PHYSICAL PROPERTIES OF OIL AND PERMEABILITY OF RESERVOIR A-X OF THE SOUTH CHEREMSHAN FIELD

L. A. Pukhlyakov, G. N. Chertenkova

(Presented by Professor A. V. Aksarin)

The oil pool of the South Cheremshan field of Tomsk Oblast is confined to reservoir A-X (Kiyalin suite). The reservoir pressure in it is equal to 222.7 atm, and the reservoir temperature is 73°C. The oil of this field for investigation of its physical properties was taken from well 335 (perforation interval 2170—2180 m) and delivered to the reservoir-physics laboratory of the Tomsk Polytechnic Institute in containers. The study was carried out on the UIPN-2M installation for investigating reservoir oils, according to the procedure set forth by V. N. Mamuna et al. [1].

In terms of its physical properties, the oil of the South Cheremshan field differs somewhat from the oils of other fields in Tomsk Oblast. In particular, its gas content is among the lowest and, when referred to unit volume, is equal to 40.93 cm³/cm³.

The saturation pressure is also rather low—61 atm (Table). Of the Tomsk Oblast oils studied by the authors, none has such a low saturation pressure. A lower saturation pressure was obtained by V. V. Chertov and his colleagues for the oil of the Veselovskoye field (55 atm); however, this field is located in Novosibirsk Oblast. Usually the lower limit of this parameter for oils of Tomsk Oblast lies at the level of 73 atm—the Klyuchevskoye field [6]—or 74 atm.

The formation volume factor, 1.247 (Table 1), is also rather low for the oil of the South Cheremshan field. This parameter is lower only for the oil of the Klyuchevskoye field—1.221 [6]—and the Sredne-Nyurolskoye field—1.177. In the oils of other fields it is higher. For example, in the oil of the Luginetskoye field it is 1.297.

The specific gravity of the degassed oil of the South Cheremshan field, 0.835 g/cm³ (Table 1), is approximately the same as that of oils from other fields of Tomsk Oblast. More precisely, its value occupies an intermediate position between the lowest and highest values of this parameter.

The compressibility coefficient of the oil of the South Cheremshan field, as with oils of other fields, does not remain constant. It increases as the pressure approaches the saturation pressure (Table 2). Its average value is equal to 12.31 · 10⁻⁵ 1/atm.

As a result of staged degassing of the oil of the South Cheremshan field, it was established that the main mass of associated gases

Table 1

Basic physical properties of oil from the South Cheremshan field
(well 335, horizon A—X, perforation interval 2170—2180 m)

begins to be liberated at 32 atm, and at 22 atm about half of it is liberated, as is seen in the example of degassing of the first sample (Table 3). The results of degassing of the second sample are analogous and therefore are not given in the article.

The composition of the associated gas liberated during single-stage degassing of oil from the South Cheremshan field remains approximately the same as in oils from other fields of Tomsk Oblast. The proportion of methane in it is relatively small and amounts to 41,7 volume percent. In second place is propane—the average content is 20,8 volume percent; in third place is normal butane

Table 2

Oil compressibility coefficient of the South Cheremshan field

—10.1 volume percent. The proportion of ethane is relatively small—7.5 volume percent (Table 4).

The authors devoted special attention to investigating the viscosity of the oil. First, completely non-degassed oil was studied (Table 5), and then partially degassed oil. Degassing was carried out first at a pressure of 60 atm, then at a pressure of 20 atm and, finally, at a pressure of 10 atm (Table 6). Viscosity was determined at pressures of 222.7 atm (reservoir pressure), 200 atm, 100 atm, and several others, and at temperatures of 20°C, 40°C, 60°C, and 73°C (reservoir temperature).

With changes in temperature and pressure, the viscosity of the oil of the South Cheremshan field changes approximately in the same way as the viscosity of oils of the Severnoye and Strezhevoye fields. As the temperature increases, it decreases in a regular manner (Tables 5 and 6). The phenomenon noted by the authors in studying the viscosity of the oil of the Klyuchevskoye field, which consisted in the fact that over a certain interval the viscosity of the oil did not decrease with increasing temperature but increased [2], was not observed here. However, comparing the viscosity values at temperatures of 60°C and 70°C, it is not difficult to see that

Table 3

Results of stepwise degassing of the first oil sample from the South Cheremshan field

Table 4

Composition of associated gas released from the oil of the South Cheremshan field as a result of single degassing

Table 5

Results of the study of the viscosity of oil from the South Cheremshan field in the non-degassed state

Table 6

Results of the study of the viscosity of oil from the South Cheremshan field in the partially degassed state

they are almost identical. Thus, the viscosity curves in this interval should be horizontal.

