Experimental Study of Miscible Thickened Natural Gas Injection for

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Experimental Study of Miscible Thickened Natural Gas Injection for Enhanced Oil Recovery Nasser Mohammed Al Hinai, Ali Saeedi, Colin D. Wood, Raul Valdez, and Lionel Esteban Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00314 • Publication Date (Web): 17 Apr 2017 Downloaded from http://pubs.acs.org on April 18, 2017

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Experimental Study of Miscible Thickened Natural

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Gas Injection for Enhanced Oil Recovery

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Nasser M. Al Hinai, §† * A. Saeedi, § Colin D. Wood, ψ R. Valdez, ɸ Lionel Esteban ψ

5

§

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W.A. 6151

7

Ψ

Commonwealth Scientific and Industrial Rese arch Organization, Australia, Perth, W.A. 6151

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ɸ

Kinder Morgan CO2, 1001 Louisiana St, Suite 1000, Houston, TX 77002, U.S.A.

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†

Petroleum Development Oman L.L.C., P. O. Box 81, Code 100, Muscat, Sultanate of Oman

Department of Petroleum Engineering, Curtin University, GPO Box U1987, Australia, Perth,

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Keywords: Associated Gas, Miscible Gas Injection, Thickened Gas, Parallel gravimetric

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extraction, Viscosity

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Abstract

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Hydrocarbon-miscible gas flooding typically involves injection of an Associated Gas (AG)

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mixture containing mainly methane (CH4) enriched with light hydrocarbon fractions and

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possibly acid gases. The AG mixture has been recognised as an excellent candidate for Miscible

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Gas Injection (MGI). However, in general, the viscosity of the AG at reservoir conditions is

2

significantly lower than that of crude oil leading to an unfavourable mobility ratio and low

3

volumetric sweep efficiency during flooding. This study assesses the suitability of a library of

4

commercially available polymers to thicken AG as a means of mobility control. The focus of the

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study is on the Field A located in the Harweel cluster in southern Oman. First, soluble polymeric

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thickeners for an AG mixture (CH4 60%, C2H6 9%, C3H8 6% and CO2 25%) were identified

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using a parallel gravimetric extraction technique combined with cloud point measurements.

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Then, the viscosity of the identified soluble polymeric candidates in AG mixture was measured

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in a capillary viscometer at reservoir conditions. Three polymers were found to be completely or

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partially soluble in the AG mixture at 377 °K and 55 MPa including poly (1-decene) (P-1-D),

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poly (methyl hydro siloxane) (PMHS) and poly (dimethyl siloxane) (PDMS). P-1-D found to be

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an effective thickener in AG mixture under conditions relevant to Field A, i.e. high temperatures

13

and pressures. The polymer is soluble in the concentration range of 1.5-9 wt%. The viscosity of

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the P-1-D- thickened AG mixture increased by 2.2-7.4 times greater than AG mixture viscosity

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at 358-377 °K. Furthermore, reservoir condition core flooding experiments were performed to

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examine the effectiveness of P-1-D-thickened AG gas mixture flooding to enhance oil recovery.

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The thickened-AG mixture flooding resulted in delayed gas breakthrough and subsequently 10-

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12% additional oil recovery.

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1

INTRODUCTION

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Enhanced Oil Recovery (EOR) is an important field development step when oil in a

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reservoir can no longer be produced by natural drive mechanisms of the reservoir (primary

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recovery) or by water or immiscible gas injection (secondary or improved recovery).1-4 The aim

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of EOR techniques is to stimulate oil flow by overcoming the physical, chemical and/or geologic


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factors that inhibit the production of the remaining oil in the reservoir.5 Hydrocarbon-miscible

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gas injection (HC-MGI) is considered as a tertiary recovery process that can increase the oil

3

recovery by achieving miscibility between the injected gas and reservoir oil. The resulting gas/oil

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mixture can then be displaced more easily through the reservoir rock and swept to producing

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wells resulting in improved recovery.6 As with other EOR techniques, HC-MGI can be

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challenging and expensive.7 For instance, treating and handling the gas as part of a gas recycling

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scheme can be expensive due to the separation, dehydration & compression costs; and further

8

impacted by concentration and quantities of gas to be handled.

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mobility ratio (less viscous gas displacing more viscous oil) is a major subsurface factor that can

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In addition, unfavourable

reduce the sweep efficiency when applying this EOR technique.

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In the Middle East, many MGI projects are currently being undertaken in carbonate

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reservoirs in which the injected AG often contains acid gases.7-9 Field A, located in the Harweel

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cluster in southern Oman, has been recognised as a viable MGI candidate. The MGI in this Field

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has already commenced where the source of the injection gas is the field’s AG.10 The AG

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mixture is re-injected into the reservoir at high pressure (up to 55MPa) where it becomes

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miscible with the oil during the displacement at the relatively high reservoir temperature of up to

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377 °K. The AG in Field A contains CH4 enriched with light and heavy hydrocarbon fractions

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found in natural gas and a significant amount of carbon dioxide at 10 – 25 mol%.10 The reservoir

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contains a light crude oil with a gravity of 42° API and a viscosity of 0.23 cP at reservoir

20

conditions. With miscible AG injection, it is estimated that up to 47% of the original oil in place

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(OOIP) can be recovered.11 However, even though the Field A oil is light and exhibits low

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viscosity, the viscosity and density contrast between the injection gas and reservoir oil presents

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technical challenges for the MGI process.


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The major challenges faced by MGI in Field A include gravity override caused by the

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density difference between the injected gas and the reservoir fluids and the unfavourable

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mobility ratio caused by the low in-situ viscosity of the injected gas (0.01 to 0.03 cP) compared

4

with that of the oil (0.23 cP). Gravity override & unfavourable mobility can result in early

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breakthrough (BT) of the injection gas and poor volumetric sweep, reducing the overall

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efficiency of the MGI development and preventing it from realising its full potential12. In fact,

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early gas breakthrough has already been experienced in some production wells in Field A. These

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challenges can be overcome by the implementation of several approaches that have been

9

proposed in the literature, mainly for CO2 flooding. The main objective of such approaches

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would be to effectively control the gas mobility and as a result increase the sweep efficiency of

11

the gas flooding.13 The most commonly used or proposed methods include Water Alternating

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Gas flooding (WAG),14,

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increasing the gas viscosity by adding polymers as thickening agents to the gas.13, 20 During the

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WAG process, the gas mobility is suppressed by alternating water and gas injection using a

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single to five cycles.21, 22 In field applications, the CO2-WAG flooding has proven to be effective

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resulting in incremental oil recovery of 5% - 10% of the OOIP.22 However, very often, a large

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amount of residual oil is still left behind after the completion of WAG injection because of

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operational difficulties and challenges associated with this method such as gravity segregation

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and water blocking due to the excessive water injected into the oil reservoir.4, 14, 21, 23 Therefore,

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the WAG strategy may not be the best choice for Field A where water saturation is already very

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low and facilities are not designed to inject or handle water.

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entrainment of the gas into a foam during foam flooding,16-19 and

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The application of foaming agents has also been studied as a way of conformance control in

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miscible flooding.17 However, applying foams for mobility control has shown to be technically


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and economically challenging because of the difficulties associated with controlling its

2

propagation over large distances in the reservoir and that large volumes of a foam are required.24

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In addition, the majority of the foaming agents are of no use in high salinity reservoirs due to the

4

inability of the surfactants to reduce the interfacial tension (IFT) to the required ultra-low

5

values.24

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To overcome the above limitations associated with WAG and foam flooding, another

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technique has been introduced which brings together the advantages of both chemical and

8

miscible gas EOR methods. Introduced for the first time about 45 years ago, the application of

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thickener agents, such as small/high molecular weight polymers, has been proposed to directly

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thicken the injection gas used during gas flooding.20 By increasing the injected gas viscosity, the

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gas mobility can be suppressed. Hence, the severity of the viscous fingering (i.e. instability in the

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displacement front) and the chance of developing pre-mature breakthrough can be reduced and

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the microscopic displacement efficiency would also be improved. Among the techniques used to

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improve the mobility ratio of a gas flood, a direct thickening of the AG mixture by using additive

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polymers may be the best method to increase sweep efficiency in Field A as the field has a high

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salinity formation water and low water saturation in the reservoir. The AG in Field A contains 25

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mol % of CO2. The presence of CO2 is considered as a positive factor as it may make the

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identification of suitable soluble polymers in the AG mixture easier because a number of studies

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have focused on polymer and small molecule solubility in CO2.25-27 Despite this, there are

20

significant challenges in identifying soluble polymers because most polymers are insoluble in

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compressed fluids which have limited their widespread application.

