- Published: September 3, 2022
- Updated: September 3, 2022
- University / College: Flinders University
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The experimental surveies described in Chapter 5 demonstrated that salt precipitation can do terrible damages in injectivity. The porousness and permeableness informations of the altered samples was used to graduate a Verma-Pruess “ tube-in-series ” theoretical account ( Verma and Pruess, 1988 ) employed in numerical simulations, which are presented in this Chapter. Similarly to the 1-D simulations presented in Chapter 3, these are performed with the all-purpose reservoir simulation codification TOUGH2, coupled with the fluid belongings faculty ECO2N which can supply accurate fluid belongingss for the system CO2/water/NaCl for pressures up to 60 MPa, temperatures in the scope 10 – 110 oC, and salt up to full NaCl impregnation ( Pruess, 2005 ) . TOUGH2/ECO2N is used to pattern multiphase flow topic to syrupy, capillary and gravitation forces ; partitioning of H2O and CO2 between aqueous and CO2-rich stages ; precipitation and disintegration of rock salt ( NaCl ) . As solubility of H2O in the CO2-rich stage is little, typically a fraction of per centum, effects of dissolved H2O on the denseness and viscousness of the CO2-rich stage are neglected.
This work focuses entirely on the precipitation of salt contained in the formation H2O during CO2 injection-induced formation dry-out. Chemical reactions between CO2, fluids and formation minerals can besides be responsible for precipitation and disintegration effects. However, as explained in Section 5. 4.
2, such interactions appears to hold a minor impact in the wellbore country compared to salt deposition induced by H2O vaporization and are non considered in this work. Non-isothermal effects are besides non considered. As Giorgis et Al.
( 2007 ) indicated in their survey, simulations of supercritical CO2 injection under non-isothermal conditions may non bring forth different consequences than when the CO2 is injected at the same temperature of the undisturbed reservoir. These, nevertheless, could be of import in the instances where CO2 is injected at a temperature significantly different from that of the stone formation. Two different sets of simulations are presented in this chapter. In the first, a planar radial-vertical geometry ( 2-D R-Z ) is used to analyze the impact of the interplay of gravitation and capillary effects, and of of import parametric quantities such as injection rate, stone porousness, irreducible H2O impregnation and H2O salt on salt deposition. In the 2nd set of simulations, the consequence of salt precipitation on the sealing unit is tested utilizing a similar 2-D R-Z geometry.
An idealized 2-D radial theoretical account is used to stand for CO2 injection in a saline aquifer.
The geological formation is assumed to be homogenous and isotropic and it is modelled as a horizontal phonograph record with thickness of 10 m, discretised into 10 grid beds of changeless tallness of 1 m. The numerical grid is extended to the distance of 100, 000 m in order to do the system infinite moving for the clip period simulated ( 10 old ages ) . Figure 6. 1 shows a conventional representation of the geometric theoretical account used. The wellbore is located on the axis of symmetricalness of the phonograph record and has a radius of 0. 2 m. The entire injection rate is uniformly distributed among the 10 reservoir beds.
The horizontal discretisation was designed in such a manner as to obtain great spacial declaration near the injection good, i. e. the part where highest gradients occur.
From the well sandface, a all right radial grid has been built get downing with an component of 0. 01 m breadth and so increasing the element breadths following a logarithmic patterned advance. In entire, 75 grid blocks have been used for each bed. The upper and lower boundaries of the formation are close, imitating impermeable beds at the top and at the underside of the reservoir. geometric model_Chapter 6. jpgFigure 6.
1: Conventional representation of the geometric theoretical account used. Initial force per unit area and temperature were severally chosen as 12 MPa and 45 oC, representative of the thermodynamic conditions which might happen in a saline formation at a deepness of about 800-1000 m. The seawater salt value of 25-wt % dissolved NaCl has been chosen to be near to the salt concentration used for the vaporization trials at reservoir conditions. Porosity was set at 20 % and permeableness at 100 mendelevium. The aqueous stage irreducible impregnation was assumed to be 0. 30. The comparative permeableness and capillary force per unit area has been calculated with the new wave Genuchten theoretical accounts taking parametric quantities similar to the those used for the 1-D numerical simulations presented in Chapter 3.
