mitigation of anhydrite dissolution in alkaline floods through injection of conditioned water

Fuel 107 (2013) 330–342

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Fuel

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Mitigation of anhydrite dissolution in alkaline floods through injectionof conditioned water

Mahdi Kazempour 1, Casey S. Gregersen, Vladimir Alvarado ⇑Department of Chemical and Petroleum Engineering, University of Wyoming, Laramie, WY 82071, USA

h i g h l i g h t s

" We prove that EDTA does not decrease calcium concentration in anhydrite-containing rocks." A new paradigm to mitigate anhydrite dissolution during alkaline floods has been tested." Engineered water is a potentially effective strategy to produce ASP blends.

a r t i c l e i n f o

Article history:Received 2 August 2012Received in revised form 1 October 2012Accepted 3 October 2012Available online 11 December 2012

Keywords:Chemical enhanced oil recoveryReactive transport modelingAnhydrite dissolutionEngineered water chemistry

0016-2361/$ - see front matter � 2012 Elsevier Ltd. Ahttp://dx.doi.org/10.1016/j.fuel.2012.10.003

⇑ Corresponding author.E-mail address: [email protected] (V. Alvarado)

1 Current address: TIORCO LLC, Denver, CO 80231, U

a b s t r a c t

Chemical enhanced oil recovery projects occasionally introduce an alkali agent to meet design require-ments. The alkali agent reacts with reservoir rock components upon injection in reservoirs. It has beenreported that the interaction of the injected alkali with some minerals in the rock assemblage, particu-larly anhydrite, is responsible for the very large alkali consumption, formation of secondary minerals,and regulates water chemistry. These effects, when unanticipated, can jeopardize the success of a chem-ical flooding project. In this study, single and two-phase flow flooding tests were carried out using rocksamples from a sandstone reservoir in Wyoming to investigate the impact of multiphase flow on anhy-drite dissolution at high-pH conditions. Effluent water chemistry was analyzed to investigate rock–fluidinteractions taking place during an alkaline flood. Rock samples were CT-scanned to find out anhydritedistribution. Mitigation of harmful effects of rock–fluid interactions under alkaline flooding has been pro-posed through the addition of ethylenediaminetetraacetic acid (EDTA) to act as a calcium chelating agent.The effectiveness of EDTA was tested in single- and two-phase flow experiments. An alternative approachto mitigate damaging effects of alkali injection in anhydrite-containing rock, based on conditioning ofinjection water, was tested in this work. Results show that anhydrite dissolution diminishes when crudeoil is present, but the effect depends on rock exposure time to oil (aging). In spite of the apparentdecreased reactivity, anhydrite dissolution is still very pronounced in two-phase flow experiments.Results also show conclusively that water conditioning intended to diminish anhydrite dissolution chem-ical driving force is a more effective strategy to attain sustainable flooding conditions.

� 2012 Elsevier Ltd. All rights reserved.

1. Introduction

The importance of an alkali agent in chemical enhanced oilrecovery methods has been studied vastly for more than four dec-ades. It has been claimed that alkali enhances oil mobilizationthrough three main mechanisms: first by lowering IFT due togeneration of in situ soap [1–4], second, by lowering interfacialtension (IFT) between oil and water to ultra-low values in combi-nation with surfactants [5–9] and third, by altering the wettabilityof the rock surface [10]. Moreover, an alkaline agent is able to

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.SA

sequester divalent cations from the aqueous phase thus regulatingthe phase-behavior of the surfactant-soap system [11]. Also, byincreasing the negative charge density on rock surfaces, an alkaliagent reduces the adsorption of anionic surfactants and partiallyhydrolyzed polyacrylamide (HPAM) on rock surfaces [11–13],which can aid ASP flooding economic feasibility. The aforemen-tioned roles of alkaline agents are attributed to their ability to in-crease pH. The propagation of a high pH front through a formationis a strong function of alkali consumption, as well as alkali type. Ingeneral, alkali consumption can be induced mainly by the follow-ing four reactions with: (1) crude oil (during the saponificationprocess), (2) multivalent cations in the formation water, (3) claysthrough the cation exchange process and finally, and (4) mineralsduring the dissolution and precipitation processes.

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Table 1Properties of the crude oil.

Property Value

Specific gravity (48 �C) 0.92Viscosity (48 �C) (cP) 83Total acid number (mg KOH/gr oil) 0.43

Asphaltenes: 5.41%Saturates: 35.29%

SARA analysis Aromatics: 35.18%Resins: 8.85%Volatiles: 15.27%

Table 2Properties of the cores.

