Experimental Investigation of Brine Hardness and Its Induced Chemistry during Heavy Crude Recovery t

Experimental Investigation of Brine Hardness and Its Induced Chemistry during Heavy Crude Recovery through CO2 Injection Ronald Nguele1,a *, Kyuro Sasaki1,b, Yuichi Sugai1,c, Hikmat Said‐Al Salim2,d, Mohammad Reza Ghulami1,e and Masanori Nakano3,f Resource Production and Safety Engineering Laboratory, Kyushu University, Japan

1

UCSI University, Kuala Lumpur Malaysia

2

Research Center, JAPEX, Japan

3

nguele.odou.548@s.kyushu‐u.ac.jp; bkrsasaki@mine.kyushu‐u.ac.jp; csugai@mine.kyushu‐u.ac.jp; dhikmatsaid@ucsiuniversity.edu.my; erezagholami87@mine.kyushu‐u.ac.jp; fmasanori@japex.jp a

* Corresponding author Abstract In a typical oil reservoir, untapped crude co‐exists with water (connate water or brine) whose chemical composition depends on the formation in which it trapped. Although CO2‐EOR has been lately regarded as viable recovery technique for heavy crudes, its applicability on the field scale lies in understandings of various phenomena among which induced chemistry. In this research, we proposed to evaluate the extent to which brine salinity and hardness as well as an induced chemistry inherent to CO2 injection alter heavy oil recovery. Conducted at a laboratory scale, CO2was selected as a displacing agent to be injected in an analysis cell of a PVT apparatus within which reservoir physical conditions were reproduced. A heavy crude (API 11.5o) and three brine solutions chemically different were selected as displaced fluids. CO2 showed a high solubility, which increased with the pressure, comparatively to methane in both pure component hexadecane and heavy crude with a bubble point –pressure at 7.8 MPa. Salinity, taken alone, was found not to alter gas solubility, however the build‐up in Ca2+ and Mg2+ within connate water impacted invariably GOR. Keywords CO2 ‐EOR; Heavy Oil; Hardness; Salinity

Background Up to 75% of well productivity could be achieved when an appropriate EOR technique is applied to an oil reservoir.

The choice of EOR technique lies in the knowledge of the field and the fluid to be displaced. The depth of a reservoir, its temperature and pressure, oil gravity as well as oil viscosity are few parameters to be taken into consideration. Heavy crudes, with a potential of 5 trillion barrels reported untapped, have been arising a commercial interest [1]. Although CO2 – EOR has received less attention for heavy crudes compared to light and medium crudes, it has lately been gaining prominence with some experimental applications reported. [2‐3]. Despite the fact that CO2 injection offers both advantage to sequester a greenhouse gas and to be readily cheap, it has been reported to lack acceptable sweep efficiency due to the large viscosity contrast between CO2 and oil as well as the unlikeliness of development of a miscible front in heavy oil reservoirs [4].

In general, oil recovery is influenced by various physical factors including relative permeability, wetting conditions, viscous fingering, gravity tonguing, channeling and the amount of crossflow/mass transfer [5‐6]. Furthermore, reservoir formation and the displacing fluid may go through a chemistry that is believed to alter gas solubility thus the recovery efficiency. This later aspect is supported when ideal physicochemical conditions are met.

This paper, therefore, has considered primarily analyzing the magnitude to which an inherent chemistry imputed to gas injection may influence or impact a typical CO2‐EOR. To a further extent, it proposes to demonstrate the 60 International Journal of Engineering Practical Research, Vol. 4 No. 1‐April 2015 2326‐5914/15/01 060‐07 © 2015 DEStech Publications, Inc. doi: 10.12783/ijepr.2015.0401.13

Experimental Investigation of Brine Hardness and Its Induced Chemistry during Heavy Crude Recovery through CO2 Injection 61

viability of CO2‐EOR as recovery technique for heavy crudes.

Materials, Experimental and Computation technique Materials In an oil reservoir, fossil resources are generally mixed with water also known as brine or connate water. This research, which intends to reproduce conditions existing underground, has selected as displaced fluids heavy oil and brine solutions whose physical and chemical characteristics are tabulated in Table 1. Brine solutions have been synthetically prepared and aimed to model connate water composition as reported by actual oilfields.

