation of water vaporization and its induced formation damage associated with underground gas storage. Journal of Porous Media. 2013;16
  84. 84. Place MC, Smith JT. An unusual case of salt plugging in a high-pressure sour gas well. In: SPE, editor. 59th SPE Annual Technical Conference and Exhibition. Houston, Texas: SPE; 1984. p. 13. DOI: 10.2118/13246-MS
  85. 85. Baumann G, Henninges J, De Lucia M. Monitoring of saturation changes and salt precipitation during CO2 injection using pulsed neutron-gamma logging at the Ketzin pilot site. International Journal of Greenh Gas Control. 2014;28:134-146
  86. 86. Grude S, Landrø M, Dvorkin J. Pressure effects caused by CO2 injection in the Tubåen Fm., the Snøhvit field. International Journal of Greenh Gas Control. 2014;27:178-187
  87. 87. Talman S, Shokri AR, Chalaturnyk R, Nickel E. Salt precipitation at an active CO2 injection site. Gas Inject into Geol Form Relat Top. 2020;104(1):22-28. DOI: 10.1002/9781119593324.ch11
  88. 88. Roels SM, Ott H, Zitha PLJ. μ-CT analysis and numerical simulation of drying effects of CO2 injection into brine-saturated porous media. International Journal of Greenh Gas Control. 2014;27:146-154. DOI: 10.1016/j.ijggc.2014.05.010
  89. 89. Pruess K, Muller N. Formation dry-out from co2 injection into saline aquifers: 1. Effects of solids precipitation and their mitigation. Water Resources Research. 2009;45:1-11. DOI: 10.1029/2008WR007101
  90. 90. Miri R, van Noort R, Aagaard P, Hellevang H. New insights on the physics of salt precipitation during injection of CO2 into saline aquifers. International Jornal of Greenh Gas Control. 2015;43:10-21. DOI: 10.1016/j.ijggc.2015.10.004
  91. 91. Sokama-Neuyam YAA, Ursin JR. The effect of mineral deposition on CO2 well Injectivity. Europec. 2015;2015:1-4
  92. 92. Bacci G, Korre A, Durucan S. Experimental investigation into salt precipitation during CO2 injection in saline aquifers. Energy Procedia. 2011;4:4450-4456. DOI: 10.1016/j.egypro.2011.02.399
  93. 93. Kim M, Sell A, Sinton D. Aquifer-on-a-Chip: Understanding pore-scale salt precipitation dynamics during CO2 sequestration. Lab on a Chip. 2013;13:2508-2518. DOI: 10.1039/c3lc00031a
  94. 94. Muller N, Qi R, Mackie E, Pruess K, Blunt MJ. CO2 injection impairment due to halite precipitation. Energy Procedia. 2009;1:3507-3514. DOI: 10.1016/j.egypro.2009.02.143
  95. 95. André L, Peysson Y, Azaroual M. Well injectivity during CO2 storage operations in deep saline aquifers—Part 2 : Numerical simulations of drying , salt deposit mechanisms and role of capillary forces. Interantional Journal of Greenh Gas Control. 2014;22:301-312. DOI: 10.1016/j.ijggc.2013.10.030
  96. 96. Tang Y, Yang R, Du Z, Zeng F. Experimental study of formation damage caused by complete water vaporization and salt precipitation in sandstone reservoirs. Transport in Porous Media. 2015;107:205-218
  97. 97. Sokama-Neuyam YA, Ursin J. Experimental and theoretical investigations of CO2 injectivity. AGH Drilling, Oil, Gas. 2016;33:245-257. DOI: 10.7494/drill.2016.33.2.245
  98. 98. Giorgis T, Carpita M, Battistelli A. 2D modeling of salt precipitation during the injection of dry CO2 in a depleted gas reservoir. Energy Conversion and Management. 2007;48:1816-1826. DOI: 10.1016/j.enconman.2007.01.012