Core I-85b (two-phase flowtest)

I-85b (single-phase flow test)

I-76 I-107 I-85 l

Length (cm) 7.53 7.53 7.59 7.87 7.65Pore volume

(cc)10.74 10.84 14.81 14.38 13.13

Porosity (%) 12.71 12.85 17.4 16.2 15.3Permeabilityair

(mD)54.3 57.3 233.3 88 140.7

M. Kazempour et al. / Fuel 107 (2013) 330–342 331

Among the aforementioned consumption mechanisms, thoseassociated to crude oil represent a small fraction only [14] and itis mainly a function of the type and concentration of alkali agentand also the type and the amount of organic acids present in thecrude oil. Generally, consumption of alkali by reactions with crudeoil and formation water can be obtained or estimated in batchexperiments or simple fluid–fluid interaction analysis, whereas,realistic analysis of alkali consumption by rock (including bothclays and minerals) requires more complex dynamic tests and geo-

Fig. 1. Coreflooding s

chemical simulations. In contrast with consumption of alkali byclays that is usually prompt and reversible, the consumption of al-kali by minerals is irreversible and generally slow. However, anhy-drite, with high dissolution kinetic rate, hastens the consumptionrate of alkali significantly. The interaction of alkali with minerals,particularly anhydrite, leads to mineral dissolution and consequentscale formation resulting in possible porosity–permeability alter-ation and significant changes in water chemistry. Therefore, studiesof anhydrite dissolution under various conditions is paramount tothe success of chemical enhanced oil recovery methods.

In this study, single- and two-phase flow alkali flooding testswere carried out on core samples from a sandy reservoir inWyoming to investigate the impact of oil on anhydrite dissolutionat reservoir temperature. Single-phase flow experiments referredto aqueous phase flooding in the absence of any oleic phase, so thataqueous-phase saturation is always 100%. This type of experimentsprovides rock–water reactivity data at 100% water saturation.Two-phase flow experiments imply partial saturation of crude oiland aqueous phase. This classification does not imply that bothphases always flow. For instance, when residual oil saturation isattained, only aqueous phase is produced, but we still refer to thisas a two-phase flow experiment. It is a convenience rather than aprecise terminology.

In order to address the intensity of rock–fluid interactions, efflu-ent samples were analyzed to track water chemistry during thetest. Cores were CT-scanned before and after flooding to examinethe initial and final anhydrite distribution. We investigated claimson the potential of ethylenediaminetetraacetic acid (EDTA) as cal-cium sequestering agent through single and two-phase flow exper-iments in this anhydrite-containing rock. An alternative approachbased on water conditioning proves to be more effective to miti-gate anhydrite dissolution under alkaline conditions, as per designsdetermined through reactive transport modeling and subsequentexperimental evaluation.

etup schematics.

Fig. 2. CT-images of core I-85b before two-phase flooding test (light-gray color represents anhydrite).

10−6

10−5

10−4

10−3

10−2

10−1 Io

n co

ncen

trat

ion

(Mol

ar)

Ca2+

Mg2+

SO42−

WF 1st NaOH & WF

2nd NaOH & WF EDTA & WF

332 M. Kazempour et al. / Fuel 107 (2013) 330–342

2. Materials and methods

2.1. Materials

The crude oil (DC oil) and rock plugs in this study were obtainedfrom an oil-bearing formation in Wyoming. The properties of thecrude oil and each rock plug are tabulated in Tables 1 and 2,respectively. The alkali and the chelating agent are sodium hydrox-ide (NaOH) and EDTA tetrasodium salt dihydrate (Na4EDTA�2H2O).NaOH is selected as an alkali agent due to its ability to sustain highpH conditions compared to other conventional alkalis in presenceof anhydrite [15]. It has been reported that EDTA binds multivalentcations in aqueous phase at high pH conditions, limiting theirprecipitation as secondary minerals [16–19].

0 5 10 15 20 25 3010−7

Inj. PV

Fig. 4. Effluent ions concentrations at different injection pore volume during two-phase flow experiment in I-85b core.

2.2. Experimental methodology

After cleaning the rock plugs with an organic solvent (toluene +methanol), the rock samples are dried and then CT-scanned to re-veal the anhydrite profile in the rock sample. Crude oil can affectanhydrite dissolution by, first, reactions of crude oil with alkali

0 5 10 15 20 25 300

25

50

75

100

RF

(%O

OIP

)

Inj. PV0 5 10 15 20 25 30

0

25

50

75

100

Pre

ssur

e dr

op (p

si)

WFFirst NaOH & WF

Second NaOH & WF EDTA & WF

Shut−in event

Fig. 3. Oil recovery factor and pressure drop as functions of the number of injectedpore volumes during two-phase flow experiment in I-85b core.

0 5 10 15 20 25 304

6

8

10

12

14

Inj. PV

pH

Effluent pH Inlet pH

Fig. 5. Effluent and inlet pH at different flooding steps during two-phase flowexperiment in I-85b core.