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To date, most of the research works regarding gas thickening agents have almost exclusively

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focused on polymers for CO2 gas because it is widely used as the displacing fluids in EOR


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projects in the United States, Canada and elsewhere.28 In addition, CO2 is a slightly more

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powerful solvent than alkane components ( CH4 and C2H6 ) to dissolve polymers due to the

3

quadrupole interactions relative to polymer-CO2 segment.25, 29 It is important to note that CO2 is

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still considered a poor solvent when compared to more conventional organic solvents. However,

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some materials (hydroxyaluminum disoaps, trisurea) show greater solubility in liquid propane

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and butane than do in pure CO2.26, 30 There have been few attempts at identifying polymers which

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could thicken pure light hydrocarbon gases. In the late 1960s, initial attempts were made to

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thicken light alkanes as evident from several registered patents.31-33 Henderson et al.33 invented

9

some thickener polymers for buffer hydrocarbon. The identified polymers included poly methyl

10

laurylate, polybutadiene and poly alkyl styrene. These polymers at a concentration of 0.25wt%

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are capable of increasing the viscosity of light hydrocarbon gases from 0.01 cP to 0.1 cP.

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Additional patents were filed later , Dauben et al.31also achieved a 2-3 fold viscosity

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enhancement for condensate mixtures contains 75% propane and 25 % heptane-rich at 0.25wt%

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of poly-isobutylene. However, none of the patented work indicated the method(s) used to

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measure the viscosity enhancements of the solutions examined.34 Heller et al.35successfully

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synthesized various α-olefin polymers (n-decene, n-pentene and n-hexene) which could be

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dissolved in CO2 and LPG (n-butane and n-propane). Concentrations of 1-2.2wt% of these

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polymers in liquid n-butane resulted in 5-10 fold viscosity enhancements. Although, these

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polymers were found to be slightly soluble in CO2, none could effectively increase the CO2

20

viscosity.

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In an attempt to identify polymers with small molecular chains as thickener candidates for

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light hydrocarbon gases and CO2, Enick et al.30 examined a series of hydroxylaluminium disoaps

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that could increase the viscosity of propane, pentane and hexane at diluted concentrations of


6

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1wt% without a co-solvent being required. Such finding proved that such small molecular chain

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polymers also may be capable of serving as thickener agents for miscible gas flooding. Dhuwe

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et.al and Lee et al.34, 36 also reported that the solubility of silicone polymers in compressed liquid

4

propane and butane is quite high for low molecular weight of PDMS at low temperature.

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However once the temperature increases, it needs a higher pressure to get the polymer dissolved

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in the solution due to large difference of free volume between the solvent and polymer at high

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temperature, leading to separation. PDMS in ethane required a higher pressure to dissolve

8

because the difference between the solubility parameters value (14.9-15.5 MPa. ) of PDMS and

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ethane (11.7 MPa.) is more than 2.05 MPa. .36 Therefore, PDMS was an ineffective thickener

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in ethane and more effective in thickening propane and butane at 2 wt% and 62.05 MPa at 25 ℃.

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Doherty et al.26 also found that branched benzene trisurea solubility increases the propane

12

viscosity between 1.2 to 1.5 fold at temperatures from 25 to 80 ℃ and the concentration of 1.5

13

wt%.

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Recently, Dhuwe et al.37reported to have found small associative molecular thickeners for

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ethane, propane, and butane at the temperature range of 298-373 °K and pressures of up to 62

16

MPa. They found Tributyltin fluoride (TBTF) to dissolve in all above three gases without any

17

heating/cooling cycle requirement. At 298 °K the TBTF was found to enhance the viscosity of

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all three light components by 70-100 fold at 1wt% concentration. However, as the temperature

19

increased, the thickening ability of the polymer substantially decreased due to degradation.

20

Dhuwe et al.37 found hydroxyaluminium di-2ethylhexanoate (HAD2EH) to be soluble in liquid

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propane and butane, but insoluble in liquid ethane. Furthermore, this small molecule was shown

22

to be a good viscosifier for butane, but not as effective for propane. Also, addition of phosphate


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ester and a crosslinker mixture to Natural Gas liquid,9 improved the viscosity just slightly

2

compared to those caused by TBTF and HAD2EH.37

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In the Dhuwe et al. study, the viscosity was measured using a falling ball viscometer. Another

4

study evaluated the solubility and viscosity enhancing property of ultra-high molecular weight

5

drag reducing agent (DRA) poly-α-olefin, and high molecular weight poly (dimethyl siloxane)

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(PDMS, Mw 980000) in NGL. At a concentration of 0.5wt%, DRA polymer was found to be

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soluble in butane and propane above the vapour pressure for the temperature range of 298-333

8

°K, and soluble in ethane above 20 MPa.36 Above 3.5 MPa, DRA polymer proved to be a better

9

thickener for butane and propane, and an ineffective thickener for ethane for pressures of up to

10

62 MPa due to its low solubility. This means that an NGL with high concentration of ethane

11

requires higher pressure to dissolve the DRA polymer. A high molecular weight PDMS was

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found to be an ineffective thickener in NGL application for EOR.36

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None of the above materials tested by other researchers have been used as a direct thickener

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specifically for an AG mixture containing primarily CH4, NGL components and CO2. In fact, the

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available data about the direct thickening of an AG mixture are very scarce in the literature.

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Therefore, in the case of Field A, none of the materials tested to date can be used as a thickener

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for the field’s AG mixture which is being used for miscible gas flooding. There are similar fields

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around the globe containing a significant fraction of CO2 (15%- 80%)38-40 which makes this

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research more relevant to other field scenarios.

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This study is to assess the solubility of a library of low/high molecular weight polymers in an

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AG mixture enriched with CO2 and then examine their effectiveness to control the gas mobility

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in miscible gas EOR. In order to achieve this objective, firstly, a library of polymers was chosen

23

to be tested for their solubility. The polymers were chosen based on the existing available data in


8

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the literature covering the solubility of commercially available polymers in CO2 and light

2

hydrocarbons. Considering the composition of Field A AG, the solubility of a total of 32

3

polymers in a gas mixture containing 60% methane, 6% ethane, 9% propane and 25% CO2 was

4

determined using a parallel gravimetric extraction method proposed by Bray et al. 41. The parallel

5

gravimetric extraction is considered as a high throughput and effective technique for preliminary

6

screening of polymers with regards to their solubility in a gas mixture. After selecting the

7

polymers with the highest weight extracted during the high throughput solubility experiments, a

8

series of cloud point pressure measurements were performed at different temperatures. The cloud

9

point pressures were measured using different enriched gas mixtures using a high pressure

10

windowed cell. These experiments were to check the compatibility of the polymers with the

11

range of pressures applicable to Field A. In the next stage of the work, the polymer that has a

12

lower cloud point pressure in the AG mixture at Field A reservoir conditions was examined for

13

possible viscosity enhancement in the AG mixture, this was accomplished by using a

14

manufactured capillary viscometer at different temperatures and different concentrations. Lastly,

15

the potential of the polymer thickener as an EOR agent was evaluated using reservoir condition

16

core flooding experiments. The core-flood experiments would reveal if a thickener can improve

17

the sweep efficiency of the gas flood for Field A at lab scale. For these experiments

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representative carbonate core plugs and crude oil from the Field A were used.

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2. EXPERIMENTAL METHODOLOGY

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2.1. Materials

21

A complete list of the polymers chosen initially to be investigated in this study is provided in

22

Table 1. The polymers were sourced from a number of international commercial suppliers (i.e.

