M.Fouad Snosy ,Mahmoud Au El Ela ,Ahmed El-Bani ,Helmy Sayyouh
a General Petroleum Company,Egypt
b Cairo University,Egypt
c The American University in Cairo,Egypt
Keywords:Low salinity Waterflooding LSWF Sandstone Bahariya formation Western desert
ABSTRACT In the last decade,there has been an increasing interest in understanding the effects of changing injected water salinity on the performance of oil reservoirs.This paper aims to investigate the effects of injected water salinity on oil recovery of an Egyptian oil reservoir (Bahariya formation).An experimental work program has been performed using 25 core plugs and 5 different water salinities to study the effects of changing water salinity during both secondary and tertiary stages of waterflooding.The objectives of the experimental work were to (1) investigate the effects of the low water salinity on oil recovery and (2)identify the optimum water salinity and the main reservoir parameters for application of low salinity waterflooding project (LSWF) in Bahariya formation.
The results revealed that there is an optimum salinity for waterflooding in the secondary flooding stage.However,for the tertiary flooding stage,the results showed that the controlling factor is not decreasing the salinity,but rather changing the salinity (e.g.either increasing or decreasing).It was also clear that applying the optimum salinity in the secondary recovery stage is more effective than applying it in the tertiary recovery stage.Furthermore,the results showed that the positive impact of LSWF may be expected in reservoirs with high amount of kaolinite,high values of CEC,and low amounts of plagioclase feldspar.
This study is an original contribution to develop guidelines for designing optimum salinity waterflooding projects in sandstone reservoirs.
Waterflooding (WF) has been used to increase oil production since the mid-nineteenth century.The first waterflooding project occurred in the Bradford oil field of Pennsylvania(USA)in 1865 by reinjecting the produced water into an oil reservoir.Initially,the WF projects used the circle drive concept then followed by line drive.The first five-spot pattern was implemented in 1924 in the Bradford oil field.By the 1950s,the WF had become a common practice in oil fields [1].
In the past decade,there was an increasd interest to understand the effects of injected water salinity changes on the reservoir performance.The application of LSWF in the laboratory experiments for sandstone core plugs reveals many useful results.Incremental increase in oil recovery of up to 20% was documented [2-6].Nasralla and Nasr El-Din showed 7%incremental recovery by changing composition from 5000 CaCl2to 5000 NaCl [7].In other studies,Austad et al.,Seccombe et al.,and Amirian stated that the clay minerals are the controlling factors in the LSWF projects [8-10].However,Al-Saedi and Flori documented an increase in oil recovery up to 5%of the original oil in place(OOIP)in sandstone core without clay[11].
The most acceptable mechanism of the LSWF is wettability change [12,13].However,the explanation of the physical mechanism of wettability change is still debatable.The other proposed mechanisms include fines migration,pH change effects,salting in,multi-component ion exchange(MIE),and double layer effects.The effect of the LSWF on oil recovery may be a result of multiple contributing mechanisms.
Tang and Morrow [14]proposed that mobility of fines could cause increased oil recovery.However,no solid particle production was observed during LSWF experiments [15-17].
An increase in the water pH because of LSWF was reported by McGuire et al.[18].They proposed that increasing pH can reduce the oil-water interfacial tension.However,Cissokho et al.showed significant increase in the pH without enhancement in the oil recovery[19].Furthermore,this mechanism was not agreed by other researchers who did not reveal any relation between the incremental oil recovery and pH of water [17,20,21].
Ligthelm et al.suggested that the LSWF can cause expansion of the double layer between the clay surface and the oil/water interface and increase in oil recovery[22].This mechanism was agreed by RezaeiDoust et al.,and Nasralla and Nasr-El-Din [7,21].
The mechanism of the Multi-component ion exchange (MIE)was suggested by Sposito[23].Later,Lager et al.and Ligthelm et al.proposed that the formation brine divalent cations,especially Ca2+,are essential for LSWF effect[20,22].This mechanism was accepted by Seccombe et al.,Buckley et al.and Arumugam et al.[9,24,25].However,Austad et al.and Cissokho et al.performed LSWF containing no divalent ions and reported an increase in the oil recovery[8,19].