Fig. 6. CT-images of core I-76 before two-phase experiment (light-gray color represents anhydrite).

0 5 10 15 20 25 300

25

50

75

100

RF

(%O

OIP

)

Inj. PV0 5 10 15 20 25 30

0

1.25

2.5

3.75

5

Pre

ssur

e dr

op(p

si)

%OOIPPressure drop

WF 1st NaOH & WF

2nd NaOH & WF

EDTA & WF

Fig. 7. Oil recovery factor and pressure drop as functions of the number of injectedpore volumes during two-phase flow experiment in I-76 core.

0 5 10 15 20 25 3010−7

10−6

10−5

10−4

10−3

10−2

10−1

Inj. PV

Ion

conc

entr

atio

n (M

olar

)

Ca2+

Mg2+

SO42−

SO42−

Ca2+

Mg2+

Fig. 8. Effluent ion concentrations at different flooding steps during two-phase flowexperiment in I-76 core.

0 5 10 15 20 25 304

6

8

10

12

14

Inj. PV

pH

Effluent pH Inlet pH

Fig. 9. Effluent and inlet pH at different flooding steps during two-phase flowexperiment in I-76 core.


and second, by coating anhydrite surfaces, which alters the amountof active surfaces of anhydrite. To study the aforementioned effectsof crude oil on anhydrite dissolution both single and two-phaseflow experiments were performed.

2.2.1. Two-phase flow experimentsTwo core plugs, 1.5’’ � 3’’ (diameter � length) were vacuum sat-

urated in degassed 2000 ppm NaCl brine for 1 day and then aged inthe same brine for 10 days at 500 psi confining pressure and a tem-perature of 48 �C. To measure rock permeability to brine, the coreswere flooded with the same synthetic brine while varying the flowrate from 0.5 ml/min to 0.7 ml/min and recording the pressuredrop between the inlet and outlet sections of the rock plug. Con-nate water saturation was established by flooding the cores withcrude oil that had been filtered and centrifuged to remove finesat a rate of 0.5 ml/min until no more water was produced andthe pressure drop stabilized. This typically required the injectionof three pore volumes (PVs) of crude oil. Aging time with oil waseither less than 1 day or 30 days. At the end of the oil aging period,core plugs were then water flooded with brine containing

Fig. 10. Observed formation damage after two-phase flow experiment in I-76 core.

Fig. 11. Elemental distribution map of the I-76 inlet face after two-phase flow experiment.

0 5 10 15 20 25 300

0.8

1.6

2.4

3.2

4

Pre

ssur

e dr

op (p

si)

Inj. PV

0 5 10 15 20 25 304

6

8

10

12

14

pH

Pressure dropEffluent pH

1st NaOH & WF

WF 2nd NaOH & WF

EDTA & WF

Fig. 12. Pressure drop and effluent pH at different flooding steps in single-phaseflow experiment (core I-85b).


2000 ppm NaCl for 8 PVs to establish residual oil saturation. Rockpermeability to brine was then measured at residual oil saturation.For tertiary chemical flooding, first, 0.5 PV of 1 wt.%NaOH + 2000 ppm NaCl solution was injected and then chasedwith a 5 PV injection of a 2000 ppm NaCl brine. After the firstbrine-flood, 1 PV of 1 wt.% NaOH + 2000 ppm NaCl solution was in-jected and the system was shut in for 15 h. Following the shut-inperiod, the cores were waterflooded with 2000 ppm NaCl solutionfor 4 PVs. Once the second brine-flood was completed, a solution of11,000 ppm Na4EDTA�2H2O + 2000 ppm NaCl was injected for 4PVs. Finally, the cores were flushed with 4 PVs of 2000 ppm NaClbrine. At the conclusion of the final 4-PV waterflooding step, waterpermeability was again measured. The effluent fluid was collectedusing an automatic fraction collector for water chemistry analysis.Pressure drop was recorded for all flooding steps and plotted alongwith oil recovery. Flow rates for water and chemical floods wereset at 0.5 ml/min. The coreflooding system schematics is shownin Fig. 1.

2.2.2. Single-phase flow experimentsAt the completion of the two-phase flow experiments, cores

were cleaned and dried. After re-measuring porosity and perme-ability, X-ray diffraction (XRD) and scanning electron microscope(SEM) tests were also performed whenever possible to further ana-lyze dissolution/precipitation events resulting from rock–fluidinteractions.

In single-phase flow experiments, operational conditions inclu-ding the type and slug size of injected materials, concentrations ofchemicals, temperature and flow rates were kept the same as inthe two-phase flow experiments. This was implemented to directly

0 5 10 15 20 25 3010−7

10−6

10−5

10−4

10−3

10−2

10−1

Inj. PV

Ion

conc

entr

atio

n (M

olar

)

Ca2+

Mg2+

SO42−

SO42−

Ca2+

WF 1st NaOH & WF

2nd NaOH & WF

EDTA & WF

Fig. 13. Effluent ion concentrations at different flooding steps during single-phaseflow experiment in I-85b core.