23

Jiangsu Yinyang Gumbase Material, Fluka AG, BASF- ICIS, DOW Corning and Sigma


9

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Aldrich). The gas mixture chosen to represent the average of major components of injected gas

2

in the field included three hydrocarbon gas mixtures (CH4 60%, C2H6 9%, C3H8 6% and CO2

3

25%; CH4 75%, C2H6 9%, C3H8 6% and CO2 10% and CH4 40%, C2H6 7%, C3H8 3% and CO2

4

50%) purchase from BOC gas- Australia. The CMG WinProp Module (Version 2011) was used

5

to estimate the density of the HC gas mixtures as needed at different pressure and temperature

6

values using Robinson equation of state (EOS).

7

The light crude oil was collected at the wellhead from the Field A, Oman. The density and

8

viscosity of the dead crude oil were 0.81 . and 0.24 cP (377 °K and 55 MPa), respectively.

9

Since this was a dead oil sample, most of the light fractions had been flashed out of the oil and,

10

therefore, there was no light hydrocarbon under C5 in its composition (Table 2). The oil

11

composition was obtained using Gas Chromatography with a Flame Ionization Detector (GC-

12

FID). Considering the available Field A brine composition, a synthetic brine was prepared in the

13

laboratory using analytical grade salts and with a total dissolved solids of 275 g. L (NaCl 220

14

g. L and KCl 55 g. L ). For the core flooding experiments, a number of relatively tight

15

carbonate core plugs drilled from the Field A wells at reservoir depths of 4995 to 5000 meters

16

were used.

17

Table 1. The library of polymers used in parallel gravimetric extraction experiments. Sample Number

Polymer, Oligomer Small Molecule Name

and Molecular Weight (g/mol)

Degree of Supplier Polymerization

1

Poly(vinyl Acetate )

250,000

2903.9

Jiangsu Yinyang Gumbase Material

2


150,000

1742.3


3


80,000

929.2



10

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55,000

639.8


5


16,000

185.8


6

Poly ( Vinyl Alcohol) -40%

72,000

1636.3

Fluka AG

7


9,000

204.5

Fluka AG

8


96,000

2181.8

Fluka AG

9

Poly(Ethylene Glycol)

8,000

21

BASF- ICIS

10

Poly(Dimethyl Siloxane), 170,000 PDMS SILANOL TERMI

-

DOW Corning

11

Poly(Vinyl Pyrrolidine)

10,000

4000

BASF- ICIS

12

Poly(4-Vinyl Pyridine)

60,000

570.6

BASF- ICIS

13

Poly(4-vinyl Pyridine)

50,000

475.5

BASF- ICIS

14

Poly(Methyl Methacrylate)

15,000

148.3

Sigma Aldrich

15

Hydroxyethyl-Cellulose

140,000

-

Sigma Aldrich

16

Poly (Ethylene Acetate)

481.8

Sigma Aldrich

17

Cellulose Acetate Butyrate

70,000

-

Sigma Aldrich

18

Poly(Vinyl Methyl Ether)

60,500

1041.6

Sigma Aldrich

19

poly (Vinyl Ethyl Ether)

3,800

52.7

Sigma Aldrich

20

Poly(Dimethyl Siloxane)

97,300

-

Sigma Aldrich

21

Poly(Butyl Methacrylate)

337,000

2369.9

Sigma Aldrich

22

Poly (Ethylene Succinate)

10,000

69.3

Sigma Aldrich

23

Poly(Isobutylene)

200,000

3564.6

Sigma Aldrich

24

poly (Butadiene)

3,000

55.4

Sigma Aldrich

25

Poly (Propylene mono Butyl Ether

Glycol) 1000

11.1

Sigma Aldrich

26

Poly (Propylene Carbonate)

50,000

489.7

Sigma Aldrich

27

Methyl-β-Cyclodextrin

1,310

1

Sigma Aldrich

Vinyl 55,000


11

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Poly(Methyl Hydro siloxane) 3,200

-

Sigma Aldrich

29

Poly(Propylene Glycol)

2,700

35.4

Sigma Aldrich

30

1,4-di-tert-Butylbezene

190

1

Sigma Aldrich

31

Poly(Vinyl Methyl Ketone)

500,000

7133.6

Sigma Aldrich

32

Poly (1-Decene)

900

6.4

Sigma Aldrich

1 2 3

Table 2. Compositional Analysis results of Field A dead oil in mole percentage Component

Mole %

Component-cnt Mole %

H2

0

C16

4.15

H2S

0

C17

3.85

CO2

0

C18

3.77

N2

0

C19

3.97

C1

0

C20

3.27

C2

0

C21

2.99

C3

0

C22

2.87

iC4

0

C23

2.67

nC4

0

C24

2.47

C5

0

C25

2.19

iC5

0.01

C26

2.1

nC5

0.02

C27

1.99

C6

0.33

C28

1.85

C7

1.54

C29

1.85

C8

3.71

C30

1.77

C9

4.84

C31

1.64

C10

5.54

C32

1.43


12

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C11

5.15

C33

1.35

C12

4.72

C34

1.26

C13

5.08

C35

1.2

C14

4.63

C36+

10.93

C15

4.86

Total

100

2.2 Experimental setup and Procedure 2.2.1 Polymer solubility measurements

4

2.2.1.1 High throughput Gravimetric Extraction (HTGE)

5

In the literature, the HTGE screening method has been described as a rapid method to use

6

when testing a large library of polymers for their solubility in gases and supercritical solvents

7

(SCF). Figure 1 shows the schematic diagram of the gravimetric extraction experiment used in

8

this research. The polymer extraction vessel is designed and built to hold 40 polymer samples at

9

a time. To test every batch of polymers, firstly, an accurate weight balance was used to weigh the

10

polymer samples. The polymer samples were weighed into open-ended Borosilicate glass tubes

11

with a length of 60 mm and an ID of 6.6 mm. A piece of quartz frit was placed into the bottom

12

opening of every tube to retain the sample. The quartz frit would let the gas mixture into the tube

13

from bottom during the extraction experiment but would prevent the polymer sample from being

14

drained from the tube. The top opening of every tube was then secured with a piece of tissue

15

paper (KIMTECH science). The tissue would prevent any possible overflow of the polymer

16

sample but would not prevent the gas mixture from freely flowing through the glass tube while

17

extracting the polymer sample (if soluble). The tubes were secured in between specially designed

18

slotted stainless steel disks before being placed inside the extractor shell (Figure 1). An AG

19

mixture was introduced into the extraction vessel and pressurised to 55 MPa at constant flow rate

20

(200 cc/min) using a gas compressor (Haskel, AGT-30/75). The gas was then flowed through the


13

Energy & Fuels

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Page 14 of 47

1

vessel under in-situ pressure and temperature for two hours at constant flow rate 80 cc/min. A

2

dome-loaded back pressure regulator (BPR) connected to a syringe pump was used to control the

3

gas pressure inside the vessel during the experiment. While the effluent gas from the extractor

4

was vented into a fume cupboard, a water trap was used to catch the polymer material dropping

5

out as the gas flashed to atmospheric pressure. After a predetermined period of the time, the gas

6

injection was stopped and gas inside the extractor was slowly vented at 0.6 MPa/min, controlled

7

by regulating pilot pressure applied to the BPR. Upon reaching atmospheric pressure, the glass

8

tubes were carefully removed and individually reweighed to determine any weight loss that they

9

may have endured. Every batch of polymers were tested twice at the same conditions. By

10

comparing the results of every two replicate experiments, the weight loss results were found to

11

be reproducible within 2 4% of the extracted weight. The gas mixture used in the extraction

12

experiments contained 60% methane, 9% ethane, 6% propane and 25% CO2.

13 14

Figure 1. Schematic diagram of gravimetric extraction equipment used for rapid measurement of

15

polymers solubility in AG mixture.