  99. 99. Hurter S, Berge J, Labregere D. Simulations for CO2 injection projects with compositional simulator. Offshore Eur 4–7 Sept. 2007. DOI: 10.2118/108540-MS
  100. 100. Zeidouni M, Pooladi-Darvish M, Keith D. Analytical solution to evaluate salt precipitation during CO2 injection in saline aquifers. International Journal of Greenh Gas Control. 2009;3:600-611. DOI: 10.1016/j.ijggc.2009.04.004
  101. 101. Sokama-Neuyam YA. Experimental and Theoretical Modelling of CO2 Injectivity: Effect of Fines Migration and Salt Precipitation. Stavanger: University of Stavanger; 2017
  102. 102. Md. Yusof MA, Ibrahim MA, Idress M, Idris AK, Saaid IM, Rosdi NM, et al. Effects of CO2/rock/formation brine parameters on CO2 injectivity for sequestration. SPE Journal. 2021;26:1455-1468
  103. 103. Md. Yusof MA, Ibrahim MA, Mohamed MA, Md Akhir NA, M Saaid I, Ziaudin Ahamed MN, et al. Predictive modelling of CO2 injectivity impairment due to salt precipitation and fines migration during sequestration. In: International Petrolium Technology Conference. OnePetro; Washington D.C. USA: Society of Petroleum Engineers. 2021
  104. 104. Bacci G, Durucan S, Korre A. Experimental and numerical study of the effects of halite scaling on Injectivity and seal performance during CO2 injection in saline aquifers. Energy Procedia. 2013;37:3275-3282. DOI: 10.1016/j.egypro.2013.06.215
  105. 105. Peysson Y. Permeability alteration induced by drying of brines in porous media. European Physical Journal Applied Physics. 2012;60:12. DOI: 10.1051/epjap/2012120088
  106. 106. Zuluaga E, Muñoz NI, Obando GA. SPE 68335 An experimental study to evaluate water vaporisation and formation damage caused by dry gas flow through porous media. Media. 2001:SPE-68335-MS
  107. 107. Sokama-neuyam YA, Ursin JR. Experimental and Theoretical Study of Salt Precipitation, Development of the Dry-out zone and CO2 Injectivity. n.d:pp. 1-18
  108. 108. Sokama-Neuyam YA, Ursin JR. CO2 well Injectivity: Effect of viscous forces on precipitated minerals. International Petrolium Technology Conference. 2015;13. DOI: 10.2523/IPTC-18268-MS
  109. 109. Wilson A. CO2 low-salinity water alternating gas: A promising new approach for EOR. Journal of Petroleum Technology. 2015;67. DOI: 10.2118/0115-0084-JPT
  110. 110. Zolfaghari H, Zebarjadi A, Shahrokhi O, Ghazanfari MH. An experimental study of CO2-low salinity water alternating gas injection in sandstone heavy oil reservoirs. Iran Journal of Oil Gas Science and Technology. 2013;2:37-47
  111. 111. Sokama-neuyam YA, Ursin JR, Boakye P. Experimental investigation of the impact of salt precipitation on CO2 injection in sandstone. 2019;5(1):1-9
  112. 112. Khilar KC, Fogler HS. Migrations of Fines in Porous Media. Vol. 12. Berlin: Springer Science & Business Media; 1998
  113. 113. Muecke TW. Formation fines and factors controlling their movement in porous media. Journal of Petroleum Technology. 1979;31:144-150
  114. 114. Khilar KC, Fogler HS. Water sensitivity of sandstone. SPE. 1983;23(1):55-64
  115. 115. Gruesbeck C, Collins RE. Entrainment and deposition of fine particles in porous. Media. 1982;22:10. DOI: 10.2118/8430-PA
  116. 116. Sarkar A, Sharma M. Fines migration in two-phase flow. Journal of Petroleum Technology. 1990;42:646-652. DOI: 10.2118/17437-PA
