Iran condensate product list

Iran condensate product list

Condensate products in a subterranean formation may not flow through the subterranean formation to the location of a recovery well. Although the hydrocarbons may be poorly flowing for different reasons, frequently, gas injection aids the recovery of these poorly flowing hydrocarbons. A hydrocarbon may be too viscous to flow in the subterranean formation, for example, because it is a heavy crude that is not hot enough to flow easily through the subterranean formation. Injection of hot gas can then be used to decrease the apparent viscosity of the hydrocarbons in the subterranean formation. For example, steam, at elevated temperature, is frequently injected to liquify heavy crudes (those having an api gravity value less than 20°.) Other hydrocarbon products may not be under enough pressure in situ to force the hydrocarbons through the subterranean formation. Pressure can be insufficient either because the subterranean formation is not under much pressure naturally or, in the later stages of production, because the subterranean formation has lost pressure due to loss of a significant volume of hydrocarbons. Gas injection can be used to apply artificial pressure to force the hydrocarbon product through the subterranean formation.

An injected gas, for example, steam, is frequently augmented with a foaming agent. For example, it has been observed that steam tends to find channels of less resistance in the rock and by-pass hydrocarbons in the subterranean formation on its way to the production well. Since the function of the injected steam is to change the physical state of the hydrocarbon by heat transfer, techniques that allow the steam to remain in prolonged contact with the hydrocarbon product have been developed. One of these techniques is the addition of a foaming agent to the steam, which increases the apparent viscosity of the steam as it passes through the subterranean formation. Addition of the foaming agent slows the passage of the steam through the subterranean formation and increases contact with, and therefore heat transfer to, the hydrocarbons in the subterranean formation.

Gas injection without a foaming agent has also been used to increase the recovery of natural gas and gas condensate (natural gas that is liquid under the conditions of the subterranean formation.) In this application a gas that will not liquify under the conditions of the well, hereinafter a non-condensable gas, is injected into the subterranean formation containing the gas condensate. The injected gas maintains the pressure of the hydrocarbon product in the later stages of production. However, gas injection presents problems of maintaining continuous contact between the hydrocarbon product and the injected gas. Due to the relatively low viscosity of the injected gas and inhomogeneities in the subterranean formation, the injected gas will "finger" or flow through the paths of least resistance. Therefore, significant portions of the subterranean formation are bypassed, and the recovery well is subject to early break through of the injected gas. Moreover, due to the relatively lower density of the injected gas, it will frequently rise to the top of the subterranean formation and override the portions of the subterranean formation bearing the hydrocarbon product. In other words, the driving gas will bypass the product bearing portions of the subterranean formation either by channelling through portions of the subterranean formation already depleted of product, or the light driving gas will stratify in the formation and rise above the product. The result of either event is that the product is not pushed, and the producing well yields little of the desired driven product gas and instead produces only large quantities of the injected driving gas. All of these factors may result in lowered hydrocarbon recovery.

Injected foam increases the apparent viscosity of an injected gas and improves the efficiency of a gas flooding process. However, although foam has been used in conjunction with a driving gas in wells producing heavier product, it has not been used with natural gas or gas condensate. The reason is that in the case of natural gas (c1 to c12) being driven by a light driving gas such as methane, the driving gas and the driven gas are more nearly the same density than in the case of driving a very heavy crude oil with steam. Therefore, it has been believed that foam could not act as an effective barrier because the foam would not maintain its structure as the driving gas and the driven gas crossed the foam barrier.

Condensate gas product list from iran petrochemical and refineries

 

National iranian oil company (nioc)

 

Research institute of petroleum industry (ripi)

 

Crude oil and petroleum products evaluation department

 

Southern pars 1 condensate

 

Table 1: condensate general properties analysis

 

Characteristics

Units

Result

 

Test method

           

Specific gravity @ 15.56 /15.56 °c

---

0.7384

   

Astm d4052

           

Api gravity

°api

60.1

   

Astm d4052

           

Sulfur content (total)

Wt.%

0.25

   

Astm d4294

           

H2s content

Ppm

3

   

Uop 163

           

Mercaptan content

Wt.%

0.13

   

Uop 163

           

Nitrogen content (total)

Ppm

<10

   

Astm d4629

           

Water content

Ppm

<0.025

   

Astm d4006

           

Salt content

P.t.b

<1

   

Astm d3230

           

Pona analysis:

         
           

*saturate

Vol.%

88.9

     
         

Astm d1319

Olefins

Vol.%

0.8

   
     
