Natural Gas Properties

In the Productive Series of the Apsheron Peninsula and Archipelago, the crude oil is accompanied by natural gas (mainly hydrocarbons), either dissolved, forming gas caps, or accumulating in the form of independent gas or gas-condensate pools (sometimes in secondary traps above). The discovery in 1961-1962 of large gas and gas-condensate accumulations in the Dzhanub Prospect has considerably increased the gas potential of this region.

The northwestern group of fields of the Apsheron Archipelago, excluding Dzhanub, is much poorer in gas reserves than the southeastern group. Gas accumulations have not been found at the Darvin Bank, Pirallaghi Adasi or Gyurgyan Deniz fields. Most of the gas is apparently dissolved in the oil, and a small gas cap was present only in the Kirmaku Suite in the eastern flank of the Darvin Bank Field before development (see Figure 7-7).

The Dzhanub Gas Field is located southwest of the Chalov Adasi Oil Field (see Figure 6-11). Its discovery completely supported the concept of gas occurrence on the submerged portions of the anticlinal trends of the Apsheron Archipelago, proposed by Samedov and Buryakovsky (1961). The number of productive zones here reaches six (units V and VI of the Balakhany Suite, and the NKP, KS, PK, and KaS suites), and the contours of gas-bearing rocks expand downward. Gas flows obtained in the wells indicate the presence of large reserves.

In the crestal portion of the northwestern flank of the Chalov Adasi Oil Field, two exploratory wells have revealed the presence of a thick gas cap, restricted to the basal parts of the Kala Suite. Gas production reached 100 to 500 Mcmd (3,530 to 17,650 Mcfd), with a wellhead pressure of 10-20 MPa. The other units of KS, PK, and KaS suites do not contain gas caps, but gas is dissolved in oil: the gas/oil ratio (GOR) reaches 50-90 m /ton. The gases of the individual units of Chalov Adasi Field have a similar composition and differ from the gases of Neft Dashlary Field in a smaller content of heavy hydrocarbons (26 and 40 g/m , respectively). Characteristics of the gases of Chalov Adasi Field are presented in Table 7-22.

In the Palchygh Pilpilasi Oil Field, the gas flows from the PK suite and KaS5 unit in the crestal parts of anticline indicate the presence of gas caps in these reservoirs.

It has been shown that the unit KaS3 on the southwestern flank of the Neft Dashlary Oil Field contains only gas and, possibly, an insignificant oil fringe. In the crestal portion of the unit KaS2 of the same field, a gas cap is present. In the other units, especially in the plunge of anticline, gas caps are also present. A significant amount of natural gas is dissolved in the oil; according to the data from downhole oil

samples, the solubility factor is on the average 0.46 cm /cm per 1 atm of differential pressure. The GOR varies over a wide range from 10

Table 7-22

Composition of Gas from the Chalov Adasi Field

Gas Composition, Vol %

Unit or Suite

Density, Content of C5", Methane Ethane Propane Butane C+ CO2 g/cm3 g/m3

PKi pk2

KaS

87.8 83.8 88.0

1.74 0.12 0.06 0.12 9.8 0.6592 2.59 0.16 0.16 0.74 12.6 0.7084 2.26 0.37 0.48 0.93 7.8 0.6718

4.46 28.7 35.9

to 1,000 m /ton. (For gas composition at the Neft Dashlary Field see Table 6-2.)

The overall pattern in the distribution of gas saturation in the reservoirs of the Apsheron oil- and gas-bearing region is the increase in the relative amount of gas and the replacement of the oil accumulations by oil-gas and gas-condensate types in the direction of submergence of the anticlinal trends (from northwest to southeast), which is associated with a decrease in the crude oil densities in this direction. Consequently, the potential of Apsheron Archipelago, and especially its southeastern continuation, is increasing as a region with significant gas reserves.

For the natural gases associated with crude oil, linear relationships have been developed empirically between the density and the contents (% by volume) of methane (CH4) and carbon dioxide (CO2) (Figure 7-30):

The accuracy of these formulae has also been established in the fields of other regions of the Former Soviet Union. This was done on the basis of 71 gas analyses from 14 fields. These formulae have received wide acceptance.

