Modulation of the binding affinity of naproxen to bovine serum albumin by conversion of the drug into amino acid ester salts

Article abstract of DOI:10.1016/j.molliq.2020.114283

Naproxen (NAP) is one of the most widely prescribed non-steroidal anti-inflammatory drugs. Novel formulations of NAP aiming at better water-solubility, dosage, and the onset of action or new routes of application in order to minimize or prevent side effects of NAP are in the current interest of the pharmaceutical industry. Here, we report the synthesis, chemical, spectral and physicochemical characterization of a series of salts containing cations amino acid alkyl esters (AAE) and NAP anion, which potentially can be used as novel drug formulation. The [L-AAE][NAP] were obtained in three steps: preparation of the AAE hydrochlorides, neutralization of the hydrochlorides to the corresponding AAE, and formation of the target organic salts. All NAP derivatives, tested at a concentration as high as 100 μM, exhibited no toxicity against murine macrophage cell line (RAW 264.7). The binding parameters and stoichiometry of [AAE][NAP]s to bovine serum albumin (BSA) are in the range of that estimated for the parent NAP. Only L-valine isopropyl ester naproxenate characterizes with about one order of magnitude lower binding affinity for BSA, which suggests a faster diffusion rate in the circulatory system than the parent NAP and other derivatives, and therefore faster reach to the target system. Using molecular modeling seven binding pockets of BSA were probed for their suitability to binds the cation and the anion and results are discussed in correlation with the obtained thermodynamic parameters for the binding of NAP derivatives to BSA.

Full text of DOI:10.1016/j.molliq.2020.114283

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Journal of Natural Gas Geoscience 3 (2018) 347e352
http://www.keaipublishing.com/jnggs
Original research paper
Experimental investigation of porosity and permeability change caused by
*
salting out in tight sandstone gas reservoirs
Lijun You*, Zhe Wang, Yili Kang, Yushan Zhao, Dujie Zhang
State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, 610500, China
Received 16 June 2018; revised 26 November 2018
Available online 13 December 2018
Abstract
Salt precipitation and its induced problems are increasingly prominent with the development of deep and ultra-deep tight sandstone gas
reservoirs with high salinity formation water. In this paper, the change of porosity and permeability of a series of tight sandstone was measured,
and then the morphology and occurrence state of crystalloid salt within the pore was observed by SEM. Meanwhile, high-pressure mercury
injection analyzed the changes of pore size distribution. Experimental results show that salt precipitation could affect the porosity and
permeability, which decreases by 53% and 65% after salt precipitation, respectively. The occurrence state of the crystalloid salt can be divided
into three models: superposition growth along with the intergranular pore-fractures/natural micro-fractures, lamellar growth attached to the
surface of the hydrophilic mineral like I/S interstratified mineral and the individual particles located in the corner of the pore. When the size of
crystalloid salt is closer to the pore size distribution of tight sandstone, it will cause cracks and pore throat blockage easily. It is suggested that
salt wash pretreatment should be carried out before analysis of tight sandstone with porosity less than 5%.
Copyright © 2018, Lanzhou Literature and Information Center, Chinese Academy of Sciences AND Langfang Branch of Research Institute of
Petroleum Exploration and Development, PetroChina. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is
an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Keywords: Salt precipitation; Tight sandstone; Porosity; Permeability; Formation damage
1
. Introduction
[3,4] due to the high salinity of the formation water. The
crystallization salt produced by salting out will block the
percolation channel, reduce the percolation capacity and
seriously affect the gas well productivity. Salting out occurs
during production of a gas well in Beihai Oilfield, which re-
sults in the skin coefficient increasing with time [5,6].
Tight sandstone gas is an unconventional natural gas
resource, which has a high proportion in the composition of
unconventional oil and gas resources in China and has
excellent potential for development [1,2]. Tight sandstone gas
reservoirs are usually deeply buried. The rapid gas flow rate
near the well area during gas reservoir development will
accelerate formation water evaporation, which leads easily to
the salting out within 5 m range of the reservoir near well zone
At present, salting out studies mainly focus on laboratory
experiments, salting out model establishment, salting out
prediction and removal [7e17]. Laboratory experiments
revealed the type of precipitate (NaCl), the kinetics of salting
out evaporation in porous media, the preferred evaporation site
of salting out in porous media, the effect of temperature/
pressure on salting out, and the changes of physical properties
of rock samples before and after salting out. These studies
mainly focus on salting out of reservoirs with good pore and
*
This is English translational work of an article originally published in
Natural Gas Geoscience (in Chinese).The original article can be found at: 10.
11764/j.issn.1672-1926.2018.05.001.
*
Corresponding author.
E-mail address: youlj0379@126.com (L. You).
À3
2
permeability properties (K > 1 Â 10 mm , F>10%).
In this paper, samples of tight sandstone with different pore
types are selected, and the evaporation experiments of high
Peer review under responsibility of Editorial office of Journal of Natural Gas
Geoscience.
https://doi.org/10.1016/j.jnggs.2018.12.003
2468-256X/Copyright © 2018, Lanzhou Literature and Information Center, Chinese Academy of Sciences AND Langfang Branch of Research Institute of Petroleum Exploration and Development, Petro-
China. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