This paper discusses the effects of permeability,clay types and content,and formation water salinity on the LSWF projects in secondary and tertiary stages.Furthermore,it studies the effect of applying HSWF in tertiary recovery stage after LSWF in the secondary recovery stage.These effects were studied on core plugs of Bahariya sandstone formation.
Bahariya formation is located in Abu Gharadig Basin (Western Desert,Egypt).The formation evaluation showed promising hydrocarbons potential with an average of 50 ft net pay sand interval.The well testing results of the discovery well showed an initial oil rate of ±3000 STB/D of volatile oil (42°API).The bubble point pressure was 2765 psi.The bubble point pressure was close to the initial reservoir pressure which was 2915 psi.
Bahariya formation has been producing naturally by the effects of solution gas drive,weak aquifer support,and most recently secondary gas cap drive.Therefore,the development strategy of the field included a water injection project to support the average reservoir pressure (pressure maintenance) of Bahariya formation.
The sedimentary section of the Western Desert of Egypt ranges from Early Paleozoic to Recent.According to the stratigraphic column of the Western Desert,Bahariya formation belongs to Cenomanian member,Upper Cretaceous age.Bahariya formation often exhibits rapid facies change laterally and vertically.It usually shows thick and clean sand intervals (tidal channels) interbedded with clay and silt intervals.The depositional environment of Bahariya formation is basically described as tidal flat with cross-cutting sand intervals and deep-water marine deposits.
Bahariya reservoirs in the area have two different water salinities(61000 and 34000 ppm)in two different fields.Therefore,both water salinities were used in the experiments of this work to saturate the core plugs and study the effect of formation water salinity on the LSWF project.
In addition,three alternatives injection water sources exist in the area:Lower Cretaceous Kharita formation water which is similar to the salinity of one of the Bahariya reservoir water(34000 ppm TDS),Miocene Moghra formation water (8000 ppm TDS),and Bahariya formation aquifer(61000 ppm TDS).One of the main objectives of this study is to identify which of these injection water sources will result in the highest recovery due to water injection in Bahariya reservoir.
3.1.Material and fluids
100 experimental runs were performed using 25 plugs in both secondary and tertiary stages.The core plugs used in this work were extracted from the sandstone producing reservoir in Bahariya formation.Table 1 shows the basic properties of the core plugs which are classified into five groups according to the experimental procedure.
In addition to the three available water sources in the area,two more water sources have been used in this work:water with lower water salinity of 3600 ppm and another one with higher water salinity of 122000 ppm.Table 2 shows the compositions of the dissolved mineral salts in the five sets of water samples.However,Table 3 presents the properties of the oil and injected water.
Furthermore,the clay content and the cation exchange capacity(CEC) experiments were performed on the second group samples.Table 4 summarizes the results of the clay content and the CEC measurements.The clay content was identified using XRD as shown in Fig.1.The CEC experiments were performed using the following steps:
Table 1 Core plugs properties.
Table 2 Composition of the dissolved mineral salts in the injected water.
Table 3 Oil and injected water properties.
Table 4 Clay content and cation exchange capacity (CEC) of core samples of group 2.
(1) The plugs trims were gently desegregated into grain size particles.These particles were(a)cleaned using toluene and acetone and (b) divided into two portions.
(2) The first portion was oven dried at 60°C (140°F) and 40%relative humidity.Then,it was cooled and reweighed to demonstrate moisture loss from the dried weigh.
(3) The second portion was passed through a refluxed 500-μm mesh sieve using ammonium chloride to make them water wet.
(4) The cation exchange sites were saturated with ammonium ions by immersing the samples in ammonium acetate,buffered to a pH of 7,for a period of 15 h.