The authors had previously established that, in terms of viscosity, partially degassed oils differ little from non-degassed oils and differ significantly from completely degassed oils, which was recommended for use in increasing the productivity of oil wells [3]. A similar phenomenon was also observed in the study of the viscosity of oil from the South Cheremshan field. Thus, oil degassed at pressures of 60 and 20 atm, at reservoir pressure (222,7 atm) and reservoir temperature (73°C), has even lower viscosity than non-degassed oil. Only after degassing at 10 atm does it acquire a viscosity somewhat higher than the viscosity of non-degassed oil.

The loss of gas has a much more pronounced effect on viscosity at a temperature of 20°C. Here each new partial degassing leads to a new increase in viscosity. Nevertheless, this increase is not at all comparable with the increase in viscosity produced by complete degassing. In fact, completely non-degassed oil at 20°C has a viscosity of 0,83 centipoise (Table 5), whereas oil degassed at 10 atm at the same temperature has a viscosity of 1,42 centipoise (Table 6). At the same time, completely degassed oil at 20°C has a viscosity of 4,97 centipoise (Table 1). Thus, in the first case (with partial degassing to 10 atm) the viscosity increased by a factor of 1,72, and in the second (with complete degassing)—by a factor of 3,5.

To determine the permeability of reservoir A-X of the South Cheremshan field, the following physical properties of the oil were used first of all: the formation volume factor, which proved to be 1.247; oil compressibility, \(12.31 \cdot 10^{-5}\ 1/\text{atm}\); and the viscosity of degassed oil under reservoir conditions, which proved to be 0.695 centipoise; as well as data obtained by the well-testing crew during inflow stimulation: 1) in the first operating regime (choke diameter 5 mm), bottomhole pressure 216.7 atm, inflow under surface conditions \(62\ \text{m}^3/\text{day}\); 2) in the second regime (choke diameter 8 mm), bottomhole pressure 209.5 atm, inflow \(141\ \text{m}^3/\text{day}\); 3) in the third regime (choke diameter 10 mm), bottomhole pressure 204.1 atm, inflow \(200\ \text{m}^3/\text{day}\); 4) in the fourth regime (choke diameter 8 mm), bottomhole pressure 209.7 atm, inflow \(140\ \text{m}^3/\text{day}\); 5) in the fifth regime (choke diameter 5 mm), bottomhole pressure 216.7 atm, inflow \(63.7\ \text{m}^3/\text{day}\). The thickness of the exposed part of the reservoir is 1000 cm (10 m). The bit diameter is \(7\frac{3}{4}\) inches (190 mm); hence the well radius before running the casing string \((r)\) is 9.5 cm. The number of openings in the specified interval is 150; the radius of an opening is 0.5 cm; the depth of the channel at an opening, \(y\), is taken as zero. The well drainage radius \((R)\) is taken as 10000 cm (100 m).

The calculation was performed using the previously derived formulas [5]

\[ P_{\text{pl}} - P_{\text{zab}} = \frac{Q_{\text{pl}}\mu}{2\pi k n}\,(G_{\lambda s} + G_R), \tag{1} \]

where \(P_{\text{pl}}\) and \(P_{\text{zab}}\) are the reservoir and bottomhole pressures in atm; \(\mu\) is the oil viscosity under reservoir conditions, in centipoises; \(k\) is the reservoir permeability in darcies; \(n\) is the number of openings in the casing string; \(Q_{\text{pl}}\) is the oil inflow into the well under reservoir conditions, determined by the formula

\[ Q_{\text{pl}} = \frac{1000000\,Q_{\text{pov}}\,b}{86400} \tag{2} \]

\(b\) is the oil formation volume factor, equal to 1.247,

\(G_{\lambda s}\) is the geometrical characteristic of the zone of influence of the openings, determined by the formula

\[ G_{\lambda s} = \frac{1}{y}\ln\frac{(y+\lambda)s}{(y+s)\lambda} - \frac{0.25}{r+y}\ln\frac{s+y}{\lambda+y} + 0.0625\,\frac{s-\lambda}{(r+y)^2} \tag{3} \]

where \(y\) is the depth of the channel at the opening, in cm; \(\lambda\) is the radius of the opening and of the channel at it, in cm; \(r\) is the well radius before running the casing string, in cm; and \(s\) is the radius of influence of the openings, which, for high perforation density, is determined by the formula

\[ s = 0.5\sqrt{2\pi r\,\frac{h}{n}} \tag{4} \]

\(h\) is the thickness of the perforated part of the reservoir.