As shown by Pruess and Muller ( 2009 ) , aqueous diffusion has negligible effects on solids precipitation and was non included in this survey. CO2 injection was simulated for 10 old ages at a changeless rate of 1 kg/s. Before executing the injection, a numerical simulation was ran in order equilibrate the force per unit area inside the formation harmonizing to the hydrostatic gradient, which gives a force per unit area of around 11. 95 MPa at the top of the formation and a somewhat higher force per unit area of 12.
05 MPa at the underside. The specifications chosen for this theoretical account are summarised in Table 6. 1. Salt precipitation induced by the CO2 injection procedure is monitored and quantified in the different parts of the formation analyzing the alterations of solid impregnation, that is the fraction of pore volume occupied by salt. From the values of solid impregnation, the ensuing porousness is computed. Matching permeableness is besides estimated harmonizing to the Verma-Pruess pore web theoretical account ( See Appendix C ) . The Verma-Pruess theoretical account has been late used in numerical modeling surveies to stand for the consequence of salt precipitation ( Pruess and Muller, 2009 ) . However, in Pruess and Muller ( 2009 ) the theoretical account was non calibrated with experimental informations derived from salt deposition but alternatively utilizing similar parametric quantities ( I“= 0.
80 ; ?¤c= 0. 90 ) to a old survey of permeableness alterations due to precipitation of formless silicon oxide at a geothermic injection good in the Philippines ( Xu et al. , 2004 ) .
This parameterisation gave really terrible lessening in permeableness for a limited porousness decrease. Muller et Al. ( 2009 ) besides used a Verma Pruess theoretical account to stand for the relationship between alterations in petrophysical belongingss induced by the formation dry out consequence. In this work, a vaporization trial was specifically executed to graduate the permeableness theoretical account used in the simulation. The ascertained experimental maximal permeableness decrease ( a?? 60 % ) was matched with the maximal salt precipitation ( a?? 16 % ) obtained from numerical modeling. The parametric quantities I“ and ?¤c were assumed both equal to 0. 567. In the writer ‘ s position, this attack presents two restrictions, viz.
the theoretical account was calibrated with a individual consequence of permeableness change, and the values of porousness and permeableness decrease used are non related to one another. In this work, as illustrated in Chapter 5, vaporization trials have been conducted at different pressure/temperature conditions to accurately stand for the consequence of salt precipitation. Figure 6. 2 shows the different Verma-Pruess theoretical accounts obtained. The uninterrupted bluish line ( Lab-TUD ) is the theoretical account calibrated from the experiments conducted at TU Delft at reservoir conditions. The parametric quantities I“ and ?¤c were assumed severally equal to 0. 70 and 0. 59.
The uninterrupted ruddy line is alternatively the theoretical account calibrated with the informations from the experiments executed at Imperial College at atmospheric force per unit area and temperature. In this instance, the parametric quantities I“ and ?¤c were severally 0. 95 and 0. 85.
For comparing, the permeableness theoretical account used in Pruess et Al. ( 2009 ) and Muller et Al. ( 2009 ) are besides displayed.
Figure 6. 1: Verma-Pruess salt precipitation theoretical accounts. It can be observed that the two theoretical accounts obtained in this survey are significantly different. Datas from experiments at atmospheric force per unit area and temperature yielded a theoretical account which indicates great permeableness alterations for little porousness alterations, similar to Pruess et Al. ( 2009 ) . Whereas, the theoretical account calibrated with the consequences obtained at reservoir conditions is surprisingly close to the 1 used in Muller et Al. ( 2009 ) . For all the numerical simulations presented in the following subdivisions, the Lab-TUD permeableness decrease theoretical account has been used.
In order to simplify modeling, the simulations reported in this Chapter were performed without implementing the modified permeableness values in the flow computation. On the other manus, old surveies showed that impregnation profiles for gas and solid precipitate do non depend on decrease of permeableness, every bit long as the decrease does non bring on utmost pressurization, which in bend would modify the fluid belongingss ( Pruess and Muller, 2009 ) . Table 6. 1: Physical belongingss of the aquiferAquifer thickness10 mPermeability100 ten 10-15 mA? Porosity20 %Pore squeezability4. 5 ten 10-10 Pa-1Rock grain denseness2, 600 kg m-3Temperature45 oCPressure12 MPaSalt25-wt %Injection rate1 kg s-1Relative permeableness theoretical account and capillary force per unit area theoretical accountsLiquid ( van Genuchten, 1980 )Residual liquid impregnationSlr= 0. 30AdvocateI»= 0. 457Gas ( van Genuchten, 1980 )Residual gas impregnationSgr = 0.