14

Page 15 of 47

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Energy & Fuels

1

2.2.1.2 Cloud point curve measurements

2

The cloud point pressure curves were determined using a standard technique set out in the

3

literature involving isothermal compression and then slow decompression of binary mixtures of

4

known compositions.42 Cloud point pressure measurements were carried out for the three

5

polymers that indicate a high level of extraction in the HTGE experiment to confirm its solubility

6

in the AG mixture. Cloud point pressures were determined at a temperature range of 298 °K-377

7

°K for PDMS and PMHS (both at 1.5wt. %) in AG mixture. For P-1-D, the cloud point pressures

8

were measured at the temperature range of 358 °K-377 °K and at different P-1-D concentrations

9

(1.5-9 wt. %).

10 11

Figure 2. Schematic diagram of experimental setup used for cloud point pressure measurements.

12

Prior to each cloud point pressure measurement for a polymer with known solubility

13

(determined by HTGE method), the windowed cell (Figure 2) was cleaned with acetone and

14

toluene sequentially. In each test run, the entire high pressure cell was thoroughly cleaned with

15

acetone and then with toluene. The combination of solvents would remove the polymers residues


15

Energy & Fuels

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Page 16 of 47

1

from the cell. The cell is cleaned at a temperature less than 323 °K. Then, it was placed under

2

vacuum for a few hours to dry. For every polymer, depending on its solubility in the AG mixture,

3

a small amount of it was accurately weighed and placed on a clean thin glass plate. The weight

4

of the polymer was needed to place the required amount of it on the glass plate and also be able

5

to calculate the exact composition of the polymer/AG mixture (in wt%) during the experiment

6

knowing the volume of the high pressure windowed cell (i.e. 20 cm ). Then the glass plate was

7

transferred to the view cell and placed horizontally on a small stand in the cell. The cell was

8

closed, sealed and displaced slowly with low pressure AG mixture to purge any air from the

9

system. Then the temperature was raised to the reservoir in-situ value. The cell pressure was

10

increased by introducing the AG mixture slowly using a syringe pump with increments of each

11

0.4 MPa until a single transparent phase of polymer/AG solution was achieved. This process was

12

done under no stirring for the solution and monitored through the see through windows of the

13

cell and using the instrument’s camera. At this stage, the polymer had completely dissolved in

14

the AG solution. Then the cloud point pressure of the mixture at the set temperature was

15

determined by slowly lowering the pressure by increments of each 0.4 MPa until the AG solution

16

became cloudy. The pressure at which it was no longer possible to see the back of the cell

17

through the polymer/gas solution (90% reduction in transmitted light intensity) was recorded as

18

the cloud point pressure. For any given weight percent of every polymer, this process was

19

repeated three times. The results were found to be reproducible within ∓ 0.5 MP.


16

Page 17 of 47

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1 2

Figure 3. Schematic of Capillary Viscometer used for viscosity measurements (55 MPa and 377

3

°K).

4

2.2.2 Viscosity Measurements

5

The viscosity of the AG mixture and polymer-thickened AG were measured in a capillary

6

viscometer (CVL-1000, Core Laboratories Inc.) (Figure 3). It is specifically designed to measure

7

the viscosity of single phase fluids at high pressure and high temperature within the range of 0.01

8

cP to 10,000 cP. It operates based on the Hagen-Poiseuille law, measuring the exerted pressure

9

drop across a capillary tube while flowing a fluid through the tube at a predetermined flowrate

10

(0.01 ml/min to 1.5 ml/min). A principle of the Poiseuille equation is employed in this

11

viscometer to measure the viscosity of the single-phase AG mixture μ or thickened AG

12

solution μ (cP):


17

Energy & Fuels

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("#$$ )& ∆(

μ =

1

) * +

∆(

Page 18 of 47

(Eq.1)

2

μ = K

3

Where, Q (m /s)is the injection rate of thickened AG solution through the capillary tube, ∆P

4

(bar) is the measured pressure drop across the capillary tube, r011 (mm) and L (mm) are the

5

effective radius and the length of capillary tubing. K is a factor that depends only on the

6

parameters of the tubing: K=

7

(Eq.2)

*

("#$$ )& ) +

(Eq.3)

8

The K factor values for the capillary tubing mounted in the viscometer (5 m length and 0.18

9

mm internal diameter) was calculated from determined linear slopes (∆P/Q) at two temperatures

10

298.15 °K and 377.15 °K and four different injection rates of (0.05, 0.08 , 0.1 and 0.2 )

11

cm . min using a known viscosity of water at temperature and pressure . The K values found

12

from the calibration are equal 0.036 at 298.15 °K and 0.033 at 377.15 °K. Then, Falcon software

13

estimates the K values for measuring the fluid viscosity over temperatures ranges of 358.15 K to

14

377.15 to be equal 0.033.

15

Due to the small ID of the coiled capillary tube (0.18 mm) in the viscometer, there was a

16

concern that at the conclusion of every measurement, any leftover polymer inside the tube could

17

not be completely cleaned impacting the next measurement with the next AG/polymer solution.

18

Therefore, prior to re measuring the viscosity of every solution, the coiled capillary tubing was

19

replaced with a new one and the instrument was recalibrated. For every experiment, the

20

instrument was heated to the desired temperature and then vacuumed before being filled and

21

pressurised with the polymer thickened AG or the AG mixture on its own. After attaining

22

stability in the viscometer, the solution was passed through the capillary tube at different


18

Page 19 of 47

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1

injection rates. The flowrates were kept low enough to have laminar flow (Reynolds number less

2

than 2000) in every viscosity measurement. Using the viscometer’s software, a range of suitable

3

flowrates could be predicted. Such a range was found to be 0.1 to 0.3 cm . min for the

4

polymer/AG solutions and 0.05 to 0.1 cm . min for the AG mixture. The viscosity of every

5

solution was measured at least three times to ensure the reproducibility of the results.

6

2.2.3 Core Flooding Experiments

7

A schematic diagram of the core flooding setup used for the polymer-thickened AG and AG

8

mixture flooding is shown in Figure 4. The apparatus consisted of four modules: a core holder,

9

injection system, heating system and production system. The core holder was of Core

10

Laboratories’ HCH Series, Biaxial type. As can be seen from Figure 4, the injection system

11

consisted of four one-litre fluid accumulators, one for each of the injection fluids. The syringe

12

pumps were all of pulsation free, positive displacement type (Vinci Technology) providing

13

constant pressure or constant injection flowrate with high precision. The fluid accumulators and

14

the core-holder were heated to the desired temperature using heating jackets (SRH Etched foil,

15

Watlow,

16

injection/production fluids were heated using suitable heating tapes (Stretch-To-Length, Watlow,

17

USA). The temperature was also regulated during the experiments using a digital temperature

18

controller (Standard-89000-00, Digi-Sense, USA). On the production side, the pore pressure was

19

regulated using a dome-loaded back pressure regulator whose pilot pressure was provided by a

20

syringe pump. Tall-form accurately graduated cylinders were also used to collect and measure

21

the produced fluid at atmospheric conditions. In addition to analog pressure gauges installed at

22

various spots to monitor the pressure within various components of the core-flood system, two

23

digital pressure transducers (KELLER, K-107) were installed at the inlet and outlet of the core-

USA)

and

the

flow-lines

and

other

fittings/connections

carrying

the


19

Energy & Fuels

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Page 20 of 47

1

holder to monitor and record the differential pressure across the core plug with an accuracy

2

of 1 psi.

3

For every experiment a composite rock sample was constructed using two reservoir core plugs

4

from Field A. Each composite core was about 14 cm long and 3.8 cm in diameter. The core-

5

plugs were initially cut in synthetic formation brine and then cleaned using toluene and methanol

6

in a temperature controlled Dean- Stark extractor. Subsequently, they were dried in an oven at

7

358 °K for about 24 h. Prior to being flooded, the porosity and gas permeability of each plug was

8

measured using an automatic porosi-permeameter (AP-608 instrument, Coretest Systems Inc.).

9

The composite sample was then wrapped in a combination sleeve made up of FEP heat shrink

10

and Viton rubber and placed inside a horizontal core-holder. After applying the next effective

11

pressure of 6.82 MPa as the overburden pressure, the sample was vacuumed for 24 hours. Then,

12

the overburden pressure, temperature and pore pressure were raised gradually to their respective

13

in-situ values. At all stages, the overburden pressure was maintained 6.82 MPa higher than pore

14

pressure reaching a final value of 62MPa, eventually.

