gas-condensate

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