05AdvocateI»= 0. 457Capillary force per unit area ( van Genuchten, 1980 )Residual liquid impregnationSlr = 0. 00AdvocateI»= 0. 457CoefficientP0 = 19.
Appraisal of Salt Precipitation within the Storage Formation
Initially, the injection of dry supercritical CO2 displaces the seawater around the wellbore. A little portion of CO2 dissolves in the seawater, whereas a fraction of the saline H2O is vaporised by the fluxing CO2. As H2O evaporates the salt content contained into the seawater is enriched. Halite deposition occurs where the solubility bound of about 26. 5 % by weight is outreached. As the injection of CO2 returns, saline H2O continues to evaporate around the wellbore country until it wholly disappears. As Figure 6.
3 shows, one twelvemonth after get downing the injection, the plume of CO2 extended more across a part localised near the top of the formation at a distance of up to around 200 m from the wellbore. The presence of higher values of gas impregnation at the top of the permeable interval can be attributed to the effects of perkiness. SG_1yr. jpgFigure 6. 3: Gas impregnation distribution after CO2 injection for 1 twelvemonth. Harmonizing to the simulation ( Figure 6. 4 ) , salt deposition is confined to a little country up to 4 m inside the formation.
Within this country, the sum of the precipitated NaCl appears to be reasonably unvarying, with an mean solid salt deposition of about 10 % . A little lower solid salt deposition can be measured at the top, whereas near the underside a localized part with larger solid deposition ( up to 13 % ) can be detected. These higher solid deposition values identified near the lower part of the dry-out forepart are due to the interplay between capillary and gravitation forces. In these countries, gravitation has the consequence of cut downing the horizontal constituent of the flow vector, while the capillary forces remain unchanged. Therefore, the potency of backflow of aqueous stage additions towards the injection good supplying a greater supply of precipitable salt. This behavior had been antecedently reported by Giorgis et Al.
( 2007 ) . As Figure 6. 5 shows, on norm, the absolute permeableness is reduced to 40 % of the initial value, as indicated by the research lab experiments. Permeability decrease extremums to 48 % in the part where the highest sum of NaCl is deposited. SS_1yr. jpgFigure 6. 4: Solid salt deposition distribution ( NaCl ) after CO2 injection for 1 twelvemonth. k-red_1yr.
jpgFigure 6. 5: Permeability decrease ( k/k0 ) due to halite grading after CO2 injection for 1 twelvemonth. As the injection continues, the CO2 plume and the dry-out forepart increasingly beforehand inside the formation. After 10 old ages, CO2 would go every bit far as 650 m from the injection good ( Figure 6. 6 ) , i.
e. 3. 25 times the promotion after one twelvemonth of injection. Solid deposition profiles, shown in Figure 6. 7, indicate that the rock salt grading forepart besides advanced 3. 25 times from the first twelvemonth, up to 13 m into the geological formation. It is possible to detect a slighter more marked perpendicular solid deposition tendency, with a extremum of 14 % decrease of the pore volume.
Absolute permeableness reduces down to 51 % of the original value ( Figure 6. 8 ) . SG_10yr. jpgFigure 6. 6: Gas impregnation distribution after CO2 injection for 10 old ages.
SS_10yr. jpgFigure 6. 7: Solid salt ( NaCl ) deposition distribution after CO2 injection for 10 old ages. k-red_10yr. jpgFigure 6. 8: Permeability decrease ( k/k0 ) due to halite grading after CO2 injection for 10 old ages. Get downing from the 2-D injection theoretical account described in Section 6.
3, which can be referred as Case 0, a sensitiveness survey was conducted to analyze the effects of different formation parametric quantities on salt precipitation. Problem fluctuations include utilizing, one at a clip, a different injection rate, porousness, residuary H2O impregnation, salt content and reservoir thickness. Table 6. 2 resumes the different instances explored in this survey. Table 6. 2: Sensitivity of salt precipitation to fluctuations in formation parametric quantities.