Fig. 14. Comparison between water chemistry of the aqueous phase with andwithout oil (core I-85b and I-76).

0.3 0.4 0.520

40

60

80

100

120

NaOH (wt %)

Req

uire

d am

ount

of N

a 2SO4 (g

r/lit)

data 1

Fig. 15. Required amount of Na2SO4 at different concentration of NaOH (48 �C).

0 2 4 6 8 100.5

1

1.5

2

2.5

3

Inj. PV

Anh

ydrit

e (v

ol%

) at t

he in

let s

ectio

n

0.4 wt% NaOH1wt% NaOHNa4EDTA. 2H2O (11,000 ppm)

Na2SO4 (59,150 ppm)

1wt%NaOH + Na4EDTA. 2H2O

0.4 wt% NaOH + Na2SO4

Conditioned WF

Fig. 16. Amount of anhydrite (vol.%) at the inlet face of the core during WF anddifferent chemical flooding scenarios.

0 2 4 6 8 100

250

500

750

1000

1250

1500

Inj. PV

Ca2+

con

c. a

t effl

uent

(ppm

)


Na2SO4 (59,150 ppm)



WF (2,000 ppm NaCl brine flood)

Conditioned WF

0 2 4 6 8 100

250

500

750

Inj. PV

Fre

e C

a2+ c

onc.

at e

fflue

nt (p

pm)


Na2SO4 (59,150 ppm)



Fig. 17. Effluent total (top) and free (bottom) calcium concentrations during WFand different chemical flooding scenarios.


address possible discrepancies between the results of two- and sin-gle-phase flow experiments associated to the presence of crude oil.As in two-phase flow experiments, pressure drop data and effluent

water samples were collected and analyzed over the entire flood-ing period.

Whenever possible, a single-phase flow experiment wasconducted after aging in brine, before any oil has contacted therock in the laboratory, and one after the waterflooding phase(removing residual oil with solvent at the end of the two-phase

0 2 4 6 8 104

6

8

10

12

14

Inj. PV

pH

at e

fflue

nt


Na2SO4 (59,150 ppm)



WF(2,000 ppm brine flood) Conditioned WF

Fig. 18. Effluent pH during WF and different chemical flooding scenarios.


flow experiment). With the single-phase flow experiments beforeand after waterflooding a core at initial irreducible water satura-tion, one can compare effects related to the presence of oil andestablish that the observed differences between single- and two-phase flow experiments are indeed related to oil coating of surfaces.

2.3. Numerical modeling

In this study, numerical modeling was utilized to gain insightinto the relationship between the composition of the injectedwater and anhydrite dissolution rate. For this purpose, a calibratedreactive transport model that works reasonably well at high-pHcondition was used [15]. XRD and SEM evidence indicate that thecores mineralogically consisted primarily of quartz, dolomite,anhydrite and k-feldspar in fractions that allowed adequate matchof effluent chemistry.

Fig. 19. Phase behavior of DC oil and 1 wt.% surfactant + 1 w

3. Results and discussion

3.1. Two-phase flow experiments

3.1.1. Short-term crude oil aging period (core I-85b)The CT-scanning results of core (I-85b) are shown in Fig. 2.

Anhydrite was identified as being distributed in thin layersthrough the core. Pressure drop and oil recovery (produced fractionof the original oil in place at surface conditions) data are plotted to-gether in Fig. 3. As expected, oil recovery increased slightly duringalkali and subsequent post brine flooding steps. Compared toNaOH and chase brine flooding steps, EDTA and following brineinjection lowered the pressure drop. Unlike NaOH, EDTA floodingdid not cause secondary mineral precipitation and instead, itsinjection induced more dissolution. The concentrations of calcium,magnesium and sulfate at effluent are depicted in Fig. 4. These re-sults show that calcium and sulfate were produced in similar con-centrations (in Molar unit) during water flooding, which is a goodindication that they originated from the same source (speculatedhere to be anhydrite) in contrast with the high-pH front arrival,when calcium concentration decreased and sulfate concentrationincreased. The latter is due to the precipitation of calcium at highpH conditions and consequent anhydrite dissolution that leads tohigher concentration of sulfate. Additionally, the observed lowmagnesium concentration at effluent is due to the precipitationof brucite (Mg(OH)2) under high pH conditions. In contrast withNaOH, as EDTA was injected, the total concentration of calcium,magnesium and sulfate ions in aqueous phase increased signifi-cantly even compared to the initial water flooding period, indicat-ing that EDTA prompted anhydrite and dolomite dissolution. Onthe other hand, during the EDTA flooding, calcium ions did notdrop out as a precipitate and remained in the aqueous phase as afree ion and in other forms such as calcium–EDTA complexes.The pH trend at effluent (Fig. 5) shows that sustaining pH higherthan 12 (inlet pH was roughly 13.2) was not possible under theconditions of this test, even after 1 PV injection of 1 wt.% NaOHand a previous alkali preflush step.

t.% NaOH with varying NaCl weight fraction (at 48 �C).