15

After reaching the full in-situ pore pressure, to ensure that the sample was completely saturated

16

with the formation brine, the sample was subjected to brine injection at a constant flow rate of

17

0.2 cm . min for two days. At the conclusion of the saturation process, the absolute

18

permeability for the composite core was determined at three different flow rates (0.2, 0.4 and

19

0.8cm . min ). The brine saturated core plugs were then exposed to the reservoir dead oil

20

which was injected at a rate of 0.3 cm . min for three to four days until reaching steady state

21

conditions corresponding to irreducible water saturation. During this time, the volumes of the

22

produced oil and brine were recorded. This preparation process was repeated at every test after

23

the composite core plugs where cleaned from the previous test. After the irreducible water


20

Page 21 of 47

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Energy & Fuels

1

saturation was achieved in each test, the AG mixture and/or thickened AG solution were injected

2

at a constant injection rate of 0.4cm . min in all three flooding tests.

3

For the first test, only the P-1-D-thickened AG solution was employed as a secondary oil

4

recovery. This P-1-D-thickened AG solution was injected at a constant injection rate until a total

5

of 9 PV (Pore Volume) of thickened AG solution was injected and no more oil was produced.

6

After successfully completing the first test, the core was thoroughly cleaned and prepared for the

7

second test. In this test both the AG mixture and the P-1-D -thickened AG solution (P 1-D, 5 wt

8

%) were introduced into the core. At first the AG mixture was injected at a rate of 0.4

9

cm . min until there was no more oil produced from the composite core plugs which was

10

roughly 3.6 PV, The subsequent P-1-D-thickened AG solution was then introduced into the core

11

to aid in the production of the remaining oil in the core plugs.

12

The third test was mainly focused around the breakthrough of the AG mixture, in this

13

particular test the core plugs were flooded with the AG mixture at the same injection rate until

14

breakthrough is detected. As soon as breakthrough was observed, the P-1-D thickened AG

15

solution was commenced to produce the residual oil and the solution injection was continued

16

until a total of 9 PV was injected.

17

In each test, the cumulative produced oil volume inside the graduated cylinder was recorded

18

and the gas was released into the atmosphere through the fume cupboard (Johndec, M 1.5). At

19

the end of each test, an oil recovery factor versus injected gas/polymer pore volume plot was

20

generated from the production and injection data. It should also be mentioned that, there was no

21

brine production during all three tests.


21

Energy & Fuels

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Page 22 of 47

1 2 3

Figure 4. Schematic diagram of the core-flood setup

4

3. RESULTS AND DISSCUSIONS

5

3.1 Polymers Solubility in the AG Mixture

6

In general, solubility of polymers in gas mixtures containing mainly CH4 is very low as the

7

light alkanes are very weak supercritical solvents (SCF) unless the system pressure and

8

temperature are and/or the density of the components are considerably high25. In addition, it is

9

difficult to perform Molecular Dynamic simulation studies for gas mixtures containing more than

10

one component to determine the solubility of polymers in them at any given pressure and

11

temperature. Therefore, as the only viable option, the previously described high- throughput

12

extraction method was used to screen the solubility of the selected 32 polymers in supercritical

13

hydrocarbon gas mixture (CH4 60%, C2H6 9%, C3H8 6% and CO2 25%). Figure 5 shows the

14

percentage of the original weight of every polymer extracted by the AG mixture. As pointed out


22

Page 23 of 47

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Energy & Fuels

1

before, the 32 polymers examined were commercially available polymers which had been tested

2

by other researchers to be soluble in pure CO2 at high and/or low pressures. Based on the

3

solubility data presented in this graph, the polymers may be divided into four categories. The

4

first category are those with high level of extraction (> 96%) under the conditions explored in

5

this work. This category contains four polymers namely poly (1-decene) (P-1-D), 1,4-di-tert-

6

butylbenzene, poly (Methyl Hydro Siloxane) (PMHS) and poly(Dimethyl Siloxane) (PDMS).

7

The second category contains the polymers with a moderate level of extraction (45-85%). This

8

category covers another four polymers namely PDMS

9

ethyl ether and poly (propylene glycol). These polymers would need more pressure and/or more

10

volume of gas passing through the extraction vessel so they may dissolve completely in the AG

11

mixture. The third category includes those with a low level of extraction (5 20%). The

12

materials in this category include poly (ethylene glycol), poly (ethylene succinate), poly

13

butadiene and Poly (propylene glycol) mono butyl ether. From the second and third category, it

14

can be seen that the polymer backbone and molecular weight architectures affect the polymer

15

solubility in the AG mixture. For instance, the weight extraction of poly (vinyl alkyl ether)

16

increases with increase in the length of the alkyl tail from methyl to ethyl (45% to 85%). As the

17

length of alkyl tail on this polymer increases, the free volume of this polymer is expected to

18

increase, which makes this polymer easier to dissolve in the AG mixture if the alkyl tail increase

19

to propyl or butyl. For the molecular weight effects, the PDMS (Mw 170,000) in category two

20

was much less soluble in the AG mixture than PDMS (Mw 97,000) in category one due to the

21

entropic effects associated with the higher molecular weight of PDMS. The final category

22

includes those polymers with negligible (< 5%) extraction. These polymers belong to the

23

carbonated and hydroxyl end groups such as poly vinyl acetate (PVAc) and poly vinyl alcohol

25

, poly vinyl methyl ether, poly vinyl


23

Energy & Fuels

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Page 24 of 47

1

(PVA). These end groups enhanced the solubility of low/high molecular weight polymers in pure

2

CO2 under high pressure,43 but unfortunately, that did not occur in the case of the AG mixture

3

even when enriched with CO2.

4 5

Figure 5. Extracted weight % in the AG mixture for a library the 32 polymers at 55 MPa and

6

337K. The name of the polymers whose numbers are presented on the horizontal axis can be

7

found in Table 1.

8

The polymer concentration in the AG mixture is determined using the following equation:

9

χ>

?@ ?@ ?@A BCD .(EF#GG H ) B@

(Eq.4)

10

Where ρJ (g. cm ) and mJ (g) are the density and mass of the polymer that is dissolved into

11

the AG mixture. KLMNN is the volume of the windowed cell which is equal to 20 cm .

12

ρ (g. cm ) is the density of the AG mixture at reservoir pressure and temperature which is

13

estimated using the CMG WinProp model.

14

The solubility of those polymers with high extraction percentages (Category 1 from above)

15

was further verified using conventional cloud point pressure measurements conducted over a

16

range of temperatures (concentration was 1.5wt%). A 1,3-di-tert-butylbenzene substance has

17

been excluded from the cloud point pressures measurements because it has a low molecular


24

Page 25 of 47

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Energy & Fuels

1

weight (190 g/mol) and is expected to have an insignificant effect on the results. However, it is

2

included in the previous test to validate the high soluble polymers results from the HTGE

3

experiment, as this is also proved by Miller, M.B., et al.(2012) that 2,4-di-tert-butylbenzene was

4

soluble in CO2 and CO2/H2 mixture.44 Figure 6 shows the measured cloud point pressures for

5

PDMS, PMHS and P-1-D at different temperatures. As can be seen, PDMS and PMHS were

6

found to be completely soluble in the AG mixture over the whole range of temperatures

7

investigated (298-383 °K) while for P-1-D, that was found to be the case only at temperatures

8

above 358 °K. These measurements indicate that P-1-D and PMHS can be adequately dissolved

9

into the AG mixture under Field A reservoir conditions. Under the Field A temperature, PDMS

10

has a much higher cloud point pressure than other two polymers due to the energetic and entropic

11

effects45. In general, most of the polymers exhibit LCST (Lower critical solution temperature)

12

trends in the volatile hydrocarbon components and CO2.25 As the temperature increases, a higher

13

pressure is required to dissolve the polymer in a mixture. As apparent from Figure 6 PMHS

14

exhibits similar trend to the PDMS in the light hydrocarbon gases and CO2 mixture. The

15

solubility of both polymers have a strong dependency on temperature as their molecular weights

16

are less than 100,000 g. mol . In a previous study, Zeman et al.46 found that PDMS has a high

17

solubility in light hydrocarbon gases (C2 – C4) because of the large thermal expansion coefficient

18

for the PDMS and low reduced temperature values for the solvents. However, this solubility

19

reduces with reducing the molecule size of alkane, similar to earlier described work that Dhuwe

20

et al. found PDMS to be less soluble in ethane than propane and butane.36 Therefore, in this

21

study, PDMS becomes less soluble in the AG mixture as CH4 is the main constituent of the gas

22

mixture. In addition, due to the entropic effects, the density of PDMS decreases and its free

23

volume increases at high temperature, making PDMS to be less soluble in the AG mixture as the


25

Energy & Fuels

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Page 26 of 47

1

temperature is increased. Therefore, it needs a higher pressure to dissolve completely in the gas

2

mixture at high temperatures.