Problem fluctuation from Case 0
1Injection rate increased to 2.
0 kg/s. 2Injection rate decreased to 0. 5 kg/s. 3Porosity increased to 30 % . 4Irreducible H2O impregnation addition to 40 % . 5Irreducible H2O impregnation decreased to 20 % . 6NaCl concentration decreased to 15 % by weight.
7Aquifer thickness increased to 100 m and flow rate increased to 10 kg/s. 8Injection distributed among merely the last 5 m at the underside. Consequences for two instances with different injection rates, 0. 5 kg/s and 2. 0 kg/s, are displayed in Figures 6.
9 – 6. 12. The graphs are referred to different injection clip periods, severally 4 old ages and 1 twelvemonth, in order to accomplish the same sum of CO2 injected for both the instances.
For the larger injection rate ( Case 1 ) , the consequence of gravitation override is less of import, and hence perpendicular gradients appear less outstanding. This can be seen detecting the gas impregnation map ( Figure 6. 9 ) which indicate a smaller inclination of CO2 to roll up near the top of the formation. Close to the wellbore, the profile of gas impregnation is about unvarying, insomuch as the flow can be about considered every bit 1-D.
As shown in Figure 6. 10, salt precipitation besides seems to be unvarying, with mean solid deposition of 9 % and a extremum of 10 % in close propinquity to the injection good, which induces a maximal decrease of the absolute permeableness to every bit small as 37 % . GS_1yr. jpgFigure 6. 9: Gas impregnation distribution after CO2 injection for 1 twelvemonth with a rate of 2. 0 kg/s ( Case 1 ) . SS_1yr.
jpgFigure 6. 10: Solid salt ( NaCl ) deposition distribution after CO2 injection for 1 twelvemonth with a rate of 2. 0 kg/s ( Case 1 ) .
For the smaller injection rate ( Case 2 ) , the horizontal constituents of injection-induced pressurization are reduced, whereas perkiness forces are non changed and, hence, the effects of gravitation override on gas impregnation distribution go more marked ( Figure 6. 11 ) . Harmonizing to this, more CO2 accumulates at the top of the formation. Rather otherwise from Case 1, for low injection rates, salt deposition varies significantly in the different parts of the formation, with pronounced perpendicular solid impregnation tendency ( Figure 6. 12 ) . Average solid deposition is larger than in the old instance ( about 13 % ) .
Similarly to the first instance studied ( Case 0: injection rate peers to 1 kg/s ) , it is possible to place an country near the lower part of the dry-out forepart where larger sums of precipitated salt can be detected. In this instance, the maximal solid impregnation is 24 % , which induces a permeableness decrease every bit high as 79 % of the original value. GS_4yr. jpgFigure 6. 11: Gas impregnation distribution after CO2 injection for 4 old ages with a rate of 0. 5 kg/s ( Case 2 ) . SS_4yr.
jpgFigure 6. 12: Solid salt ( NaCl ) deposition distribution after CO2 injection for 4 old ages with a rate of 0. 5 kg/s ( Case 2 ) . Case 3 investigates the influence of initial porousness. By increasing porousness from 20 % to 30 % , the absolute sum of salt precipitating is besides increased ; nevertheless, the solid deposition distribution predicted by numerical modeling appears to be unchanged.
Due to the increase of planetary pore infinite in the formation, the CO2 plume reached a somewhat smaller distance than in Case 0. Case 4 and Case 5 examine the effects of a different value of irreducible liquid impregnation. This parametric quantity modifies the sum of seawater that can be moved through the non-miscible supplanting mechanism, and accordingly the fraction of liquid which is removed by vaporization into the CO2 watercourse. As expected, cut downing irreducible liquid impregnation down to 0. 20 resulted in less precipitation of salt and decrease in permeableness.
Increasing liquid impregnation to 0. 40 had the opposite consequence. Case 6 investigates the effects of decreased seawater salt. As NaCl concentration was reduced by 40 % , from 25 % -wt to 15 % -wt, the salt deposition well decreased. After 10 old ages of CO2 injection, mean solid deposition within the country affected by salt precipitation became 6 % , i.
e. 40 % less than the mean solid impregnation for Case 0. Therefore, mean solid deposition proportionately decreased with the decrease in seawater salt. However, the extremum solid deposition in Case 6 resulted in merely 7 % , i.
e. 50 % less than that determined for Case 0. Comparing to Case 0, besides the gas impregnation informations nowadayss some differences. Consequences indicate that the CO2 plume extends to a smaller distance into the aquifer. This is because less deposition of salt allows more CO2 to be stored in the pore infinite.