Heavy oil candidate for the experimental has been drilled in Hokkaido (Japan). CO2, 99.99 % purity, was chosen as primary displacing gas and was supplied by Itochu Industry gas Ltd. (Japan). To have a comparative basis, methane (CH4) has been used as alternative gas.

TABLE 1.PHYSICAL AND CHEMICAL PROPERTIES OF MATERIALS USED

API [o]

Heavy Oil

11.5

Specific Gravity [‐]

Kinematic Viscosity [cSt]

0.988

874

Brine code

Chemical composition

Density

Molecular Weight

pH

[g/cm3]

[g/mol]

[‐]

CW‐1

2% NaCl

0.76607

18.248

6.46

CW‐2

4% NaCl+10 ppm Ca2+

0.76608

18.495

6.51

CW‐3

10% NaCl + 60 ppm Ca2+ + 30 ppm Mg2+

0.99463

19.221

6.87

Experimental In a laboratory scale, a typical multi contact test including gas injection, thus CO2‐EOR, is conducted through an apparatus known as P‐V‐T. The model used for this study and the experimental schematic is depicted in Figure 1.

The gas, CO2, was injected at its subcritical pressure (P= 4 MPa) in an analyzing cell containing both heavy oil and a brine solution. The injection was performed at constant temperature of 50oC. Afore‐discussed conditions are believed to simulate an average reservoir conditions [7].

Pressure gauge

From gas tank

Relief valve Vapor phase Liquid phase (Crude + brine)

Gas Holding Cell

Piston

Anaylizing/Diffusion Cell

FIGURE 1. P‐V‐T (RUSKA TEXAS, MODEL 2370) APPARATUS ‐ EXPERIMENTAL SCHEMATIC ILLUSTRATION.

62 Ronald Nguele, Kyuro Sasaki, Yuichi Sugai, Hikmat Said‐Al Salim, Mohammad Reza Ghulami and Masanori Nakano

Computation Technique The prime information from PVT tests are the ratio of phase volume at reservoir conditions to that at surface conditions, and the solubility of gas in oil. In general, it lies upon the change in pressure of the system gas‐fluid at either a constant volume or both recorded in function of time. Consider an isothermal pressure‐volume graph in function of contacting time as shown in Figure 2, 4.8

4.6

Pressure,in M Pa

4.4

E 4.2

4.0

C 3.8

A

D B

3.6 0

5

10

15

20

25

30

Tim e,in hrs FIGURE 2. EXPERIMENTAL ISOTHERMAL PRESSURE –VOLUME PROFILE.

Let AB, BC, CD and DE to be characteristic points of the plot. The gas injected (A) diffuses in the liquid phase composed of the mixture heavy oil + brine (AB). Concurrently, solubility process occurs (BC) which continues until a pseudo equilibrium is reached (CD). At this stage, vapor‐phase and heavy oil mixture‐rich phases are believed to be thermodynamically in equilibrium. This state is broken if any further mechanical compression (DE) is performed.

The amount of CO2 diffused into the liquid phase is calculated from the change in pressure or volume of the gas phase along with a cubic equation of state (EOS) of real gases. If ni and neq are the number of moles of gas at the injection A and the equilibrium D respectively, the number of moles nd dissolved in the heavy oil mixture rich phase is given by (1),

nd  ni  neq 





1 l ilVi  eq Veq .

MWgas

(1)

Whereρliand ρleq represent liquid densities of oil mixture‐rich phase at the injection and at the equilibrium state respectively, in g.cm‐3.

Viand Veq are the volumes of oil mixture‐rich phase at the injection and at the equilibrium state respectively, in cm3.

MWgas is the molecular weight of the displacing gas, in g.mol‐1.

Both ρliandρleq were computed, as aforementioned, using a cubic equation of state. This study has selected Peng‐Robinson EOS (1976) [8].