3

The observed solubility for silicone polymers (PMDS and PHMS) and poly alfa-olefin (PAO)

4

(P-1-D) polymers in the gas mixture is probably due to partial presence of CO2 in the mixture

5

and the influence of high temperature and pressure. Generally, the solubility of polymers in a

6

mixture consisting of low molecular weight components increases at elevated temperature due to

7

the dominance of dispersion interactions.25 In the experiments conducted here, P-1-D behaves as

8

a single phase liquid in the AG mixture only at temperature above 358 °K, unlike PDMS and

9

PMHS, which start behaving as single-phase liquids in the gas mixture at 298 °K as can be seen

10

in Figure 6. Thermodynamically, the heat of mixing depend on the difference between the

11

cohesive energy of a solution, as the temperature rises, the cohesive energy of the mixture

12

become greater than the total cohesive energies of the component liquids.47 The temperature and

13

pressure needed to obtain the solubility of the polymers in SCF depend on the intermolecular

14

interaction between solvent-polymers segment and polymer-polymer and solvent-solvent in

15

solution.48 A P-1-D has flexible alkyl branching groups on each other carbon of their backbone

16

chain. These flexible alkyl groups can shape themselves in numerous conformations, forming

17

random polymer coil. These conformations impact on the accessibly of light gas to the polymer

18

coil. As the temperature increases, the solvent becomes more effective and the polymer coil

19

expands which causes a lower contact surface area between molecules and decreases the

20

intermolecular interactions.49 If the temperature is high enough as is in Field A, the energetic

21

interaction between the polymers and solvents outweigh the polymer segment-segment and

22

solvent–solvent interaction. In Figure 6, above 358 °K the P-1-D becomes completely soluble in


26

Page 27 of 47

1

the mixture which can obtain a single phase solution at suitable pressure. Therefore, given these

2

solubility conditions, P-1-D is expected to dissolve in the AG mixture at Field A conditions. PDMS

P-1D

PMHS

70 65 Cloud pressure (MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

60 55 50 45 40 35 30 298

308

3

318

328

338 348 Temperature (°K)

358

368

378

388

4

Figure 6. Measured cloud-point pressures for three polymers at 1.5wt% in the AG mixture at

5

different temperatures.

6

CO2 is a weak solvent for many polymers. Several studies have reported that silicone polymer

7

and PAO are soluble in CO2 under supercritical conditions.20, 35, 50-53 Partial presence of CO2 in a

8

hydrocarbon gas mixture can have a large influence on the cloud point pressure of the polymer-

9

gas mixture as evident from Figures 7 and 8. The cloud point pressures were measured for

10

PMHS and P-1-D at a concentration of 1.5 wt% in three AG mixtures containing different CO2

11

weight fractions (CHS 75%, CT HU 9%, C H) 6% and COT 10%, CHS 60%, CT HU 9%, C H) 6%

12

and COT 25%, and CHS 40%, CT HU7%, C H) 3% and COT 50%). It is found that as the CO2

13

content in the AG mixture increases, the cloud point pressure decreases across all temperatures.

14

As can be seen from the two figures, a 15% increase in the CO2 content (from 10% to 25%) in

15

the gas mixture causes a reduction in could point pressure of around 3 MPa for both polymers.


27

Energy & Fuels

1

These results may indicate that the presence of CO2 in the AG mixture can possibly facilitate the

2

dissolution of silicone polymers and POA polymers in the gas mixture. In comparison to the

3

silicone polymer in pure CO2, Lee et al.54 found the cloud point pressures of low molecular

4

weight (Mw 3780) PDMS (10 MPa, 14MPa) at the concentration 2 wt% and different

5

temperature (296 °K and 313 °K) to be 4.7-3.4 times less than that of the AG enriched by CO2.

6

That is because PDMS molecules are more CO2 philic than light hydrocarbon. Gas mixture with 10% CO2

Gas mixture with 25% CO2


60 55

Cloud pressure (MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 47

50 45 40 35 30 298

7

308

318

328

338 348 Temperature (°K)

358

368

378

388

8

Figure 7. Measured cloud point pressures for PMHS at 1.5wt% in the AG mixture containing

9

different percentages of CO2 at different temperatures.


28

Page 29 of 47




60 55 Cloud pressure (MPa)

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Energy & Fuels

50 45 40 35 30

1

355

360

365

370 Temperature (°K)

375

380

385

2

Figure 8. Measured cloud point pressures for P-1-D at 1.5wt% in the AG mixture containing

3

different percentages of CO2 at different temperatures.

4

Based on the earlier presented solubility results (Figure 6), among the three polymers

5

examined, P-1-D has a lower cloud point pressure in the AG mixture at Field A reservoir

6

conditions. Lower cloud point pressure may also make it possible to increase its concentration in

7

the gas mixture to values higher than 1.5 wt% to further increase the AG mixture viscosity. In

8

comparison, the cloud point pressures of both PDMS and PMHS are considerably higher even

9

exceeding the reservoir pressure limit (55 MPa). Therefore, the concentrations for both polymers

10

cannot be increased to more than 1.5 wt%. Furthermore, according to the data reported in the

11

literature, at 298 °K, the miscibility pressures of PDMS (2 wt%) with pure CO2, ethane, propane

12

and butane (23 MPa, 12 MPa, 1.07 MPa and 0.31 MPa, respectively) are much less than the

13

miscibility pressure of PDMS and PMHS in the AG mixture (47 MPa and 43 MPa,

14

respectively)36, 54. This is because CH4 is the main component in the mixture making PDMS less

15

soluble. A 1- 2 wt% solution of PDMS in CO2 or NGL enhanced the viscosity to only 1.5 to 2

16

fold only at 298 °K 36. Hence, PDMS and PMHS may not be expected to be suitable thickeners


29

Energy & Fuels

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Page 30 of 47

1

at higher temperature. Therefore, the focus of any further assessments has been placed solely on

2

P-1-D.

3

The cloud point pressure for P-1-D was measured in the AG mixture containing C1H4 60%,

4

C2H6 9%, C3H8 6% and CO2 25%, at three temperatures of 358 °K, 368 °K and 377 °K and for a

5

range of concentrations. The results of the measurements are plotted in Figure 9. As can be seen

6

from the figure, at all three temperatures, the measured cloud point pressure increases linearly

7

with P-1-D concentration. As expected, with increasing temperature, a higher pressure is needed

8

to dissolve the P-1-D /AG mixture in a single phase. At 9 %wt of P-1-D in the mixture, the

9

required pressure has to be 51.4 MPa at 377.15 °K which is still below the reservoir pressure of

10

55 MPa. Hence, P-1-D polymers can be adequately dissolved into this mixture at reservoir

11

conditions even for concentrations higher than 9 wt%. This behaviour is because of the solvent

12

entropy effect on the polymer solubility as described earlier. At high temperature, changes in the

13

cloud point pressure are very subtle, as can be seen in Figure 8. The reason behind such a

14

behaviour can be explained as follows. Generally, as the temperature increases the free volume

15

difference between the solvent and the polymer would increase leading to the system phase

16

separation which then requires elevated pressures for the solution to remain a signal phase25.