(5) The excess ammonium acetate was removed by washing the samples with a 70%-30% methanol-water solution.Hydrochloric acid was used to displace ammonium ions by leaching.
(6) The amount of ammonium displaced was measured by titration with sodium hydroxide solution.
(7) The cation exchange capacity,expressed as meq/100 g,was calculated for each sample.
Fluid-rock compatibility tests between the rock and the different water samples were conducted.The results of the compatibility tests showed no significant decrease in permeability due to injection of water from the different water samples.
3.2.Experimental procedure
The plugs were divided into five groups.Each group contained plugs with different characteristics,representing the variations in Bahariya formation.The experiments of the first two groups were performed using formation water salinity of 61000 ppm.However,the experiments of the other three groups were conducted using formation water salinity of 34000 ppm.
The first group was used to study the effect of aging on oil recovery in the tertiary stage using 5 plugs with different permeability.The second group was the main group.It was used to study the effects of aging and injected water salinity in the secondary and tertiary recovery stages.The experiments were performed with salinity of 61000 ppm formation brine.The experiments of the last three groups were performed after obtaining the results of the second group.The experiments of the third group were conducted to investigate the effect of applying high water salinity (61000 ppm) in the tertiary recovery stage.Group 4 experiments were performed to study the effect of increasing the injection water salinity in the tertiary recovery stage to 122000 ppm.The effect of reducing the injection water salinity in the tertiary recovery stage was studied by applying WF with 3600 ppm brine in the last group.
Fig.1.XRD charts of the 2nd group plugs.
Furthermore,twin plugs from Groups 4 and 5 were used to investigate the effect of formation water salinity on oil recovery in the secondary stage.The two groups experiments were applied with different formation water salinity than the one used in the experiments of the second group.The results of the twin plugs experiments were compared with the results of the second group experiments.
All core plugs were prepared for flooding experiments with the same procedure as follows:
(1) The plug samples were cleaned from the hydrocarbons by the Soxhlet extraction using chloroform.
(2) The core samples were then dried using humidity drying in a conventional oven at 140°F.After that,the core samples were cooled in a sealed room temperature condition.
(3) The main lithological characteristics,color,rock type,grain size,sorting,and consolidation were examined under a microscope.
(4) The porosity and grain density were measured by a double cell helium expansion gas porosimeter.
(5) The gas permeability was measured with air using a calibrated steady state permeameter.
(6) Synthetic formation brine was used to saturate the core samples with 100% brine.
(7) The fully saturated core samples were placed in individual hydrostatic core holders under a confining pressure of 400 psig and oil was injected into the top of the core until water production ceased.
Furthermore,some of the plugs were used to continue the experimental procedures without aging in oil,while the others were aged in crude oil for 28 days to restore the reservoir wettability.These two experimental procedures have the following differences:
For the unaged core samples:
(1) The core samples were subjected to waterflood using specific brine as a secondary stage flooding until the oil production ceased (unsteady state flooding).Oil was displaced by keeping constant differential pressure across the core plugs and different flow rate at ambient temperature 25°C(77°F)in all experiments.
(2) The core samples were subjected to waterflood using different brine salinity as tertiary stage flooding at the same conditions of the secondary stage flooding.The excess oil production was measured,if any.
For the aged core samples under overburden pressure:
(1) The overburden pressure was increased gradually to the required effective value of 4,100 psi.The amount of the displaced oil by the decrease in the pore volume was determined.As the pore space had changed and the volume of water had remained constant,the initial water saturation as a percentage of the pore space was recalculated.
(2) The plug samples were then restored in an aging cell under reservoir temperature and pressure (194.5°F and 2924.5 psig) for 28 days.
(3) The restored state core samples were placed in individual hydrostatic core holders under a confining pressure of 4,100 psig.Then,the oil was injected into the top of the core until the brine production ceased.
(4) The core samples were subjected to water injection using specific brine as secondary flooding until the oil production ceased.Similar to the unaged core samples,oil was displaced by keeping constant differential pressure across the core plugs in all experiments.