Fig. 20. Phase behavior of DC oil and 1.wt.% surfactant + 1 wt.% NaOH with varying Na2SO4 weight fraction (at 48 �C).


3.1.2. Long-term crude oil aging period (core I-76)CT scans of the core (I-76) used in this section (Fig. 6) showed a

thick layer of anhydrite in one third of the length of the core. Thepressure drop and oil recovery data of this test are shown inFig. 7. Similar to the results of the previous test, different alkaliand water flooding steps did not improve recovery factor signifi-cantly and no serious permeability damage was observed at the

Fig. 21. Phase behavior of DC oil and 1 wt.% surfactant + 0.4 w

conclusion of the flooding process. The trends of divalent cations(Ca2+ and Mg2+) and sulfate concentrations were similar to whatwas found in the first test (Fig. 8). The main difference betweenthis and the former test is the pH trend. As opposed to the resultsof the first two-phase flow experiment, there was a larger retarda-tion of OH� ions (Fig. 9) in this test. This retardation might be dueto either a higher concentration of active clays present in this core

t.% NaOH with varying Na2SO4 weight fraction (at 48 �C).

Fig. 22. The CT-scanning results of core I-107 (bright color represents anhydrite).

5 10 15 20 25 30 350

100

200

300

400

500

Efflu

ent C

a2+ c

onc.

(ppm

)

Inj. PV

0 5 10 15 20 25 30 354

6

8

10

12

14

pH

Ca2+ conc. pH

1st CW & WF

WF CW + Surf. & WF

2nd CW & WF

Final CW & WF

WF: Water floodCW: Conditioned waterSurf.: Surfactant

Fig. 23. Effluent Calcium concentration and pH during last single-phase flowexperiment.

0 5 10 15 20 25 30 35

10−10

10−8

10−6

10−4

10−2

100

102

Inj. PV

Por

tland

ite s

atur

atio

n ra

tio (Q

/K) Portlandite SR

Saturation line

Fig. 24. The status of portlandite saturation ratio of the collected samples duringlast single-phase flow experiment.

0 5 10 15 20 25 30 350

0.2

0.4

0.6

0.8

1

1.2

Inj. PV

Sur

fact

ant c

onc.

(wt%

)

Inlet Effluent

Fig. 25. Inlet and effluent surfactant concentration during last single-phase flowexperiment.


compared to the I-85b core or larger concentration of anhydrite.Additional data would be necessary to assess this. Additionally,the values of effluent pH after the shut-in event did not exceed10, which was possibly caused by the presence of more complexpH buffering mechanisms in this core with slow reaction rates.After the flooding process, we intended to conduct the second sin-gle-phase flow experiment, namely after the two-phase flowexperiment, but the rock sample was damaged severely (Fig. 10)with the major damage appearing where anhydrite previously ex-isted. We speculate that the dissolution of the thick anhydrite layerunder 500 psi confining pressure is responsible for the observedformation damage. However, this does not exclude the possibilityof the existence of an initial mechanical instability in the core.The SEM test was carried out on the inlet segment of the core tofind out the intensity of anhydrite dissolution. The SEM results(Fig. 11) show that the distribution of calcium is more similar tothe magnesium distribution rather than sulfate. Also, calciumabundance is more pronounced than sulfate’s. These evidenceshint that more dolomite remained in the inlet section comparedto the mostly dissolved anhydrite.

Fig. 26. The CT-scanning results of core I-85l (bright color represents anhydrite).

Table 3DC Synthetic reservoir brine.

Ion Na+ K+ Ca2+ Mg2+ HCO�3 Cl� SO2�4

pH TDS

Conc.(ppm)

1315 71 456 63 509 30 3400 7.95 6174

5 10 15 200

25

50

75

100

Rec

over

y fa

ctor

(%O

OIP

)

Inj. PV0 5 10 15 20

0

20

40

60

80

Pres

sure

dro

p (p

si)

Recovery factor Pressure drop

ASP & P

WF Post−WF

Fig. 27. Pressure drop and oil recovery data obtained from ASP flood in anhydrite-rich sandstone core (I-85l).