17

However, at high pressure, the molar volume of the solvents reduces and the difference in free

18

volume decreases between the polymer and the solvent which leads to the enthalpy of mixing

19

dominating over the entropic of mixing.25 That can be attributed to the cloud point pressure curve

20

being relatively constant with increasing temperature. Figure 9 shows the results of cloud point

21

pressure measured for P-1-D at different known solubilities and temperatures. At all three

22

temperatures, the measured cloud points pressure increase linearly with P-1-D solubility weight.


30

Page 31 of 47

377 K

368 K

358 K

55 54 53 Cloud point pressure ( MPa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

52 51 50 49 48 47 46 45 0

1

2

3

4

5

6

7

8

9

10

P-1-D concentration (%wt)

1 2 3

Figure 9. Measured cloud point pressures for P-1-D at different concentrations and temperatures.

4

3.2 Polymer- Thickened AG Viscosity

5

The viscosity of the P-1-D- thickened AG mixture was measured at two pressures of 52 MPa

6

and 55 MPa (both are above its cloud point), three temperatures of 358 °K, 368 and 377 °K and

7

varying the polymer concentration between 0 and 9 wt%. The results of the measurements are

8

presented in Figures 10 and 11 in the form of the actual measured viscosities and relatives

9

viscositiesWXYZG [, respectively. As can be seen from these two figures, there is a significant

10

increase in P-1-D-thickened AG mixture viscosity (2 - 7.4 fold) with increase in the P-1-D

11

concentration. Overall, the relationship between viscosity and P-1-D concentration seems to be

12

linear. The temperature also tends to have a moderate effect on the measured data with viscosity

13

of the solution decreasing almost linearly with increase in temperature. In general, the thermal

14

degradation of any polymeric additives at 373 °K is very unlikely to occur much less affect their

15

rheological properties. Such a loss can cause a significant reduction of viscosity in most

X

CD


31

Energy & Fuels

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Page 32 of 47

1

polymers due to the weakness of intermolecular association of polymer-polymer segments.

2

However, in this study, P-1-D has been found to be an effective thickener for the AG mixture

3

tested even above 373 °K at high pressure. It seems that this polymer is thermally stable at high

4

temperatures as demonstrated by other studies too where it was dissolved in 1- hexane and 1-

5

octane mixture at high temperature and high pressure.55, 56 In general, poly-α olefin, such as P-1-

6

D, have excellent thermal and oxidative stability, high Viscosity Index (VI) and low pour point

7

due to the lower branching ratio (0.19).57 A high VI means the rate of viscosity drop is low as the

8

fluid temperature increases due to expansion of the polymer coil with increasing temperature.58

9

As previously shown in the P-1-D- AG mixture, the AG mixture solvents become more effective

10

as the temperature increases which leads to the P-1-D dissolving through the expansions of the

11

P-1-D molecules. Conversely, as the temperature decreases, AG solvents become less effective

12

as the macromolecules contract leading to the precipitation of the P-1-D. In addition, this

13

polymer is stable at high temperature due to the flexible alkyl branching group on the C-C

14

backbone chain and that its synthesis process takes place at high temperature (398.15 °K) in the

15

isomerization reaction resulting in a better thermal stability.59, 60 Hence, P-1-D does not tend to

16

affect it rheological properties at high temperature and maintains its ability to enhance the AG

17

mixture tested here.

18

As reported by Heller et al.,35 dissolution of poly-1-hexenes at concentration 1wt% to 2.2wt%

19

resulted in significant increases in the viscosity of n-butane and n-hexane (5-10 fold ). In a recent

20

publication, Zhang et.al

21

using less than 1 wt% of P-1-D at 329.15 °K. However, Zhang et.al findings do not correlate and

22

are inconsistent with the results of other previous research work 13 as well as the present study. In

23

most studies reported in the literature, low/high molecular weight polymers and small molecular

23

also found the viscosity of CO2 to increase significantly by 13 fold


32

Page 33 of 47

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

1

polymers that have been reported to thicken CO2 used concentrations 1.5 - 7wt %.13 This

2

experimental result demonstrates that the HC gas mixture can be thickened using P-1-D which is

3

consistent with previous research reported with gas thickener.

4

As can be seen from Figures 10 and 11, with increase in pressure, there is a slight increase in

5

the viscosity of the polymer/AG solution at all the temperatures and polymer concentrations

6

explored. Dhuwe et al have reported a similar effect where they thickened the light alkanes using

7

an ultra-high molecular weight poly α-olefin drag reducing agent.36,

8

behaviour is because the strength of alkanes increases with density and pressure, which can be

9

reflected on the swelling and overlapping between the polymer chains. With temperature

10

increase, there is also a significant viscosity reduction of the polymer/AG solution at all the

11

polymer concentrations tested. For instance, at 5 wt% polymer concentration, a 0.38 fold

12

reduction can be seen between temperatures of 378 and 377 °K. Overall, there is a linear

13

relationship between the temperature and viscosity reduction of the polymer/AG solution.

37

The above-described

14

The P-1-D viscosity enhancement results achieved are indeed very promising. Such data open

15

up the potential of thickened AG injection in Field A and other similar fields towards enhancing

16

the oil recovery beyond original estimates.


33

Energy & Fuels

358 K and 52 MPa 358 K and 55 MPa

Gas/polymer viscosity ( cP)

0.26



0.21

0.16

0.11

0.06

0.01 0

1

2

3

4

1

5 Wt % P-1D

6

7

8

9

10

2

Figure 10. Measured P-1-D-thickend AG gas viscosity at different P-1-D concentrations,

3

temperatures and pressures.


8



7 6

Relative viscosity

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 34 of 47

5 4 3 2 1 0 0

1

2

3

4

5

6

7

8

9

10

4

Wt % P-1D

5

Figure 11. Relative viscosity WXYZG [ at different P-1-D concentrations, temperatures and

6

pressures.

7

X

CD

3.3 Core-Flood Experiments


34

Page 35 of 47

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Energy & Fuels

1

Three core-flood experiments were conducted under secondary and tertiary modes to

2

investigate the effectiveness of the thickened AG mixture (5 wt% P-1-D) in enhancing the

3

recovery from the Field A, and related fields. All three experiments were performed under the

4

reservoir conditions of 377 °K and 55 MPa. At this P-1-D concentration, the injected AG

5

viscosity is enhanced from 0.0299 to 0.131 cP (4.38 fold) under reservoir conditions. The pore

6

pressure applied during the core flooding was higher than the Minimum Miscibility Pressure

7

(MMP) for the AG mixture used. The MMP for the AG mixture in the Field A dead oil was

8

estimated from the CMG WinProp module to be 40 MPa. Table 3 presents the petrophysical

9

properties of the carbonate composite core plugs, the experimental conditions and the ultimate

10

oil recovery factor for the flooding tests using the AG mixture as well as the thickened mixture.

11

In all three flooding experiments, the residual water saturation was found to be very low because

12

the oil and water viscosities (0.24 and 0.29 cP respectively) are very close at reservoir conditions

13

and also the high pore pressure applied in the system. The irreducible water saturation in a

14

laboratory scale depends on the capillary properties of the rock or the viscous forces between the

15

oil and water.61 In addition, the results that we have obtained in the experiment is in line with

16

Larsen et.al as he has stated that water saturation can be reduced to zero if a high capillary

17

pressure is applied and if the water in the core has a continuous phase which leads to an escape

18

route for the water.62

19

Table 3. Summary of the core-flooding experiment data (377 K and 55MPa). K: Permeability,

20

ϕ: Porosity, Swirr: Irreducible Water Saturation, Soi Oil Saturation, RFAG: AG Recovery Factor,

21

RFthick’d AG: Thickened AG Recovery Factor and RFtotal :Total Recovery Factor. Test No.