(5) The core samples were subjected to waterflooding using different brine salinity as tertiary stage flooding at the same conditions of the secondary stage flooding.The excess oil production was measured,if any.
All the above procedures were repeated in the experiments of the second group using water of a different salinity as a secondary WF.The core samples were cleaned by the Soxhlet extraction and dried using humidity drying to ensure no residue inside the core.The porosity and permeability were measured after cleaning to assure that the cleaning process did not affect the quality of the core sample.Fig.2 presents the experimental procedure and the program for the five groups.
In this section,the experimental results obtained during the waterflooding in the secondary and the tertiary recovery stages are presented.In all experiments,the water injection was continued until the oil production ceased.
The first group of experiments were conducted on unaged core samples.The main objective of these set of experiments was to investigate the effects of core aging in the tertiary recovery stage.Table 5 summarizes the oil recovery for the five core samples which have different permeabilities.The core samples were initially flooded with brine of 61000 ppm salinity.Then,the core samples were flooded continuously with brine of 8000 ppm (low salinity).
The average oil recovery for the five samples was ±61% OOIP,with 41%OOIP as minimum oil recovery and 68%OOIP as maximum oil recovery.All core samples of this group did not show any additional recovery when subjected to tertiary water injection.
The second group of core plugs were used to compare oil recovery in cases of flooding with high and low salinity water in both secondary and tertiary stages.Table 6 summarizes the results of all flooding experiments of unaged core samples in the second group.Fig.3 summarizes the results of all flooding experiments of aged core samples in the second group.
Initially,the unaged core samples were flooded by brine of high salinity(61000 ppm)followed by brine of salinity of 34000 ppm as tertiary recovery stage.For the secondary recovery stage,the average oil recovery was±55.9%OOIP,with minimum oil recovery of 45.7% OOIP and maximum oil recover of 72.8% OOIP.All core samples of this group did not show any additional recovery in the tertiary recovery stage.
Secondly,after cleaning and repeating the basic procedure for the unaged core samples,they were flooded by brine of salinity of 34000 ppm followed by brine of 8000 ppm salinity.For the medium salinity brine,the average oil recovery was±53.8%OOIP,with a minimum recovery of 42.2% OOIP and a maximum recovery of 69.6%.The core samples also did not show any additional oil recovery in the tertiary recovery stage.
Thirdly,the core samples were cleaned and the basic procedure for the aged core samples were repeated.After that the core samples were aged in oil for 28 days.Then,they were flooded with brine of high salinity(61000 ppm)followed by brine of 34000 ppm salinity.An additional oil recovery was noticed,but with different percentages varying from 1.3% to 3.2%.
Fourthly,after cleaning the aged core samples,the basic procedure for the core samples preparation were repeated.Then,they were flooded by brine of salinity of 34000 ppm and followed by brine of 8000 ppm salinity.An additional oil recovery was also noticed,but with different percentages ranging between 1% and 4.4%.
Finally,the aged core samples were cleaned and prepared again to be flooded by brine of low salinity(8000 ppm)followed by brine of high salinity (61000 ppm).This step was performed to investigate the possible reasons for the additional oil recovery in the tertiary stage:whether it is due to applying low salinity flooding or due to the change of water salinity(either increasing or decreasing the salinity).An additional oil recovery between 1.5%and 2.1%was noticed.
Table 7 shows the measured parameters after cleaning of the core plugs in each step.The results show that the cleaning procedure have insignificant change on the quality of the core samples.
Table 5 Results of core flooding for group 1.
Table 6 Results of core flooding for unaged samples in group 2.
Table 7 -Porosity and permeability measurements after cleaning of the 2nd group samples.
The core sample with 3 mD permeability (Sample 6) displayed the highest oil recovery (57.5% of the OOIP),when it was flooded with water of low salinity (8000 ppm)for aged core sample cases.However,the oil recovery after flooding the plug with water of 34000 ppm and 61000 ppm salinities was 35.5%and 54.1%of OOIP,respectively.