3.2. Single-phase flow experiments

3.2.1. Core I-85bThe results of the single-phase flow experiment on core I-85b

are plotted in Figs. 12 and 13. The pressure drop during the EDTAflood was lower than that of the NaOH flood, which was consistentwith the results obtained in two-phase flow experiments (Fig. 12).Additionally, the pH values after alkali floods were slightly higher(0.25 in pH units) than two-phase flow experimental results, likelydue to the absence of crude oil in this test. In two-phase flowexperiments, oil was responsible for lower effluent pH, due tothe saponification process. Like in the two-phase flow experiment,

again, strong pH buffering was observed (Fig. 12), but the concen-trations of calcium and sulfate ions were higher during first waterflooding step (Fig. 13). The latter indicates that oil lowers anhydritedissolution probably by limiting surface exposure through coating.Fig. 14 shows effluent water composition in two-phase flow exper-iments, before and after being exposed to crude oil at the primarystage of water flooding. The concentration of calcium and sulfateions were higher when crude oil was not introduced. It should bepointed out that core I-76 had been aged in the crude oil for a long-er period of time. As aforementioned, this core was damaged afterthe two-phase flow experiment and no further flooding experi-ment was performed on it.

3.3. Mitigation of anhydrite dissolution and portlandite (Ca(OH)2)precipitation during NaOH flood

The main driver for mitigation of anhydrite dissolution in chem-ical floods is avoidance of calcium precipitation by alkali, eitherportlandite or calcium carbonate, which reduces Ca2+ and drivesthe equilibrium reaction toward the products. This and other mul-tivalent cations affect surfactants phase-behavior as well asprompt precipitation of undesirable minerals (typically associatedwith ‘‘scales’’). Our approach to this problem was to convenientlylower the chemical forcing for dissolution. One potential avenueis to saturate the solution with one of the ions, in this case, sulfate,so that this imposes a limit in the chemical gradients leading todissolution. For convenience, we tested this strategy by adding so-dium sulfate to the solution, in contrast with the addition of chelat-ing agents. To this end, geochemical simulation was used to choosethe conditioning of the injection brine and determine appropriatecomposition. Then, this was followed by laboratory tests in coreflo-ods to verify predictions of the geochemical simulation. To addresspractical issues in chemical flooding for EOR purposes, we carriedout additional experiments to determine the impact of an adjustedwater chemistry on oil recovery. This in turn can be examinedthrough surfactant phase behavior and direct estimation of oilrecovery in coreflooding experiments.

3.3.1. Results of numerical simulationThe Reaction module of Geochemist’s Workbench (GWB [20])

was used as a mixing cell model to find a chemical agent to inhibitportlandite precipitation while NaOH is added. The results of these


conceptual simulations revealed that using a blend of NaOH andNa2SO4 with appropriate concentrations can mitigate anhydritedissolution and consequent portlandite formation. Fig. 15 demon-strates the required amounts of Na2SO4 for different weight frac-tions of NaOH at 48 �C. For this application, the concentration ofNaOH should be less than 0.5 wt.%, otherwise the amount ofNa2SO4 needed would be very high, which is impractical for fieldapplication and also might exceed the solubility limit of Na2SO4.On the other hand, it is not recommended to lower the concentra-tion of NaOH to less than 0.3 wt.% because the concentration ofalkali might not be effective enough to saponify the crude oil. Ingeneral, the main advantages of the proposed blend are as follow:it minimizes the concentration of Ca2+ while sustaining high pHcondition in the system and secondly, it minimizes the dissolutionof anhydrite. To compare the efficiency of this proposed blend withother candidates, a hypothetical coreflooding test was built andtested through separate numerical simulations. The flooding planwas first an injection of 8 PVs of 2000 ppm NaCl brine chased bya 2 PV injection of different chemical blends (conditioned waters)at 48 �C.

Chemical blends used in this part were as follow: (a) 0.4 wt.%NaOH, (b) 1 wt.% NaOH, (c) 11,000 ppm Na4EDTA.2H2O, (d)59,150 ppm Na2SO4, (e) 1 wt.% NaOH + 11,000 ppm Na4EDTA.2H2Oand (f) 0.4 wt.% NaOH + 59,150 ppm Na2SO4 solution. The concen-tration of NaCl in all of these blends was kept constant at 2000ppm. The simulation results are depicted in Figs. 16–18. The anhy-drite dissolution rate at the inlet face can be accelerated ormitigated during chemical flooding depending on the compositionof the injected fluid (Fig. 16). Among injected chemicals,59,150 ppm Na2SO4 and 0.4 wt.% NaOH + 59,150 ppm Na2SO4 solu-tions caused the minimum anhydrite dissolution. Conversely,1 wt.% NaOH + 11,000 ppm Na4EDTA.2H2O and 1 wt.% NaOH trig-gered the maximum anhydrite dissolution. Compared to water-flooding, the injection of 0.4 wt.% NaOH and 11,000 ppmNa4EDTA�2H2O increased anhydrite dissolution. The trends of thetotal and free calcium concentrations at effluent of different chem-ical floods (Fig. 17) reveal that the 59,150 ppm Na2SO4 and 0.4 wt.%NaOH + 59,150 ppm Na2SO4 floods yielded the lowest producedcalcium concentration, whereas, 11,000 ppm Na4EDTA.2H2O and1 wt.% NaOH + 11,000 ppm Na4EDTA.2H2O led to the maximumproduction of Ca2+ compared to other chemical treatments.Fig. 18 shows that in order to sustain high pH condition, 0.4 wt.%NaOH + 59,150 ppm Na2SO4 and 1 wt.% NaOH solutions are thebest candidates. In accordance to the aforementioned points,0.4 wt.% NaOH + 59,150 ppm Na2SO4 is the best candidate basedon the required objectives in alkaline-chemical floodingmechanisms.