An correspondent sensitiveness survey had been antecedently conducted by Pruess and Muller ( 2009 ) for a simpler 1-D instance, which gave similar indicants sing the effects of fluctuation in porousness, salt and residuary H2O impregnation. Case 7 investigates the effects of an addition in aquifer thickness. This simulation has been conducted increasing the perpendicular length of the formation by 10 times, from 10 m to 100 m. The injection rate was increased by 10 times every bit good, in order to keep the figure of pore volumes of CO2 injected over the 10 old ages injection period. Figure 6. 13, illustrates the gas impregnation distribution at the terminal of 10 old ages of CO2 injection. The consequences indicate that by increasing the aquifer thickness, the effects of perkiness become stronger and the part of CO2 that accumulates near the top of the reservoir additions.
Figure 6. 14 shows the presence of a local part near the underside of the formation where salt accumulated, making a solid impregnation of 18 % . Such porousness fluctuation corresponds a permeableness decrease of 64 % , i. e. 13 per centum points more than the maximal permeableness decrease determined for Case 0. inj_10yr ( H= 100m ) .
jpgFigure 6. 13: Gas impregnation distribution after 10 old ages of CO2 injection at 10 kg/s in a formation with a thickness of 100 m ( Case 7 ) . SS_10yr ( H= 100m ) . jpgFigure 6. 14: Solid salt ( NaCl ) deposition distribution after 10 old ages of CO2 injection at 10 kg/s in a formation with a thickness of 100 m ( Case 7 ) .
Case 8 examines the influence of a different injection scheme. In this simulation, injection has non been distributed among all the reservoir beds but merely among the lower 5 m. The entire injection rate is unchanged.
The gas impregnation distribution did non present significant differences from Case 0 ; nevertheless, the salt precipitation form was well modified. Figure 6. 15 shows the solid salt deposition distribution after 10 old ages of CO2 injection. As antecedently observed, besides for this instance, it is possible to detect the presence of a part near the lower portion of the dry-out forepart where salt copiously precipitates.
However, otherwise from the old instances, Figure 6. 15 shows besides another country where solid impregnation is peculiarly high ( around 16 % ) . This is in close propinquity to the wellbore, 3-4 m below the top of the formation, i. e. right above the portion of the reservoir where CO2 injection is conducted. In this country, vaporization is strong.
The perpendicular constituents of injection induced-pressurisation is alternatively weak, since the flow near the well is about 1-D. Therefore, capillary force per unit area forces are able to reload the vaporization forepart with a uninterrupted supply of new seawater from the top of the formation arousing a terrible accretion of salt. In the top parts of the aquifer, halite grading is much lower compared to Case 0. This is because CO2, traveling from the underside due to buoyancy merely, arrives to the top of the formation already saturated to an extend with H2O and can bring on merely limited vaporisation of seawater in the environing countries and ensuing in limited salt deposition. SS_10yr. jpgFigure 6. 15: Solid salt ( NaCl ) deposition distribution after 10 old ages of CO2 injection distributed into merely the lowest 5 m of the injection interval ( Case 8 ) .
Appraisal of Salt Precipitation on the Caprock
The consequences presented in Section 6. 3 indicate that capillary driven backflow can be responsible of the formation of local parts where salt accumulates ensuing in great damages in the reservoir petrophysical belongingss. This phenomenon is much more marked when the promotion of the drying forepart is someway defeated. As an illustration, it has been observed that due to the consequence of gravitation override, the horizontal patterned advance of the dry-out forepart is delayed near the underside of the formation and larger sums of salt are deposited. In the ideal instance of no promotion of the dry-out forepart in one way, the localized decrease in permeableness that can be obtained would be highly high. This is because seawater would invariably provide new seawater on the same vaporization interface ensuing in a uninterrupted accretion of salt, which would stop merely with the complete plugging of the pore infinite. A state of affairs similar to the ideal instance described could happen on the interface between the aquifer and the impermeable waterproofing unit.