Usingthe high andlowsalinity brinesinthetertiaryrecoverystage also showed similar incremental oil recovery:when the core sample was flooded by brine of 61000 ppm salinity followed by brine of 34000 ppm salinity in the tertiary stage,the incremental oil recovery was 1.6%of the OOIP.In addition,when the core sample was flooded by brine of 8000 ppm salinity followed by brine of 61000 ppm in the tertiary stage,the incremental oil recovery was 1.8%of the OOIP.
The core sample with 4 mD permeability (Sample 7) exhibited the lowest oil recovery of 39.4% of the OOIP,when it was flooded with water of low salinity (8000 ppm) for the aged core samples.However,the highest oil recovery was approximately 46% in the flooding experiments with water of a medium salinity of 34000 ppm in aged core samples,while flooding the core sample with high salinity brine (61000 ppm) showed slightly better oil recovery (45.7% of OOIP).Then,additional recovery (2.7% of OOIP)was achieved by flooding the core sample with medium salinity brine (34000 ppm).
Using the low salinity brine (8000 ppm) in the tertiary stage showed higher increase in the incremental recovery(3.1%of OOIP)versus the incremental recovery (1.7% of OOIP) by changing the salinity from 8000 ppm to 61000 ppm.
The core sample with 6 mD permeability (Sample 8) achieved the highest oil recovery (51.7% of OOIP),when it was flooded with water of salinity 34000 ppm for aged core samples.This recovery is 8%higher than the oil recovery which was obtained when the core sample was flooded with low salinity water of 8000 ppm.
The highest additional oil recovery in the tertiary stage(2.3%of OOIP) was achieved by applying LSWF.The two different salinity showed almost the same additional oil in the tertiary stage(±1.4%of OOIP).
The sample with 24 mD permeability (Sample 9) gave the highest oil recovery of 61.5% of OOIP,when it was flooded with water of salinity of 8000 ppm for aged core samples.However,when the core sample was flooded with water of 8000 ppm salinity,the oil recovery was higher with 7% and 11% than when it was flooded with 61000 ppm and 34000 ppm water salinity,respectively.
Applying the LSWF (8000 ppm) in the tertiary stage showed higher incremental oil recovery (4.2% of OOIP) comparing to the incremental recovery(±2%of OOIP)which was achieved when the HSWF (61000 ppm) was applied in the tertiary stage.
The core sample with 86 mD permeability(Sample 10)gave the highest oil recovery(68%of OOIP),when it was flooded with water of 61000 ppm salinity for aged core samples.This recovery is 20%higher than the oil recovery resulting from flooding the core sample with low salinity water of 8000 ppm.
The highest additional oil recovery in the tertiary stage (3% of OOIP) was shown by applying medium salinity brine WF and changing the salinity from 61000 ppm to 34000 ppm.However,the LSWF showed the lowest additional oil recovery in the tertiary stage (±1.1% of OOIP).
The core sample with 924 mD permeability(Sample 11)gave the highest oil recovery (70.9% of OOIP),when it was flooded with water of salinity of 61000 ppm for aged core samples.This recovery is 14% higher than the oil recovery which was achieved when the core sample was flooded with water of low salinity of 8000 ppm.
The medium salinity brine in the tertiary stage showed increased incremental oil recovery (3.2% of OOIP) by changing the salinity from 61000 ppm to 34000 ppm comparing to the achieved incremental oil recovery (±1.5% of OOIP) in the HSWF and LSWF(61000 and 8000 ppm) in the tertiary recovery stage.
The third group of cores were used to study the effect of applying high water salinity flooding (61000 ppm) after medium water salinity(34000 ppm)to confirm the previous results.All core samples showed additional recovery as shown in Fig.4.The incremental recovery varied from 0.5% to 3.6%.
Fig.2.Experimental procedure flow chart.