3.3.2. Phase-behavior resultsIn this section, the effect of adding Na2SO4 as a salt on the

phase-behavior of oil-AS mixtures was investigated. Three sets ofbottle test experiments were carried out. All the phase-behaviortests were run at 1:1 oil to brine ratio, which is customary in thistype of tests. In the first set, the brines contained 1 wt.%NaOH + 1 wt.% of surfactant (0.75 wt.%PS13 + 0.25w_t.%PS-3B) anddifferent weight fractions of NaCl. The selected blend was previ-ously found in EOR designs for this oil, brine and rock combina-tions [21]. All the vials were kept at 48 �C for 1 week and shakengently every day. In the second set of experiments, the only changewas that NaCl was replaced by Na2SO4 as to keep the total salinity(in weight fraction) of both brines equal. In the third set, all theconditions of the second set were used, but the concentration of al-kali, which was changed from 1 wt.% to 0.4 wt.%.

The phase-behavior results are shown in Figs. 19–21. To aidinterpretation, given how dark the images are, the main consistentobservation is a dark-brown Type III microemulsion in a broad

range of salinity. This show that using Na2SO4 in the selectedchemical blend would preserve the formation of Type III micro-emulsion to allow ultralow IFT conditions to persist under similarconditions as those associated with the pure NaCl design. The par-ticular choice of surfactants for the crude oil studied indeed leadsto a broad optimal salinity range.

3.3.3. Single-phase flow experiment using the proposed conditionedwater (core I-107)

To evaluate the impact of the proposed conditioned water onanhydrite dissolution, a new single-phase flooding test was per-formed in a core from the same anhydrite-containing formation(core I-107). The anhydrite distribution along this core is depictedin Fig. 22. Unlike previous single-phase tests, in this experiment,1 wt.% NaOH component replaced with the blend of 0.4 wt.% NaOH+ 59,150 ppm Na2SO4. Moreover, EDTA agent was replaced withthe blend of 0.4 wt.% NaOH + 59,150 ppm Na2SO4 + 1 wt.% surfac-tant while keeping other flooding characteristics the same as be-fore. The latter was carried out to study the effect of theproposed method on the dynamic adsorption of the surfactantagent. At the conclusion of this test, in order to investigate the im-pact of other possible candidate of the proposed method that haslower concentration of NaOH and Na2SO4, 3 PVs of 0.3 wt.% NaOH+ 29,580 ppm Na2SO4 + 1,600 ppm NaCl was injected through thesame core and then followed by 2 PV injection of 2000 ppm NaClbrine at the same flow rate of 0.5 cc/min.

The results (Fig. 23) reveal that both proposed conditionedwaters ((0.4 wt.% NaOH + 59,150 ppm Na2SO4) and (0.3 wt.%NaOH + 29,580 ppm Na2SO4)) are able to sustain the calcium con-centration low enough (about 100 ppm or lower) and the pH highenough to favor the performance of chemical enhanced oil recov-ery mechanisms. As expected, throughout this flooding experimentthe system remained under-saturated with respect to the portlan-dite which is indeed very desirable (Fig. 24). Fig. 25 shows the inletand the effluent surfactant concentration during surfactant flood-ing. Despite the high concentration of dolomite and anhydrite inthis core, the retention of surfactant by rock is not very significant(0.11 mg of surfactant/gr of rock).

3.3.4. Examining the efficiency of an ASP blend using the proposedconditioned water (core I-85 l)

Based on phase behavior results, particularly the one with loweralkali concentration (Fig. 21), it appeared that for this surfactantblend and crude oil system, the concentration of Na2SO4 shouldbe less than 50,000 ppm to be in the range of optimum salinity.Thus it was decided to use (0.3 wt.% NaOH + 29,580 ppm Na2SO4)instead of (0.4 wt.% NaOH + 59,150 ppm Na2SO4) in the ASPformulation.