Using the CH4 and CO2 contents of gas (% by volume), the content of C 2+ hydrocarbons (ethane and heavier) can be found according to the following formula:

Figure 7-30. Relationships between the specific gravity of gas (compared to air) and the contents of CH4 and CO2.

The content of heavier hydrocarbons (C+) in g/m3 can be calculated from the volume percents of C+ using the following formula:

If the gas contains no foreign admixtures, then, knowing its density (specific gravity), a rough determination of gas composition can be made using these formulae.

Formation Water Properties

The formation waters of the Productive Series of the Apsheron oil-and gas-bearing region, are those of the South Caspian Basin. There is a very slow movement of formation waters from the more submerged parts of the basin toward the higher parts, where discharge zones are located (Samedov and Buryakovsky, 1966).

In the Productive Series, the formation waters are predominantly of the sodium bicarbonate type. These waters are typical of all units of the Lower Productive Series and of certain (lower) units of the Upper Productive Series. The waters from the Upper Productive Series have high total salinity and are of calcium chloride and magnesium chloride types. Tables 7-23 and 7-24 illustrate total salinity and chemical composition of formation waters from the fields of Apsheron Peninsula and Apsheron Archipelago, respectively.

According to Chilingar (1957) the relationship between the chemical composition of Apsheron Peninsula waters and the stratigraphic depth is subject to the following rules:

1. The water salinity decreases with the stratigraphic depth (also see Rieke and Chilingarian, 1974, pp. 265-269; Samedov and Buryakovsky, 1966).

2. Cl-, Ca2+, and Mg2+ contents decrease with depth.

3. (Na+ + K+) and (HCO- + CO32- + H+ + K+) contents gradually increase with depth.

4. The transition from hard to alkaline water occurs at a maximum concentration of not exceeding 100 mg-equ per 100 g of water (50-65 g/l). As a rule, the water is hard at concentrations above 100 mg-equ.

5. The HCO3 content (in mg-equ) does not exceed the Cl- content (A1 < S1).

6. Usually, the water does not contain SO42- anion. If present, however, its concentration does not exceed 0.4 mg-equ per 100 g of water.

Mekhtiev (1956, in: Rieke and Chilingarian, 1974, p. 265) also showed that in the Azerbaijan oil fields water salinity decreases with stratigraphic depth, and calcium-chloride water [(r Cl- - rNa+)/rMg2+ > 1, where r = percent equivalent] is gradually replaced by bicarbonate water [(rNa+ - r Cr)/rSO4!- > 1]. For magnesium chloride type of water: [(r Cl- - rNa+)/rMg2+ < 1]. For details on classification of waters, see Chilingar (1956, 1957, 1958), Samedov and Buryakovsky (1956, 1966), and Buryakovsky (1974a).

The chemical composition and total salinity of the formation water regularly change areally and vertically in the section of individual

Table 7-23

Total Salinity and Chemical Composition of Formation Waters from Oil and Gas Fields of the Apsheron Peninsula

Anion (a) and Cation (c) Composition mg-equivalents/1 OOg water

Table 7-23

Total Salinity and Chemical Composition of Formation Waters from Oil and Gas Fields of the Apsheron Peninsula