The perpendicular patterned advance of the drying forepart is so suddenly interrupted by the caprock, under which CO2 accumulates. CO2 can non pervade the caprock bed, nevertheless, can evaporate the H2O contained in it ensuing in precipitation of salt. The importance of this phenomenon steams on the possibility that the associated permeableness decrease can to boot better the waterproofing capacity. Evidences proposing this behavior can be found in the afore mentioned survey from Peysson et Al. ( 2010 ) . A numerical survey has been conducted in this research to look into the effects of halite grading on the sealing unit. The numerical theoretical account used is similar to the 1 illustrated in subdivision 6.
2. The chief difference is that an extra impermeable 1 m bed is included at the top of the formation stand foring the caprock. The undermentioned formation parametric quantities have been chosen for this bed: porousness peers 10 % , permeableness peers 1 mendelevium and the capillary force per unit area was computed utilizing the new wave Genuchten theoretical account and a value of P0 equal to 5, 000 kPa, which prevents any Darcy-driven flux. Similarly to the old simulations presented in the Chapter, stone fluid interactions are non considered. For the first simulation, referred to as Case 9, the same parametric quantities employed for Case 0 in subdivision 6. 2 have been used for the aquifer formation. Unfortunately, the simulation had to be interrupted after merely 10 yearss because salt impregnation in the top first grid block stand foring the aquifer reached 1.
In fact, when solid impregnation reaches value 1 in one of the grid blocks the package is non able to go on the simulation. Figure 6. 16 shows the solid impregnation distribution following 10 yearss of CO2 injection. It is possible to detect the formation of a bed of really high solid impregnation and zero permeableness merely underneath the caprock, around the wellbore.
After 10 yearss, this bed extends merely for a limited distance into the reservoir, within a radius of 0. 10 m. However, during the overall clip of a CO2 injection undertaking, a NaCl bed with a radius of several meters can be expected to organize. This would add excess sealing capacity in the country near to the wellbore, which is possibly the most sensitive part for the hazard of escape. SS_inj10days. jpgFigure 6. 16: Solid salt ( NaCl ) deposition distribution map after 10 yearss of CO2 injection ( Case 9 ) . It is of import to detect, that the eventual formation of such a salt barrier can be considered as a relevant mechanism in the context of CO2 storage because it could farther better the sealing effectivity of a caprock in good conditions.
However, it would non forestall escapes from one that is faulty at the first topographic point. In fact, as Figure 6. 17 illustrates, after 10 yearss of injection the CO2 plume entered about 30 m into the reservoir, i. e. much more widely than the formed salt bed. Therefore, CO2 can easy pervade into the caprock if this is fractured or has an unequal capillary entry force per unit area and permeableness. As shown in Figure 6.
18, the force per unit area perturbation involves even a larger country, making out to 3, 000 m off from the wellbore. SG_inj10days. jpgFigure 6. 17: Gas impregnation map after 10 yearss of CO2 injection ( Case 9 ) . P_inj10days.
jpgFigure 6. 18: Pressure field ( Pa ) after 10 yearss of CO2 injection ( Case 9 ) . By cut downing the NaCl salt to 15 % ( Case 10 ) , the formation of the salt bed is slowed down. Solid salt deposition reaches value 1 in the aquifer top left grid block after 18 yearss of injection. Salt was further reduced in order to let the simulation to run for a longer period of clip ( Case 11 ) .
Formation parametric quantities are the same used in Case 9 but NaCl concentration was set every bit low as 0. 5 % by weight. Similarly to the old instances, the entire injection rate of 1 kg/s is distributed uniformly among the aquifer 10 beds. Solid salt deposition and permeableness decrease informations for an injection clip of 1 twelvemonth are severally shown in Figure 6. 19 and 6. 20. Following 1 twelvemonth of CO2 injection, mean solid deposition into the formation is about void.
This is due to the really low salt chosen for the simulation. However, the two aquifer top beds present important higher degrees of salt deposition, making a maximal solid impregnation of 47 % . Despite the really low seawater salt, harmonizing to the permeableness decrease theoretical account used, underneath the caprock a wholly impermeable salt barrier can be formed besides in this instance ( Figure 6. 20 ) .