Therefrom, we have defined gas solubility Rs as the ratio of amount of dissolved gas to the Fluid‐In‐Place as mathematically expressed by (2), Rs 

nd

WFIP

.

(2)

Where nd is the number of moles dissolved, in mmol and WFIP is the total weight of fluid‐in‐place (heavy crude+brine), in g.

Experimental Investigation of Brine Hardness and Its Induced Chemistry during Heavy Crude Recovery through CO2 Injection 63

Results and Discussions Figure 3 depicts the gas solubility in heavy crude selected for this study. CO2 was found to be highly soluble compared to CH4 when considered as alternative gas. Experimentally, the bubble point‐pressure was found at 7.70 MPa which concords with the literature [9]. Moreover, although CH4 was found to diffuse rapidly in oil mixture, it has shown a slow pace to reach the equilibrium point. This is partially explained by its high bubble point‐pressure as reported by Sasaki et al. (2013) [10].

Compared to a pure component (n‐ hexadecane) as performed by Tanaka et al.(1993) [11], CO2 showed a good solubility response that is imputed to its chemical composition.

50

G as Solubility,R s,in m m olCO 2/g-oil

(Tanaka et al.,1993) CO 2:H eavy O il 10

40

CH 4:H eavy O il

8

Calculated from EO S

6

4

30 2

0 0

1

2

3

4

5

20

10

0 0

2

4

6

8

10

12

14

16

Equilibrium Pressure,in M Pa FIGURE 3. SOLUBILITY OF CH4 AND CO2IN HEAVY CRUDE.

CO2 Injection and Induced Chemistry When injected in cell/reservoir, CO2 comes in contact with both water (brine) and heavy oil. The conditions existing within are thought to favor an induced chemistry. Free Gibbs energy of the pseudo system has been computed and it was found to be negative, thence suggested occurrence of chemical reactions. The process is believed to start with formation of carbonic acid as expressed by (3‐5),

CO 2(g)  CO 2(aq) .

H 2O(aq) + CO2(aq)  H +  HCO3 (aq) .

HCO-3  H + +CO32-(aq) .

(3) (4) (5)

If CO32‐is selected as tracer i.e. component that asserts formation of carbonic acid, it is able to compute its concentration mathematically expressed by (6),

CO 32- 

C NaCl .

D

(6)

Where CNaCl is the concentration of brine solution, in mol/L

64 Ronald Nguele, Kyuro Sasaki, Yuichi Sugai, Hikmat Said‐Al Salim, Mohammad Reza Ghulami and Masanori Nakano

D is acidity factor, D  1 

10  pH 102 pH K1and K2are acidity constants.  K2 K1 K 2

Brine, channeling through reservoir formation, gets enriched in metal ions Mn+ which subsequently react with free CO32‐ and lead to formation of carbonate salts M2(CO3)n also known as scale. This chemical process is described by (7‐10)[12]. +  NaCl(aq)  Na (aq)  Cl(aq) .

(7)

+ 2Na (aq) +CO32-(aq)  Na 2CO3(aq) .

(8)

2+ Mg(aq) +CO32-(aq)  MgCO3(aq) .

(9)

2+ Ca (aq) +CO32-(aq)  CaCO3(aq) .

(10)

If C1 is the concentration of the carbonate salt formed, C1 is expressed mathematically by (11), C1 

CNaCl Ks   102 pH .

D K1 K 2 M n+

(11)

Where Ks is the carbonate salt solubility coefficient computed in this work using Van’t Hoff law. |Mn+| is the concentration of incriminated metallic ion i.e. Ca2+/Mg2+, in mol/L. This work has defined a dissociative fraction “α“which expresses either the formation of carbonate salts or carbonic acid or both. Computed from (6) and (11), Figure 4 which predicts the behavior of CO2 in contact with mixture brine+ heavy crude at various stages of assumed acidity was sketched.