348
L. You et al. / Journal of Natural Gas Geoscience 3 (2018) 347e352
salinity formation water in these tight cores are conducted to
stimulate the process of salting out under the given tempera-
ture. Before and after the experiments of salting out, the
porosity and permeability of these tight cores are measured.
The effect of salt washing on the analysis of pore and
permeability properties of tight sandstone is also discussed.
Fig. 1. Schematic diagram of evaporation of sampled saturated by formation
water.
2
. Samples and methods
2
.1. The experimental sample
2.2.2. Salting out occurrence and pore size change analysis
After salting out, six experimental cores salting out were
The experimental rock samples were taken from the west-
ern Sichuan outcrop, the N block in the East China Sea and the
K block in the Tarim Basin. The porosity of tight sandstone in
Western Sichuan is mostly between 14% and 20%, with an
average of 16.23%. The porosity of tight sandstone in N block
of East China Sea is mainly between 4% and 10%, with an
average of 7.45%. The porosity in K block of Tarim Basin is
mainly between 1% and 5%, with an average of 3.11%. Eight
representative, tight sandstone cores selected from the 3
blocks, are divided into three types according to the porosity:
analyzed by using alpha Quanta 450 environmental scanning
electron microscope.
The morphology, size and occurrence position of salt
crystallization were observed. A tight sandstone core was cut
into two sections. 9250 automatic mercury injection meter was
used to test two sections of them. The capillary pressure
curves are used to analyze the change of pore size of the core
before and after salting out.
relatively high porosity of TP :10% < F < 16%, relatively
3. Experimental results and analysis
H
medium porosity of TP :5% < F < 10%, relatively low
M
porosity of TP :1% < F < 5%. The basic physical parameters
3.1. Change of porosity and permeability
L
of these cores are shown in Table 1. Salt crystallization is
mainly sodium chloride [18] according to the analysis results
of ionic composition of formation water with high salinity in
some gas reservoirs [19,20]. In this paper, the simulated for-
mation water in K area with the salinity of 200 000 mg/L is
prepared as experimental fluid.
As shown in Figs. 2 and 3, the porosity and permeability of
six tight sandstone cores after salting out have been reduced to
varying degrees. Among them, the porosity and permeability
of TP
porosity and permeability of low TP
by 13% and 26% respectively, and the porosity and perme-
ability of low TP cores have been reduced by 49% and 57%
cores have been reduced by 16% and 10%, and the
H
cores have been reduced
M
2
2
.2. The experimental method
M
respectively. These show that the smaller the porosity of tight
sandstone is, the lower the permeability is, and the more
substantial the decrease of porosity and permeability caused
by salting out is.
.2.1. Porosity and permeability testing
(
(
(
1) The basic physical parameters of the cores are measured
after drying.
2) The simulated formation water solution is prepared and
filtered.
3.2. Salt crystal morphology and microscopic
distribution
3) As shown in Fig. 1, the experimental cores are immersed
in the simulated formation water solution for 24 h, and
then the saturated formation water samples are heated and
From the scanning electron microscopy (Fig. 4) of the
salted tight sandstone, it can be seen that salting out occurs in
three types of occurrence modes, i.e., growth pattern (Fig. 4a)
along intergranular pore/natural micro-fracture clusters,
growth pattern (Fig. 4b) on the surface of hydrophilic clay
ꢀ
evaporated in an oven at 60 C for 48 h.
4) Measure the porosity and permeability of rock samples
using the SCMS core measurement system.
(
Table 1
Basic physical properties of experimental samples.
Core number
Lengh/mm
Diameter/mm
Mass/g
Porosity/%
Permeability/( Â 10À3 mm2)
Core type
LT-1
LT-2
52.34
50.50
35.91
46.75
22.05
28.25
26.56
27.63
25.10
25.10
24.68
24.76
24.25
24.16
24.22
24.18
57.99
55.00
41.42
55.43
27.56
34.65
31.85
33.06
16.18
15.98
7.39
8.97
2.81
3.40
3.50
3.16
0.0930
0.0860
0.0723
0.0907
0.0128
0.0329
0.0420
0.0312
TP
H
TP
M
TP
L
DH-1
DH-2
KS-1
KS-2
KS-3
KS-4