\(G_R\) is the geometrical characteristic of the plane-radial flow zone, determined by the formula

\[ G_R = \frac{n}{H}\ln\frac{R}{r+y+s} \tag{5} \]

where \(H\) is the total reservoir thickness in cm and \(R\) is the well drainage radius in cm.

This parameter in the first regime is calculated by the formula

\[ R^2 = \frac{2V}{\pi m \alpha H P_s}, \tag{6} \]

where \(V\) is the total volume of oil or other fluid withdrawn from the well during its testing in the first regime, in \(\text{cm}^3\); in our case, \(86978\) thousand \(\text{cm}^3\); \(m\) is the reservoir porosity as a fraction of unity; in our case ...

case 0.19, \(\alpha\) is the compressibility of oil or another fluid in \(1/atm\), \(P_s\) is the drawdown on the formation at the outer boundary of the zone of influence of the openings, determined by the formula

\[ P_s = (P_{\text{pl}} - P_z)\frac{G\lambda_s}{G\lambda_s + G'_s}. \tag{7} \]

For the second, third, and subsequent regimes, the radius of influence of the well is calculated by the formula

\[ R^2 = 2.25\chi t, \tag{8} \]

where \(\chi\) is the piezoconductivity of the formation, determined from the data for the first regime, and \(t\) is the time of well operation in the given regime.

As a result of calculation by formula (2), the following oil inflows under reservoir conditions were obtained: in the first regime, \(894.84\ \text{cm}^3/\text{s}\); in the second regime, \(2035.035\ \text{cm}^3/\text{s}\); in the third regime, \(2886.57\ \text{cm}^3/\text{s}\); in the fourth regime, \(2020.605\ \text{cm}^3/\text{s}\); and in the fifth regime, \(919.38\ \text{cm}^3/\text{s}\).

The results of the remaining calculations are summarized in Table 7.

Table 7

Results of determining the permeability of reservoir A—X of the South Cheremshan oil field from inflows at steady-state regimes

The average permeability over all regimes is 228.9 millidarcies.

Next, in accordance with the procedure [5], the permeability of the unclayed zones remote from the bottomhole, \(k_{\text{nz}}\), was determined. As the initial data, the average effective permeabilities for the first three and last two regimes, 226.2 and 232.9 millidarcies, and the corresponding sums of geometric characteristics, 2.0071 and 2.0466 \(1/\text{cm}\), were taken. After substitution into the corresponding formula they gave

\[ k_{\text{nz}} = \frac{232.9 \cdot 2.0466 - 226.2 \cdot 2.0071}{2.0466 - 2.0071} = \frac{22.647}{0.0395} = 573.3\ \text{mD}. \tag{9} \]

Thus, because of clay invasion during perforation, the permeability of the formation decreased by a factor of 2.505.

LITERATURE

1. V. N. Mamuna, G. F. Trebin, B. V. Ulyanskii. Experimental study of reservoir oils. GOSINTI, 1960.

2. L. A. Pukhlyakov, G. N. Chertenkova. On the viscosity of oil from the Klyuchevskoye field of Tomsk Oblast under reservoir conditions. Izvestiya TPI, vol. 218, 1970.

3. L. A. Pukhlyakov, G. N. Chertenkova. A new method for increasing the productivity of oil pipelines. Izvestiya TPI, vol. 217, 1971.

4. L. A. Pukhlyakov. Determination of formation permeability from inflows into a well at steady-state regimes. Izvestiya TPI, vol. 177, 1971.

5. L. A. Pukhlyakov. Procedure for determining formation permeability in unclayed zones from the results of investigation of a well at steady-state regimes. Information sheet No. 100–74. Tomsk Interbranch Territorial TsNTI, 1974.

6. G. N. Chertenkova. Compressibility coefficient and volumetric coefficient of oil from the Klyuchevskoye field of Tomsk Oblast. Izvestiya TPI, vol. 218, 1970.