A

B

D issociation factor (-)

1.0

2% N aCl 4% N aCl 10% N aCl

0.8

C

Zone ofinterest

0.6

F

0.4

E

0.2

D

0.0 4

6

8

10

12

14

Assum ed cell/reservoir acidity,pH FIGURE 4. PREDICTIVE INDUCED CHEMISTRY IN HEAVY OIL + BRINE DURING CO2 INJECTION

5 distinct zones have been highlighted with of zone of interest found between a pH ranging from 8 to 11. In a low acidity (AB/ED), likely to be yielded in sour environment, salt carbonate formation, with low production of carbonic acid, is promoted however salts remain soluble during the gas injection process. As the medium moves towards alkalinity, scale deposition is expected (BC) which is enhanced by carbonic acid formation (DC); effect strengthened with a strong basicity (CF).

CO2 Solubility and Gas‐Oil Ratio (GOR) Analyses Prior CO2 injection, the hydrocarbon mixture acidity was measured and found to be 6.78. Based upon predictive analysis, Figure 5a that depicts CO2 solubility in various heavy oil + brine solutions has been plotted. Salinity, taken

Experimental Investigation of Brine Hardness and Its Induced Chemistry during Heavy Crude Recovery through CO2 Injection 65

alone i.e. 2% NaCl, was found to have a less impact on solubility. As the amount of metal ion (Ca2+) grows, Rswas altered; this was found to be counter‐balanced with the presence of Mg2+. However, the bubble point‐pressure remained unchanged regardless brine composition.

50

8

6

40

Rs,m m olCO 2/g-FIP*

4

30

2

0 0

20

1

2

3

4

10

0 3

4

5

6

7

8

9

10

Equilibrium Pressure,M Pa

CO 2 solubility in brine-free m edium CO 2 solubility in 2% N aCl(pH =9.4) CO 2 solubility in 4% N aCl(pH =10.2) CO 2 solubility in 10% N aCl(pH =10.2) Computed from EOS

FIGURE 5A. CO2 SOLUBILITY IN VARIOUS HEAVY OIL+ BRINE MIXTURES ANALYSIS.

GOR9.08MPa = 2.8980

G as-O il-Ratio,m 3 CO 2 injected/m 3 FIP*

3.5 3.0

G O R in 2% N aCl@ 3.20 M Pa G O R in 4% N aCl@ bubble point-pressure G O R in 10% N aCl@ 9.08 M Pa

2.5

GOR7.51 MPa = 1.8551

2.0 1.5

GOR3.20 MPa = 0.5855

1.0 0.5 0.0

8.0

8.5

9.0

9.5

10.0

10.5

11.0

Assum ed Cell/Reservoir Acidity FIGURE 5B. GAS‐OIL RATIO ANALYSIS.

Gas oil ratio (GOR), which defines the amount of gas that dissolved in a fixed volume of fluid, has been depicted in Figure 5b at the zone of interest. Apparent GOR was computed for different types of brine solutions without accounting any induced chemistry. Illustrated in Figure 5b by the dotted line GOR was found to decrease with the

66 Ronald Nguele, Kyuro Sasaki, Yuichi Sugai, Hikmat Said‐Al Salim, Mohammad Reza Ghulami and Masanori Nakano

increase of alkalinity. At low saline medium, in which carbonic acid formation is predominant, alteration of oil recovery is fairly low. This is imputed to the weakness of H2CO3. As concentration of metal ions builds up, the mutual solubility of hydrocarbon‐water is further reduced, thus GOR. Both carbonate salts and carbonic acid formation enhance this effect.

Conclusions CO2‐EOR is influenced by various factors. From a chemical point of view, this research believed that both salinity and brine hardness should be regarded as parameters that may impact such EOR technique. Based upon experimental data and predictive chemistry imputed to gas injection, two major points has been drawn and discussed as below: (1) CO2 solubility is effective in heavy oils. Regardless its large viscosity contrast revealed, the low bubble point‐ pressure found suggests that CO2 could be a promising and viable displacing agent.

(2) Salinity has a less impact to Gas –Oil Ratio (GOR) when concentration in metal ions is negligible. However, any further build‐up is believed to decrease drastically GOR, thus recovery efficiency.

ACKNOWLEDGEMENTS

The authors would like to extend the gratitude towards JAPEX, which has kindly supplied raw crude oils for this study.

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