L. You et al. / Journal of Natural Gas Geoscience 3 (2018) 347e352
349
crystals on the surface. When salting out occurs at the corner
of the pore, crystalline salts grow at the corner or on the
surface of quartz with natural single crystals of about 3e5
micron in length. Such crystalline salts may come from
evaporation of pore water or retained water, or salt transport.
3.3. Variation of pore throat radius distribution in tight
sandstone
Figs. 5 and 6 show the pore distribution of mercury injec-
tion analysis of KS-3 and KS-4 tight sandstone cores before
and after salting out. The pore sizes are divided into four types
in order to facilitate the analysis of the effect of salting out on
the pore size of tight sandstone. These are macropore (pore
size is greater than 100 nm), mesopore (pore size is
Fig. 2. Effects of the salt precipitation on the porosity of tight sandstone.
50e100 nm), transition pore (pore size is 10e50 nm) and
micropore (pore size is less than 10 nm) [21]. The mercury
intrusion test results show that the pore volume of KS-3 before
À5
salting out is between (40.88e1218) Â 10 mg/L, and after
salting
out,
the
pore
volume
is
between
À5
(85.12e92.55) Â 10 mg/L. The pores are dominated by
macropore and micropore. After salting out, the proportion of
macropore and micropore decreases, and the volume of mac-
ropore decreases the most, which indicates that salting out
occupies most of the pore space. The volume of pre-salting
mercury injection method for KS-4 is between
À5
(
1.71e1889) Â 10 mg/L, and the pore volume of post-
salting
(
mercury
injection
method
is
between
À5
37.34e162) Â 10 mg/L. The pore volume of a core is
Fig. 3. Effects of the salt precipitation on the permeability of tight sandstone.
minerals such as illite/Mongolian interlayer, and growth
pattern (Fig. 4c) at the corner of the pore. When micro-
fractures or intergranular pore develop in the reservoir rock,
these pore fractures become the dominant flow path of
gaseliquid and the fast channel of preferential water evapo-
ration, providing a good evaporation environment for gas flow
and liquid evaporation. Also, the fluid saturation in these slots
is usually higher, resulting in higher salinization. Scanning
electron microscopy (SEM) reveals that the main types of clay
minerals are illite/montmorillonite and chlorite. Among them,
illite/montmorillonite is a hydrophilic clay mineral, so the
solution is more readily adsorbed on the surface of such clay
minerals and evaporates to form continuous layered salt
Fig. 5. Pore distribution of KS-3 core before and after salt precipitation.
Fig. 4. Occurrence state of crystalloid salt within the pore throat.