  117. 117. Sharma MM, Yortsos YC, Handy LL. Release and deposition of clays in sandstones. In SPE Oilfield and Geothermal Chemistry Symposium. OnePetro; 1985
  118. 118. Han X, Zhong L, Liu Y, Fang T, Chen C. Experimental study and pore network modeling of formation damage induced by fines migration in unconsolidated sandstone reservoirs. Journal of Energy Resources Technology. 2020;142
  119. 119. Prempeh K, Chequer L, Badalyan A, Bedrikovetsky P. Effects of kaolinite on fines migration and formation damage. In: SPE Int. Conf. Exhib. Form. Damage Control. OnePetro; 2020
  120. 120. Giraldo LJ, Diez R, Acevedo S, Cortés FB, Franco CA. The effects of chemical composition of fines and nanoparticles on inhibition of formation damage caused by fines migration: Insights through a simplex-centroid mixture design of experiments. Journal of Petroleum Science and Engineering. 2021;203:108494
  121. 121. Civan F. Reservoir Formation Damage. Gulf Professional Publishing; Amsterdam, Netherlands: Elsevier Inc.; 2015
  122. 122. Wilkinson M, Haszeldine RS, Fallick AE, Odling N, Stoker SJ, Gatliff RW. CO2-mineral reaction in a natural analogue for CO2 storage—Implications for modeling. Journal of Sedimentary Research. 2009;79:486-494. DOI: 10.2110/jsr.2009.052
  123. 123. Hangx SJT. Subsurface mineralisation: Rate of CO2 mineralisation and geomechanical effects on host and seal formations. CATO Workpackage WP 4.1, Report. 2005:1-43
  124. 124. Khilar KC, Fogler HS. Migrations of Fines in Porous Media. Netherlands: Springer; 2010
  125. 125. Aji K. The Experimental and Theoretical Study of Fines Migration in Porous Media under Particle-Rock Repulsion and Attraction Kaiser Aji a Thesis Submitted for the Degree of Doctor of Philosophy (PhD) October 2014. 2014
  126. 126. Sen TK, Khilar KC. Review on subsurface colloids and colloid-associated contaminant transport in saturated porous media. Advances in Colloid and Interface Science. 2006;119:71-96. DOI: 10.1016/j.cis.2005.09.001
  127. 127. Vaidya RN, Fogler HS. Formation damage due to colloidally induced fines migration. Colloids and Surfaces. 1990;50:215-229. DOI: 10.1016/0166-6622(90)80265-6
  128. 128. Nalawade SP, Picchioni F, Janssen LPBM. Supercritical carbon dioxide as a green solvent for processing polymer melts: Processing aspects and applications. Progress in Polymer Science. 2006;31:19-43. DOI: 10.1016/j.progpolymsci.2005.08.002
  129. 129. Sokama-Neuyam YA, Ginting PUR, Timilsina B, Ursin JR. The impact of fines mobilization on CO2 injectivity: An experimental study. International Journal of Greenh Gas Control. 2017;65. DOI: 10.1016/j.ijggc.2017.08.019
  130. 130. Yusof MAM, Neuyam YAS, Ibrahim MA, Saaid IM, Idris AK, Mohamed MA. Experimental study of CO2 injectivity impairment in sandstone due to salt precipitation and fines migration. Journal of Petroleum Exploration and Production Technologies. 2022. DOI: 10.1007/s13202-022-01453-w
  131. 131. Sokama-Neuyam YA, Ursin JR. The coupled effect of salt precipitation and fines mobilization on CO2 injectivity in sandstone. Greenh Gases Science and Technology. 2018;8(6):1066-1078. DOI: 10.1002/ghg.1817

Written By

Yen A. Sokama-Neuyam, Muhammad A.M. Yusof and Shadrack K. Owusu

Submitted: 22 February 2022 Reviewed: 07 April 2022 Published: 28 May 2022