EOR Mode

Κ

ϕ

S_`""

S`

RF

mD

%

%

%

%

RFcd`efgh %

RFcci %


35

Energy & Fuels

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Page 36 of 47

1

Secondary

8.2

14.20

2.5

97.5

-----

96.75

96.75

2

Tertiary

5.2

14.592

2

98

84.2

10.2

94.5

3

Tertiary

2.9

15.153

1.8

98.2

20

77.5

96.66

1 2

The oil recovery profile for all three tests are plotted in Figure 12 until 3.6 PV and in Figure 13

3

until 9 PV of thickened gas injected. In the first test, the thickened AG injection was conducted

4

under secondary recovery mode. As such the thickened gas injection commenced at injection rate

5

0.4 cm . min when water saturation was at residual corresponding to maximum possible oil

6

saturation in the core sample. In this test, the gas breakthrough occurred after 0.29 PV of

7

thickened gas injection corresponding to an oil recovery of 30%. After the breakthrough, the oil

8

recovery factor continued to increase steadily up until 64% or 0.85 PV of thickened gas

9

injection. After that, the oil recovery continued at lower rates until the end of the experiment

10

corresponding to 9 PV of gas injection and a final recovery of 96.75% of the OOIP. In the

11

second test the thickened AG gas was injected to recover oil under tertiary mode after injecting

12

the unthickened gas on its own under secondary mode. Initially, the AG mixture was injected at

13

0.4 . jk and the breakthrough occurred at just 0.163 PV of gas injection which is much

14

earlier than the first test. This early breakthrough time is due to the large viscosity contrast

15

between the oil (0.24 cP) and unthickened AG mixture (0.0299 cP). As can be seen from Figure

16

12, in test 2, the oil recovery at breakthrough is about 20%, which is lower than that of test 1 by

17

about 33%. In summary, addition of the polymer to the injected AG mixture helped to improve

18

the displacement efficiency by reducing the viscosity contrast and delaying the breakthrough.

19

The viscosity contrast can be further reduced resulting in better displacement performance by

20

dissolving more than 5% of P-1-D in the AG mixture. In the second test, at 3 PV gas injection,

21

the oil almost stopped from being produced but the injection continued until 3.6 PV of gas


36

Page 37 of 47

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Energy & Fuels

1

injection at which point the oil recover had reached 84.2% corresponding to a residual oil

2

saturation of 13.8%. Subsequently, the injection of the P-1-D-thickened AG solution was

3

commenced. After the injection of 5.4 PV of the thickened gas, owing to 4.38 fold increase in the

4

viscosity of the injected gas, the oil recovery factor increased by 10% to a final value of 94.2%

5

but still less than the final value achieved in test 1 by more than 2.5%

6

The third core-flooding test was conducted with P-1-D-thickend AG solution injected

7

immediately after the breakthrough of the unthickened AG mixture. As can be seen in Figure 12,

8

the AG mixture breakthrough occurred after 0.168 PV were injected which corresponds to an oil

9

recovery of 21%. As may be expected, the breakthrough properties (injected volume and

10

recovery factor) of these test are much closer to those of the second test. In test 3, during the

11

early times of the post-breakthrough thickened gas injection, the oil recovery profile shows

12

values slightly less than those achieved in test 1 for the same values of recovery (Figure 12).

13

However, with further injection the two curves seem to overlap resulting in almost identical final

14

recovery factors for the two floods. Given the current condition of Field A where gas

15

breakthrough has already been experienced in some production wells, the results of the third test

16

may be the most relevant if the thickened gas injection is to be implemented in this field.


37

Energy & Fuels

Test 1-Thickened AG flood-Secondary mode

Test 2-Thickened AG flood-Tertiary mode

Test 3-Thickend AG flooding-Tertiary mode 100

90

80

70

Oil Recovery Factor %

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 38 of 47

60

50

40

30

P-1-D -thickend AG solution BT at 0.29 PV of injection in Test 1 The begineing of thickened gas injection for Test 3

20

AG mixture BT at 0.163 PV and 0.168 PV gas injection in Test 2 and Test 3, respectively.

10

0 0

1

1

2

3

4

HC gas PV injected

2

Figure 12. Measured oil recovery factor versus 3.6 of total injected pore volume of AG mixture

3

or P-1-D-thickend AG solution at flow rate 0.4 cm . min , reservoir temperature 377 °K and

4

pressure 55 MPa.


38

Page 39 of 47

Test 1-Thickened AG flood-Secondary mode Test 3-Thickened AG flood-Tertiary mode

Test 2-Thickened AG flood-Tertiary mode

100

90

80

The begineing of thickened gas injection Test 2 70

60

Oil Recovery Factor %

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

50

40

30

20

The begineing of thickened gas injection for Test 3

10

0 0

1

2

3

4

5

6

7

8

9

HC gas PV injected

1 2

Figure 13. Measured total oil recovery factor versus 9 of total injected pore volume of AG

3

mixture or P-1-D-thickend AG solution at flow rate 0.4 cm . min , reservoir temperature 377

4

°K and pressure 55 MPa.

5


39

Energy & Fuels

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1

Page 40 of 47

4. CONCLUSIONS

2

The solubility of 32 commercial polymers was assessed in a supercritical AG mixture using a

3

rapid screening method (gravimetric extraction method) and was reinforced using conventional

4

cloud point testing. These methods examined a number of commercial polymers that were found

5

to be soluble in a hydrocarbon gas mixture as the solvent. In particular, three polymers were

6

discovered that were soluble in the AG mixture. The solubility profiles of these three polymers

7

were further studied by measuring the cloud point pressures using a high-pressure cell equipped

8

with a window. P-1-D and PMHS polymers are soluble in AG mixture under actual reservoir

9

conditions. The polymer-thickened AG solution viscosity was measured using a manufactured

10

capillary viscometer. The measured thickened AG solution viscosities show only P-1-D with the

11

ability to enhance the AG mixture viscosity between 2 to 7.4 fold at high pressure and high

12

temperature, while the PMHS cannot increase the AG mixture viscosity at low polymer

13

concentrations. It is found that a concentration 5wt % of P-1-D in AG mixture can effectively

14

increase AG mixture viscosity by 4.38 fold at 377 °K and 55 MPa. Three composite core

15

flooding tests were conducted for AG mixture and thickened AG solution flooding to assess the

16

effect of 4.38 fold viscosity increase on oil recovery and gas breakthrough in secondary and

17

tertiary recoveries. In secondary recoveries, the P-1-D- thickened AG solution achieved a higher

18

oil recovery factor than AG mixture injection and delayed the breakthrough to 0.29 PV. In

19

tertiary recovery, the subsequent injection of the P-1-D –thickened AG solution showed the

20

ability to mobilize and produce the residual oil left after AG mixture flooding completed. In

21

summary, a direct thickening of AG mixture by P-1-D at high pressure and high temperature can

22

improve gas mobility and sweep efficiencies; this resulted in an improved ultimate oil recovery.

23


40

Page 41 of 47

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Energy & Fuels

1

AUTHOR INFORMATION

2

Corresponding Author

3

* E-mail: [email protected] or [email protected]

4

Tel: +61452589291

5 6

Author Contributions

7

All authors contributed to the manuscript; and all authors approved the final version of the

8

manuscript.

9

ACKNOWLEDGMENT

10

The Authors would like to acknowledge the generous support provided by the Petroleum

11

Development Oman (PDO) and Ministry of Oil and Gas (MOG) in Oman. They provided Field

12

A reservoir data, the rock and crude oil samples used in this study and the scholarship and

13

financial support for PhD student Nasser Al Hinai.

14

ABBREVIATIONS

15

EOR, Enhance Oil Recovery; MGI, Miscible Gas Injection; AG, Associated Gas; P-1-D, Poly

16

(1-Decane); PMHS, Poly (Methyl Hydro Siloxane); PDMS, Poly (Dimethyl Siloxane); PVAc,

17

Poly Vinyl Acetate; PVA, Poly Vinyl Alcohol; TBTF, Tributyltin fluoride; HAD2EH, hydroxyl

18

aluminium di-2ethylhexanoate; DRA, Drag Reducing Agent; MMP, Minimum Miscibility

19

Pressure; CMG, Computer Modelling Group; OOIP, Original Oil In Place; PAO, Poly Alfa-

20

Olefin; HTGE, High Throughput Gravimetric Extraction; HC; Hydrocarbon


41

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 42 of 47

1

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4 5

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