The fourth group was used to investigate the effect of decreasing the water salinity to 3600 ppm in the tertiary recovery stage.All core samples did not show any additional recovery as shown in Fig.5 which reveals that applying low water salinity in the tertiary stage does not yield incremental oil recovery in all conditions.The group samples obtained the highest recorded oil recovery (73% of OOIP at core permeability higher than 1000 mD) by flooding the aged plugs with medium salinity brine (34000 ppm).However,in the tertiary stage,by flooding the plugs with low salinity brine(3600 ppm),no incremental oil recovery was observed in any one of the tested plugs including the highest permeability core sample.
Fig.3.Results of core flooding experiments for aged samples of group 2.
The fifth group was used to study the effect of increasing the water salinity to 122000 ppm in the tertiary recovery stage.All core samples exhibited additional recovery from 1.4 to 2.3% of OOIP as shown in Fig.6.
The results of the five groups of core flood experiments explained above are analyzed in the following sections.It is beneficial to combine all results to answer two important questions for designing LSWF projects:(1)when is LSWF effective?and(2)what factors make the LSWF effective or ineffective?The analysis of the results will start with the learnings from applications of LSWF in secondary recovery stage,followed by the learnings from application of LSWF in tertiary recovery stage.
5.1.Effect of the LSWF in the secondary recovery stage
The core flooding experiments were performed for Group 2(aged and unaged samples)to investigate the core aging effects on recovery in the secondary stage.The second group unaged samples only were initially flooded with two different salinities as a secondary stage flood:high salinity brine (61000 ppm) and medium salinity brine (34000 ppm).Fig.7 illustrates the secondary waterflooding oil recovery for the two different salinities for the same plugs.The figure shows that for most core plugs,the oil recovery due to secondary WF was almost the same except for Sample 10.Sample 10 has the lowest amount of overall clay content,lowest amount of kaolinite,highest feldspar,lowest cation exchange capacity,and permeability of 86 md.The sample showed 10% lower oil recovery during WF with the brine of low salinity.
Fig.3.(continued).
Fig.8 shows the oil recovery for the aged core plugs of the second group using brine of different salinities in the secondary stage WF.The results show that the LSWF is not always advantageous to high salinity WF in the aged core samples.The effect of changing waterflooding salinity on oil recovery depends on multiple parameters:kaolinite content,plagioclase feldspar content,Kfeldspar content,CEC,and permeability.Fig.9 shows the values of these parameters for the different samples.
Samples 6 and 9 have high values of CEC(11.4 Meq/100 g and 6.6 Meq/100 g,respectively),high amount of kaolinite(18.1%and 8.3%)and the least amount of plagioclase-feldspar(5%and 5.5%).The two samples showed high oil recovery (57.5% and 61.5%) when LSWF(8000 ppm)was applied(3-22%higher oil recovery than medium and high salinity WF).Samples 7 and 11,on the other hand,have low CEC values (less than 6 Meq/100 g),and almost similar amounts of kaolinite,plagioclase feldspar and K-feldspar (around 5-8%for each clay type).In addition,Sample 8 has high amount of kaolinite(11.2%)and plagioclase feldspar(11.5%)with no k-feldspar(zero).The LSWF (8000 ppm) for the three samples (Samples 7,8 and 11) showed 5-10% higher oil recovery than medium and high salinity WF (34000 and 614000 ppm).Sample 10 has the lowest amount of kaolinite (5.0%) and cation exchange capacity CCE (5.1 Meq/100 g).However,it has the highest amount of plagioclase feldspar and k-feldspar(12.3%and 7.3%,respectively).The LSWF for Sample 10 showed 20% lower oil recovery than the HSWF.
These observations reveal that the plugs of high amount of kaolinite and CEC showed higher oil recovery with the LSWF.In addition,the core plugs with high amount of plagioclase feldspar showed low oil recovery with the LSWF.The relation between other clay minerals (k-feldspar,illite,chlorite,and smectite) and oil recovery is not clear in the reported experiments and needs further investigation.
Fig.4.Results of core flooding experiments for group 3.
Fig.5.Results of core flooding experiments for group 4.