SS_inj360days. jpgFigure 6. 19: Solid salt deposition distribution after 1 twelvemonth of CO2 injection ( Case 11 ) . k-red_inj360days. jpgFigure 6. 20: Permeability decrease due to halite grading after 1 twelvemonth of CO2 injection ( Case 11 ) .
An extra sensitiveness survey was conducted in order to analyze the effects of the different aquifer parametric quantities on the formation of the salt barrier underneath the sealing unit. From Case 11, a figure of job fluctuations were explored including different injection rates, porousness, residuary H2O impregnation and injection scheme. Table 6. 3 presents the inside informations of the different instances investigated. Table 6. 3: Case features used to look into the sensitiveness of salt precipitation to fluctuations in formation parametric quantities.
Problem fluctuation from Case 11
12Injection rate increased to 2. 0 kg/s.
13Injection rate decreased to 0. 5 kg/s. 14Porosity increased to 30 % . 15Irreducible H2O impregnation addition to 40 % .
16Irreducible H2O impregnation decreased to 20 % . 17Injection merely in the bottom 5 bedsCases 12 and 13 investigate the consequence of alterations in the injection rate. As seen before, when increasing the flow rate, solid salt deposition somewhat decreases in most parts of the aquifer for the same sum of pore volume of CO2 injected.
However, it seems that the consequence on the formation of the salt barrier below the caprock is opposite. In fact, injection of 2 kg/s for 6 months ( same sum sum of pore volumes injected as in Case 11 ) increased the sum of salt deposited below the caprock. Solid impregnation reached the maximal value of 53 % ( Case 12 ) . Similarly, diminishing the flow rate down to 0.
5 kg/s ( Case 13 ) additions salt precipitation in all the aquifer parts underneath the caprock. Case 14 analysed the influence of initial porousness on the formation of the salt barrier below the caprock. Increasing porousness to 30 % slows the formation of the salt bed. In fact, utilizing the hypothesis that the vaporisation rate is independent to porousness as assumed in these simulations, the sum of salt deposited after a certain clip will be the same than in Case 11. However, since in this instance more pore volume is available, the comparative decrease in null infinite that occurs is slower. Cases 15 and 16 examine the importance of irreducible liquid impregnation.
Consequences presented in the old Section demonstrated that this parametric quantity controls the part of seawater that is non removed by non-miscible supplanting and, hence, besides controls the sum of salt deposited into the pores. However, the consequence on the formation of the salt barrier is minimal. In fact, the big solid impregnation reached underneath the caprock is merely fringy due to the local salt contained in the seawater but it largely comes from the salt dissolved in the seawater continuously coming towards the vaporization forepart.
Finally, Case 17 investigates the effects of a different injection scheme. Similarly to the sensitiveness survey discussed in the old subdivision, the entire injection rate of 1 kg/s was distributed merely among the bottom 5 beds. Results show that no salt barrier underneath the caprock is formed by shooting merely from the underside.
This is because CO2 that lifting by perkiness and coming to reach with the caprock is already saturated with H2O and can non do important vaporization. In this Section, the possibility of a salt bed formation adjacent to the caprock was numerically explored together with the influence of the chief petrophysical formation parametric quantities onto the procedure. However, the existent happening of such phenomenon requires proof from field and laboratory experiments.
It is besides of import to foreground that the rate of the salt bed formation obtained in this survey was purely dependent to the perpendicular discretisation used and it can non be considered representative of field conditions. In these simulations, the reservoir bed under the waterproofing unit, in which the salt barrier signifiers, had a thickness of 1 m. However, old surveies demonstrated that salt deposition can roll up in a much dilutant bed, of the order of few millimeters of thickness, next to the vaporizing surface ( Peysson et al. , 2010 ) . If, as indicated by the writers, rock salt sedimentations in a significantly narrower part, high values of solid salt deposition could be expected within a much shorter period of clip.
The numerical survey showed that halite grading is likely to concentrate underneath the caprock, nevertheless, in the field some salt deposition could happen besides inside the sealing unit. In fact, presuming really high vaporization rates, the caprock might non be able to supply sufficient capillary-driven beginning of seawater to the dry-out forepart and, hence, the vaporization forepart could come in into the caprock advancing halite grading on the interior.