Anion (a) and Cation (c) Composition mg-equivalents/1 OOg water

Unit or Suite

Average Depth, m

Total Salinity, g/i

ci-

SOf

HCO-+CO-

Ca++

Mg+

Na++K+

X(a+c) mg-equ

so4

Cl-Na Mg

Ça Mg

A

320

155

272.8

_

0.3

23.4

37.5

212.2

546

0.78

1.63

0.62

B

400

151

263.6

0.1

0.3

26.4

32.7

204.9

528

0.78

1.80

0.81

C

450

140

245.3

0.2

0.5

24.6

33.0

188.4

492

0.82

1.73

0.75

D

530

128

222.0

0.1

0.9

25.0

15.8

182.2

446

0.84

2.52

1.58

I

560

124

215.7

0.1

0.7

22.8

12.1

181.6

433

0.82

2.82

1.88

II

610

129

225.1

0.1

0.3

19.0

23.2

183.3

451

0.82

1.81

0.82

III

675

127

222.4

0.2

0.9

20.3

21.5

181.7

447

0.82

1.89

0.95

IV

725

117

294.6

0.2

1.1

21.8

15.9

168.3

412

0.82

2.28

1.37

IVa

750

116

201.0

0.1

2.3

21.5

15.1

166.9

407

0.83

2.24

1.42

IVb

770

111

191.4

0.2

2.2

17.1

14.0

162.8

388

0.86

2.22

1.22

IVcd

790

72

129.9

0.1

4.6

3.0

7.0

125.0

270

0.97

0.7

0.43

IVe

810

60

98.3

0.1

5.9

1.3

3.0

100.7

210

1.02

24.0

0.43

V

860

57

92.6

0.1

6.6

1.0

2.1

96.9

200

1.04

42.0

0.49

VI

920

45

68.6

0.1

9.7

0.3

0.6

78.1

158

1.13

95.0

0.50

VII

960

40

58.4

0.1

10.7

0.4

0.5

68.6

139

1.17

102.0

0.80

VII

1,030

38

54.1

0.1

12.0

0.1

0.2

66.2

133

1.23

121.0

0.50

IX—X

1,100

36

51.2

0.2

11.8

0.1

0.2

63.2

127

1.23

60.0

0.50

Pereryv"

1,250

40

56.8

0.1

11.8

0.1

0.5

68.4

138

1.20

116.0

0.20

NKG

1,350

44

67.6

0.1

10.0

0.2

0.3

77.5

156

1.14

99.0

0.70

NKP

1,400

36

54.3

0.2

7.8

0.2

0.3

62.0

125

1.14

38.5

0.70

KS

1,570

20

25.9

0.1

8.7

0.1

0.2

34.7

70

1.34

88.0

0.50

PK

1,740

9

8.6

0.3

7.2

0.1

0.2

16.2

33

1.88

25.3

0.50

KaS

2,630

13

12.7

0.5

8.9

0.1

0.2

22.2

45

1.71

19.0

0.50

structures. With depth, the total water salinity decreases, whereas the alkalinity increases depending both on the stratigraphic and topographic position of the suite (Tables 7-23, 7-24, and 7-25).

Differences in water salinity between adjacent units are not distinct, but are more or less gradual from unit to unit. The individual units are distinguished mainly by the average values. Overlap in water salinity of individual units may be due to lithology, grain-size, and mineralogic composition of the rocks. The total water salinity increases with increasing content of clay minerals in rocks. This is possibly due to a decrease in permeability of the reservoir rocks with increasing clay content, resulting in slow water exchange and an increase in stagnation.

There is a general trend of decreasing salinity of produced water with time, probably due to the influx of fresher water from the shales into associated sandstones. Upon initiation of waterflooding, however, this trend becomes obscure due to mixing of injection and formation waters.

In the Apsheron Archipelago, there is a decrease in total water salinity on moving from the uplifted structures to the deeper ones. Within the northwestern group of fields (through all the units of the Kirmaku and Podkirmaku suites) the formation waters move from the central field of Pirallaghi Adasi to the peripheral fields of Darvin Bank and Gyurgyan Deniz. For the southeastern part of the archipelago, it is assumed that the fields of Neft Dashlary and Palchygh Pilpilasi are central, whereas the Chalov Adasi and the Gyuneshli structures are peripheral. This may indicate a marked stagnation of formation waters in the central uplifted structures of the anticlinal trends, which may have contributed to an increase in the total water salinity. Table 7-26 shows this trend using the total salinity of formation waters.

The formation water on the southwestern flanks of all the structures is less mineralized than that on the northeastern flanks. This suggests that the general direction of water movement is from the southwestern to the northeastern flanks, along the regional rise of the structures. This regularity is shown in Table 7-27 using the total salinity of formation waters.

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