These results of unaged and aged plugs in the second group are consistent with the previous observations in the literature.Amirian et al.showed that kaolinite effect is essential during the LSWF[10].In addition,Shehata and Nasr-El-Din showed that double layer effect due to kaolinite content is important factor for the LSWF[26].High CEC is an indication of increased double layer effect.
Plagioclase minerals effect was studied by Strand et al.who demonstrated that plagioclase minerals can have positive or negative effects on the LSWF according to the formation water salinity and flooding temperature [27].They showed that plagioclase can have initial pH ＞7,if the formation water salinity is moderate.In addition,pH can reach 10 at low temperature(40°C),while it can reach 8 at high temperature (130°C).Furthermore,Garrels and Howard reported an increase in the pH during the reaction of K-feldspar with water due to altering K-feldspar to kaolinite[28].The following chemical equations show the reaction of both plagioclase (NaAlSi3O8) and K-feldspar (KAlSi3O8) with water.
Fig.6.Results of core flooding experiments for group 5.
The feldspar effect can be illustrated by the pH effect.One of the mechanisms in the LSWF is the increased pH associated with the secondary water injection.The increase in the pH increases the positive effect of the LSWF [8,18].Therefore,high initial pH decreases the positive effect of the LSWF (since the incremental increase in pH will be low).Brady et al.documented that the oil/kaolinite edge interaction can be highly repulsive for initial pH range between 6 and 9 at all salinities [29].This repulsive interaction reduces the positive impact of LSWF.According to the chemical reactions explained above,plagioclase feldspar can increase initial pH above 6 and reduce the positive impact of LSWF.
Fig.7.Oil recovery in the secondary stage for plugs of group 2 (unaged samples).
The positive impact of LSWF may be expected in reservoirs with high amount of kaolinite,high values of CEC,and low amounts of plagioclase feldspar.
Furthermore,the results of the current work are consistent with the results of Naeem and Dehaghani who documented that there is an optimum water salinity that enables the highest displacement of oil droplets [30].Similar conclusion was also independently reached by Snosy et al.[31].Therefore,experimental work for potential LSWF-application reservoirs is essential for determining the optimum salinity(provided that several water sources are available at comparable costs).
Fig.8.Oil recovery in the secondary stage flooding for the plugs of the second group(aged samples).
Fig.9.Clay content and CEC for the samples of the second group.
Fig.10.Results of twin plugs in the secondary flooding for the fourth and fifth groups(aged samples).
In addition to the above,the results of the last two groups(Groups 4 and 5)document the role of the formation water salinity in the waterflooding process.Fig.10 shows the oil recovery for different water salinities in the secondary stage for the twin plugs from the fourth and fifth groups.Applying water flooding with salinity of 34000 ppm (which is equal to the formation water salinity) showed higher oil recovery than applying water flooding with salinity of 61000 ppm.The additional oil recovery ranged from 5% to 13% of OOIP.The results confirm that the composition and salinity of formation water can change the displacement efficiency in the secondary water injection projects.
5.2.Effect of the LSWF in the tertiary recovery stage
The application of low salinity water flooding as a tertiary stage for unaged samples in the first and second groups is ineffective.The samples demonstrated no additional recovery in the tertiary stage even for the high permeability unaged plugs.No incremental oil recovery in the unaged plugs can be attributed to the clay effect.Aging samples in oil may allow clay minerals to absorb organic components which are the target of the LSWF in the tertiary stage.
Fig.11.Incremental oil recovery in the tertiary stage for the plugs of the second group(aged samples).
The effect of different water salinities in the tertiary stage was studied in the second group plugs(aged plug samples)as shown in Fig.11.The LSWF showed the highest oil recovery in Samples 6,7,8,and 9.The brine of medium salinity showed the highest oil recovery in Samples 10 and 11,which have the lowest values of CEC and highest values of permeability.It also seems that the plugs with high permeability show good recovery anyway,regardless of the salinity of the injected water.This means that the LSWF will have the potential to improve the recovery of low permeability rock more than high permeability rock.The results also reveal that there is an optimum salinity in the tertiary stage that may be different from the optimum salinity in the secondary stage.