To summarize, the following were established by the numerical simulations presented in the first portion of this Chapter: Salt deposition dressed ores in an country of few metres around the wellbore inside the dry-out part.
Gravity and capillary effects slow the promotion of the CO2 vaporization forepart and bring on backflow of seawater bring forthing local countries near the underside of the aquifer where deposition of salt occurs to a larger step. For an equal sum of CO2 injected into the reservoir, these effects result accentuated as the injection rate is decreased. Gravity override effects become more important in aquifers with larger aquifer thickness, where the formation of local part near the underside of the formation with really high values of solid NaCl deposition can be expected. The comparative sum of solid salt precipitated additions with brine salt and irreducible H2O impregnation while list it consequences no significantly dependent to porousness. The 2nd set of numerical simulations showed that at the interface between aquifer and caprock a stationary dry-out forepart can be formed, bring oning the formation of a salt bed which acts as an excess protection against escapes around the wellbore. The formation of the salt bed can non forestall escapes from fractured on unsuitable caprocks, but it can be of import in bettering the sealing capacity of caprocks in satisfactory conditions.
The numerical simulations have besides established the followers: Increases of seawater salt accelerates the formation of the salt bed between aquifer and caprock. For an equal sum of CO2 injected into the aquifer, the formation rate of the salt barrier appears to lift as injection rate is increased. In aquifer with larger values of porousness, high values of solid impregnation are reached in larger periods of clip. Irreducible H2O impregnation seems to hold non important influence on the procedure. This procedure seems to happen merely when portion of the CO2 is injected in the close propinquity of the caprock. In fact, in a simulation where CO2 was injected merely in the lower portion of the formation, there is no mark of such phenomenon.
The occurring of the salt bed has non been antecedently reported in the literature and it requires confirmation from field and laboratory experiments. Lab experiments appear indispensable to verify the happening of these mechanisms. Here, an experimental attack is proposed in order to analyze the presence of the salt barrier phenomenon. For this experiment, a caprock sample saturated with saline H2O is placed in a flow cell in perpendicular place. The sample is put in contact with CO2 on one free side at the underside and with a seawater reservoir on the top side. The CO2 and seawater reservoir have to be at the same force per unit area in order to forestall Darcy flow motion of one stage into the other. This force per unit area can be representative of reservoir conditions. Anyhow, it is of import that the force per unit area is kept below the capillary entry force per unit area of the caprock.
On the lower face of the caprock, CO2 and seawater will be in contact and will easy get down to fade out in each other. As the seawater vaporises, more saline H2O from the seawater reservoir will travel towards the vaporizing surface. Diffusion of H2O saturated CO2 into the gas reservoir assures that CO2 will be able to take up more H2O vouching uninterrupted vaporization on the nucleus face. As the vaporization procedure continues, salt concentration increasingly increases and halite grading finally occurs. The procedure easy carries on until all the CO2 contained in the gas reservoir becomes to the full saturated with H2O. However, this experiment might take really long clip because the mechanism is governed by diffusion.
An alternate faster option consists in puting the flow cell in an oven, with one side free and the other connected to the seawater reservoir. The rate of vaporization in this instance can be regulated seting the temperature in the oven.
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EduFrogs. (2022) 'Numerical modelling of the effects of halite scaling biology essay'. 3 September.
EduFrogs. (2022, September 3). Numerical modelling of the effects of halite scaling biology essay. Retrieved from https://edufrogs.com/numerical-modelling-of-the-effects-of-halite-scaling-biology-essay/
EduFrogs. 2022. "Numerical modelling of the effects of halite scaling biology essay." September 3, 2022. https://edufrogs.com/numerical-modelling-of-the-effects-of-halite-scaling-biology-essay/.
1. EduFrogs. "Numerical modelling of the effects of halite scaling biology essay." September 3, 2022. https://edufrogs.com/numerical-modelling-of-the-effects-of-halite-scaling-biology-essay/.
EduFrogs. "Numerical modelling of the effects of halite scaling biology essay." September 3, 2022. https://edufrogs.com/numerical-modelling-of-the-effects-of-halite-scaling-biology-essay/.
"Numerical modelling of the effects of halite scaling biology essay." EduFrogs, 3 Sept. 2022, edufrogs.com/numerical-modelling-of-the-effects-of-halite-scaling-biology-essay/.
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