           

Aromatics

Vol.%

10.3

     
           

Kinematic viscosity @ 0 °c

Mm2 /s

1.097

     
           

Kinematic viscosity @ 10 °c

Mm2 /s

0.984

   

Astm d445

           

Kinematic viscosity @ 20 °c

Mm2 /s

0.836

     
           

Cloud point

°c

-30

   

Astm d2500

           

Pour point (upper)

°c

<-45

   

Astm d97

           

Reid vapor pressure

Psi

9.70

   

Astm d5191

           

Wax content

Wt.%

0.30

   

Bp 237

           

Corrosion copper strip (3h/50°c)

---

1b

   

Astm d130

           

Total acid number

Mg koh/g

0.10

   

Astm d 664

           

Aniline point

°c

60

   

Ip2

           

Molecular weight

G/mol

124

   

Osmomat

           

Saybolt color

---

22.5

   

Astm d156

           

Bromine index

Mgbr2/100g

867

   

Ip 130

           

Lead content

Mg/kg

<1

   

Astm d 5863

         

*s: saturate= paraffin+naphthene

Sampling date: 17 mordad 1394 (08 aug. 2015)

 

Report date: 24 shahrivar 1394 (15 sep. 2015)

 

 

National iranian oil company (nioc)

 

Research institute of petroleum industry (ripi)

 

Crude oil and petroleum products evaluation department

 

Southern pars 1 condensate

 

Table 2: tbp distillation analysis (astm d2892)

Frac. No.

Boiling range, °c

Yield, wt.%

Cumulative

Sp.gr. @

Yield, vol.%

Cumulative

 

Yield, wt.%

15.56/15.56 °c

Yield, vol.%

 
         
               

1

Ibp-15

4.37

4.37

0.5846

5.52

5.52

 
               

2

15-65

15.33

19.70

0.6442

17.57

23.09

 
               

3

65-100

18.70

38.40

0.7231

19.10

42.19

 
               

4

100-125

11.94

50.34

0.7445

11.84

54.03

 
               

5

125-150

10.60

60.94

0.7642

10.24

64.27

 
               

6

150-175

9.30

70.24

0.7782

8.82

73.09

 
               

7

175-200

7.35

77.59

0.7875

6.89

79.98

 
               

8

200-225

6.10

83.69

0.8015

5.62

85.60

 
               

9

225-250

4.97

88.66

0.8188

4.48

90.08

 
               

10

250-275

3.38

92.04

0.8290

3.01

93.09

 
               

11

275-300

2.46

94.50

0.8351

2.18

95.27

 
               

12

300-325

2.06

96.56

0.8545

1.78

97.05

 
               

13

325+

3.44

100.00

0.8610

2.95

100.00

 
               

 

National iranian oil company (nioc)

 

Research institute of petroleum industry (ripi)

 

Crude oil and petroleum products evaluation department

 

Southern pars (2 & 3) condensate

 

Table 1: condensate general properties analysis

 

Characteristics

Units

Result

Test method

 
         

Specific gravity @ 15.56 /15.56 °c

---

0.7371

Astm d4052

 
         

Api gravity

°api

60.5

Astm d4052

 
         

Sulfur content (total)

Wt.%

0.28

Astm d4294

 
         

H2s content

Ppm

<1

Uop 163

 
         

Mercaptan content

Wt.%

0.21

Uop 163

 
         

Nitrogen content (total)

Ppm

<10

Astm d4629

 
         

Water content

Ppm

<0.025

Astm d4006

 
         

Salt content

P.t.b

<1

Astm d3230

 
         

Pona analysis:

       
         

*saturate

Vol.%

90.0

   
     

Astm d1319

 

Olefins

Vol.%

1.0

 
   
         

Aromatics

Vol.%

9.0

   
         

Kinematic viscosity @ 0 °c

Mm2 /s

1.114

   
         

Kinematic viscosity @ 10 °c

Mm2 /s

0.955

Astm d445

 
         

Kinematic viscosity @ 20 °c

Mm2 /s

0.830

   
         

Cloud point

°c

-30

Astm d2500

 
         

Pour point (upper)

°c

<-45

Astm d97

 
         

Reid vapor pressure

Psi

9.50

Astm d6191

 
         

Wax content

Wt.%

0.50

Bp 237

 
         

Corrosion copper strip (3h/50°c)

---

1b

Astm d130

 
         

Total acid number

Mg koh/g

0.06

Astm d 664

 

 

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