Applying HSWF after LSWF in the second group aged samples showed low incremental oil recovery (±2% of OOIP).The results were confirmed by Groups 3 and 5 experiments.The results of the third group showed that flooding the plugs with high salinity brine(61000 ppm) following the medium salinity (34000 ppm) yielded improvement in the oil recovery(1.5%of the OOIP as an average and 3.6%as maximum).Increasing water salinity to 122000 ppm in the fifth group showed incremental oil recovery up to 2.3% of OOIP.Strand et al.documented a decrease in the pH value from 10 to 7 when water salinity is changed from low to higher salinity[28].The decrease in the pH value is believed to reduce the double layer thickness,which may result in expelling some of the oil contained within the clay.
The salinity reduction to 3600 ppm in the fourth group has not shown any incremental oil in the tertiary stage flooding.These results show that the very low salinity of 3600 ppm was not effective in the tertiary recovery stage for the fourth group of plugs.The reason for not increasing recovery with decreasing the salinity might be explained by osmosis effects.Naeem and Dehaghani documented that water molecules move from low-salinity water through oil to connate water due to the difference in their osmotic pressure(difference in chemical potential) [30].Introducing water molecules from the low salinity water causes the swelling of connate water and moves oil towards pore throats.Further reduction in the salinity of the injected water causes lower displacements of oil and less recovery (as observed here).
(1) There is an optimum salinity for water flooding each reservoir rock.Careful design of water injection (when cost allows) will improve displacement efficiency and yield additional recovery.
(2) Applying waterflooding with the optimum salinity in the secondary stage may result in 5-20% higher recovery than applying water flooding with any other salinity.
(3) Optimum water salinity for secondary and tertiary WF depends on traditional factors (e.g.permeability and heterogeneity)and other factors such as kaolinite,CEC,plagioclase feldspar,and K-feldspar.
(4) The potential of LSWF may be expected in reservoirs which have high amount of kaolinite,high values of CEC,and low amount of plagioclase feldspar.This result has been obtained from Group 2 experiments.Therefore,further investigation may be required to validate this result.
(5) Increased kaolinite content (up to 18%) and increased CEC have positive effects for LSWF in absence of other effects.However,increased kaolinite is usually correlated with lower permeability,which generally reduces the recovery efficiency.
(6) The relation between k-feldspar and oil recovery is not clear and needs more investigation.
(7) Experimental work for each specific reservoir is essential for determining the optimum salinity.
(8) Changing the water salinity (not LS) in the tertiary stage of EOR waterflooding may give minor additional recovery.
(9) Changing water salinity(not only reducing water salinity)in the tertiary stage may result in higher oil recovery.Incremental oil recovery of up to 5%in tertiary stage has been seen in the experiments reported here.
Declaration of competing interests
The authors have no affiliation with any organization with a direct or indirect financial interest in the subject matter discussed in the manuscript.
Acknowledgement
This work was executed through unfunded research project at Cairo University (Egypt).
Nomenclature
Abbreviations
CEC Cation exchange capacity
EOR Enhanced oil recovery
H.S.1 High water salinity with 122000 ppm TDS
H.S.2 High water salinity with 61000 ppm TDS
HS High salinity water
HSWF High salinity waterflooding
L.S.1 Low water salinity with 8000 ppm TDS
L.S.2 High water salinity with 3600 ppm TDS
LS Low salinity water
LSWF Low salinity waterflooding
M.S.Medium water salinity with 34000 ppm TDS
MIE Multi-component ion exchange
OOIP Original oil in place
PV Pore volume
Sec Secondary stage flooding
TDS Total Dissolved Solids
Ter Tertiary stage flooding
WF Waterflooding
Symbols
k Permeability,mD
Swi Initial water saturation,fraction
Φ Porosity,fraction