To begin the coreflooding procedures, the core (I-85 l) was firstcharacterized (Table 2 and Fig. 26). It was then vacuum saturatedfor 1 day and aged in the synthetic DC formation brine (Table 3)at 48�C and under 500 psi confining pressure for a week. To mea-sure rock permeability to connate brine, the injection flow rate wasvaried from 0.5–0.7 ml/min while recording the pressure dropalong the core. The core was flooded with DC oil at a rate of0.5 ml/min for 3 PVs. Effluent samples were collected using anautomated fraction collector to determine initial water and oil sat-urations within the core through material balance calculations.After aging a minimum of 10 days, cores were water flooded withinjection brine containing 1600 ppm NaCl for 10 PVs to establishresidual oil saturation. Before initiating the tertiary chemical injec-tion, permeability was measured at residual oil saturation. Thecores were then flooded with 1 PV of the ASP blend followed bya 1 PV polymer (P) slug consisting of the injection brine and1000 ppm Floppam 3330S. To complete the coreflood, a 5 PVwaterflood of injection brine was run. At the conclusion of the final

Fig. 28. Collected effluent samples showing the performance of chemical flooding.


waterflood, the permeability of the core was again measured. Pres-sure drop was measured and recorded for all flooding steps. Flowrates for waterflooding and chemical flooding were held constantat 0.5 ml/min. The chemical ASP blend contained: 1 wt.% surfactant(0.75% PS13-D and 0.25%PS3-B), 0.3 wt.% NaOH + 29,580 ppmNa2SO4, and 2,500 ppm Flopaam 3330S prepared in 1600 ppm NaClbrine.

The results of ASP flooding using the blend of NaOH and Na2SO4

(Figs. 27 and 28) show that this proposed method is very promisingto recover significant amount of residual oil without facing perme-ability impairment under the conditions of this test.

4. Discussion

Adding EDTA intensifies anhydrite dissolution, which in prac-tice increases the chance of formation damage. On the other hand,if anhydrite is not present in the rock assemblage, EDTA can, inprinciple, be used to sequester divalent cations at relatively highpH conditions [16]. However, if the concentration of Ca2+ ion inthe formation water is high, EDTA and polyvinyl sulfonate can beinjected first to bind free calcium ions and to enable the injectionof the alkaline agent. Polyvinyl sulfonate is recommended in con-junction with EDTA to reduce the amount of costly EDTA [16]. Ashas been studied before [22–24], increasing pressure ramps upanhydrite dissolution regardless of the values of temperature andsalinity, accordingly, anhydrite dissolution investigated in thisstudy might be more severe in formations at higher pressure (deepreservoirs).

As demonstrated in this study, using a mixture of NaOH andNa2SO4 with the engineered concentrations averts intense anhy-drite dissolution and portalandite formation, and keeps both pHand Ca2+ concentration in a desirable interval for alkaline-chemicalflooding. It should be pointed out that using Na2SO4 in chemicalflooding might cause issues in field applications and thereforeprecautions should be taken. If the formation water containssignificant amount of Ba2+ or Sr2+, Na2SO4 should not be used forchemical treatment due to the possible formation of harmful sul-fate scales. Further, if the calcium concentration of formation brineis high, the injection of Na2SO4 may cause precipitation of gypsumand hence it should not be applied.

The present study was performed under dynamic conditions inlaboratory with relatively short reaction time, so, anhydrite(CaSO4) dissolution and subsequent secondary mineral precipita-tions might be more extensive in application in the field due tothe much longer reaction times.

5. Closing remarks

1. Crude oil acts as a barrier that limits the reactivity of anhydriteagainst injected alkali. This effect depends on the rock agingtime in crude oil. Despite the decreased reactivity, anhdyritedissolution is still very pronounced.

2. EDTA as a ligand (alone or accompanied with NaOH) increasesanhydrite dissolution rate and does not contribute to reducingfree Ca2+ concentration significantly. Using EDTA (alone oraccompanied with NaOH) during alkali flooding of anhydrite-containing rock might cause formation damage.

3. A blend of NaOH and Na2SO4 in appropriate amounts helps toalleviate anhydrite dissolution. This blend provides more desir-able conditions for chemical flooding including higher pH andlow calcium concentration when compared to other candidatetreatments.

Acknowledgements

The authors would like to thank the Enhanced Oil RecoveryInstitute (EORI) and the School of Energy Resources at the Univer-sity of Wyoming through the Anadarko Fellowship on EnergyExcellence Research for financial support. Also the authors wouldlike to thank Dr. Piri’s research group at the University of Wyomingfor providing some of the CT-scanning images.

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mitigation of anhydrite dissolution in alkaline floods through injection of conditioned water

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