350
L. You et al. / Journal of Natural Gas Geoscience 3 (2018) 347e352
or thick pore throats, and the single crystalline salts mainly
occur in the corner or grooves of the small pore throats. In the
actual production process, crystalline salts in clusters are sta-
ble, and migration does not occur smoothly. Generally, it is
mainly to reduce the cross-section of the flow channels. Under
a given pressure difference, the single-grained will migrate
and block the throat due to its weak binding force on the pore
wall, which severely reduces the flow capacity of tight
sandstone.
4.2. The influencing factors of salting out
Salting out phenomenon in pore throat of tight rock is
related to liquid salinity, distribution of flow field and prop-
erties of mineral interface [26e29]. The main factors affecting
the distribution of salt crystallization include:
Fig. 6. Pore distribution of KS-4 core before and after salt precipitation.
mainly mesoporous and microporous. After salting out, the
pore volume of mesopore tends to decrease, but the peak value
of micropore increases, which indicates that the proportion of
micropore increases by filling and cutting the mesopore with
salt crystallization [22].
(1) Heterogeneity of flow path of a reservoir. Micro-cracks are
the dominant flow path (Fig. 4a). The more developed the
cracks are, the stronger the gas flow ability is, the easier
the liquid evaporates, and the more naturally the liquid
reaches the saturated state to form salt crystallization.
With high water content in the cracks, the crystalline salts
produced by salting out grow rapidly in layers, have a
stable structure and sufficient thickness, plug the cracks
and significantly reduce their transport capacity.
4
. Discussion
4.1. Salting out mechanism analysis of tight sandstone
gas reservoir
(
2) The occurrence and content of the hydrophilic clay min-
erals. Crystalline salts mainly distribute on the surface of
the clay minerals in the pore throat, but no crystalline salts
exist on the surface of chlorite (Fig. 4b). This is because
the surface of the interlayer minerals is hydrophilic and
super absorbent [30]. At high temperature, water evapo-
ration causes crystalline salts to stay on the surface of the
interlayer minerals. In addition, the illite/montmorillonite
has an intricate surface, on which crystalline salts grow in
clusters of “film-attached” layers, resulting in a decrease in
pore volume.
The pore structure and fracture of porous media strongly
determine transport and precipitation patterns of salt in porous
media strongly depend on the [14,23]. The characteristics of
tight sandstone, such as high capillary pressure and abundant
clay minerals in natural fractures, determine that the salting
out mechanism of tight sandstone is different from that of
conventional sandstone. In the process of formation water
evaporation, the gas first enters the larger pore, and the smaller
pore has strong water binding capacity but keeps saturated
state. When the salinity increases due to the evaporation of the
solution in the larger pore and the concentration gradient ex-
ists between the smaller pore solution and the larger pore
solution, the smaller pore solution will migrate to the larger
pore, and finally, the smaller pore will more naturally reach the
salt solution limit [24]. However, after the final evaporation
and salting out of the solution, the larger pore contains more
crystalline salts because it stores more solutions and the so-
lution migration caused by the concentration gradient. The
pore distribution characteristics of Figs. 5 and 6 also show that
crystalline salts have a more severe influence on the larger
pore. Fracture is the main flow channel of tight sandstone
reservoir. The liquid evaporation in a reservoir is mainly the
result of gas carrying and high-temperature evaporation. In a
fractured reservoir, gas flow rate increases, resulting in rapid
evaporation of the solution to induce rapid production of
crystalline salts and filling of fractures [25].
(3) Pore shape of a rock. Some single salt crystalline are
distributed in the corner of the pores (Fig. 4c), because the
liquid is easily retained and evaporated to inducing salting
out occurs in situ.
(4) The salinity of formation water. The higher salinity of
formation water, the more salt crystals will be produced
after evaporation and salting out.
4.3. Effect of salt washing on the physical property of
tight sandstone cores
Salting out may occur in the process of drilling tight
sandstone cores from underground to surface, which may in-
fluence the analysis results of physical properties. Thirty-nine
tight sandstones in K block of Tarim Basin are selected to
wash the salt and test the porosity and permeability of tight
cores using the method for the repeated-pressure saturation
establishing [31]. Fig. 7 is the relationship between pore and
permeability of the cores.
In tight sandstone reservoirs, salt crystallization occurs
mainly in stratified cluster crystalline salts and single crys-
talline salts. The stratified cluster crystalline salts mainly
occur in the iso-high permeability evaporation zone in cracks

L. You et al. / Journal of Natural Gas Geoscience 3 (2018) 347e352
351
washing. The smaller the porosity and permeability of tight
sandstone, the more obvious the change of porosity and
permeability after salt washing. For tight cores with the
porosity greater than 5%, the effect of salting out on porosity
is not significant. Therefore, it is necessary to carry out salt
washing treatment before conducting flow or rock electricity
experiments of tight sandstone containing high salinity for-
mation water [32].
5. Conclusions
(
(
1) After salting out, the porosity and permeability of tight
sandstone may decrease by 53% and 65%.
2) Salting out can be divided into three types: growth along
intergranular pore fracture/natural micro-fracture cluster
superposition, layer growth on the surface of hydrophilic
clay minerals such as illite/montmorillonite interlayer, and
growth of single grain at the corner of pores.
Fig. 7. Curve of the relationship between porosity and permeability.
The results of porosity and permeability test before and
after salt washing (Figs. 8 and 9) show that the average
porosity before salt washing is 2.54%, and after salt washing,
the average porosity is 3.17%, which increases by 25%. The
(
(
3) After salting out, the volumes of all kinds of pores in tight
sandstone can decrease.
4) For tight sandstone with porosity less than 5%, salt
washing should be carried out before core laboratory
analysis experiments.
À3
2
average permeability after salt washing is 0.0217 Â 10 mm ,
À3
2
which is 23% higher than that (0.0176 Â 10 mm ) before salt
Funding
Supported by the Youth Science and Technology Innova-
tion Research Team Project of Sichuan Province, Chi-
na(2016TD0016); National Science Foundation of China
(51674209).
Conflict of interest
The authors declare no conflict of interest.
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