Determination of Enhanced Oil Recovery Candidate Fields in the Volga-Ural Oil and Gas Region Territory

Abstract

Most of the current Russian oil production comes from mature fields. The application of enhanced oil recovery methods on oil fields increases recovery efficiency. This article presents an analysis of the increased field development efficiency methods of the Volga-Ural oil and gas region, which allows the full and efficient development of last-stage fields with unconventional reserves and production stabilization. The selection of the optimum method for a given field is a complex procedure consisting of many stages, from collecting data about the field, through more advanced data interpretation, to working out a detailed proposal for the most efficient extraction method. In this article the instantaneous and average annual growth above wells average was taken as a performance criterion for enhanced oil recovery methods. Based on the performed analysis, it follows that candidate wells for enhanced oil recovery method use must meet the I group parameters (high values of the remaining recoverable reserves and improved reservoir properties, low water cut, obtained oil rate increase). In order to assess the possible increase in production rate after enhanced oil recovery methods hydrodynamic modeling of radial drilling, acid treatment and water-alternated-gas injection for two oil fields of the Volga-Ural oil and gas region were performed.

1. Introduction

Due to early production of most pay-out beds the oil reserves structure of Russian fields is experiencing negative qualitative changes. Unconventional oil share is nowadays 60% in total, whereof 71% comes from the Volgo-Ural and West-Siberian oil regions. Besides, fields related to these regions contain 60% of total Russian reserves of heavy oil (density more than 900 kg/m³). Nowadays the share of heavy oil is more than 23% of the total Russian production, whereof about 50% is produced in the Khanty-Mansiisk autonomous district [1,2].

It is considered that unconventional oil recovery technologies are divided into well, mine and quarry (while producing heavy oil more than 900 kg/m³ and bitumen, Table 1). Generally, existing field development technologies are not efficient and this causes undershoots of high oil recovery factor value [3,4].

The fields of the East part of the Volgo-Ural oil region are considerably different in terms of geological and physical pay-out beds parameters, fluid properties and reserves features, which as a rule hinder the choice of suitable enhanced oil recovery methods. According to the classification which is used in leading oil producing companies of the East part of the Volga-Ural oil and gas region such as LUKOIL and Rosneft enhanced oil recovery methods are considered to be divided into three groups: hydrodynamic (new well input, well shifts to other development objectives, etc.); production intensification methods (increased injectability of injection wells, down hole washing, perforation, etc.); physical (rat hole drilling, radial drilling, hydraulic fracturing, acid hydraulic fracturing, etc.) and chemical (repairing and isolation workovers, bottom-hole treatment, etc.). Unconventional oil in this region is considered oil with the following parameters: viscosity of wellbore oil of more than 30 mPa·s (Kudryavtsevskoye, Malo-Usinskoye, Moskudinskoye, Nozhovskoye, Etyshskoye) and an gas-oil ratio is more than 200 m³/ton (Krutovskoye, Magovskoye); permeability of less than 0.05 µm² (Aspinskoye, Dorohovskoye, Churakovskoye, Pavlovskoye) [5]. Field development of the East part of the Volgo-Ural oil region with wellbore oil viscosity of 100 mPa·s is characterized by oil recovery factors up to 0.30. Under these conditions there are relative objectives connected to evaluation of implementation efficiency of enhanced oil recovery methods, which allow the full and efficient development of last-stage fields with unconventional reserves and thus production stabilization [6,7,8].

Leading oil companies such as ExxonMobil, Royal Dutch Shell, BP and Chevron are financing modernization of existing enhanced oil recovery methods and actively implementing new approaches. The most widespread method in carbonate reservoirs is gas injection (permanent or cyclic). The number of gas injection operations under high pressure has been increased during the last 10 years (especially on the fields of the USA, which contain low-viscosity—less than 10 mPa·s—oil) [9,10]. The enhanced oil recovery methods implementation analysis which has been performed on East European oil fields with an average density value equal to 870–970 kg/m³, viscosity of 10–30 mPa·s, and low permeability of 0.1 µm² shows that thermal methods are implemented mostly on heavy oil reservoirs.

Table 1. Unconventional oil recovery technologies.

Production Technology	Description	Oil Recovery Factor, %	Application Features	Fields
CHOPS (Cold Heavy Oil Production with Sand)	Production of oil with sand by breaking weakly cemented collector and creating appropriate conditions for the movement of the oil and sand mixture in the formation [11]	up to 15	Not applicable for production of bitumen and on the fields with bottom water	Karajanbas, Lindbergh, Bodo, Duri
VAPEX (Vapor Extraction Process)	It involves the use of two horizontal wells. The injection of solvent into the upper well establishes the camera-solvent. Oil is diluted by diffusion and flows along the boundaries of the chamber to a producing well under the influence of gravitational forces	up to 60	Low energy costs, uncertainty in costs	Cold Lake, Peace River, Athabasca
Quarry development	Bitumen saturated rock is extracted by open method	up to 85	Reservoir depth is up to 50 m, after extracting rocks require additional work to obtain it from the hydrocarbons, capital and operating costs are low	Bemolanga, Syukeyevskoye, Spiridonovskoye, Vassilyevskoye, Fikov-Kolokskoye
Cleaning mine development	The rise of hydrocarbon saturated rock on the surface	up to 45	Reservoir depth is up to 200 m, a large amount of waste rock drivage is cost-effective only in case of the rare metals presence	Athabasca, Sunnyside, Tar Sand Triangle, PR Spring
SAGD (Steam-Assisted Gravity Drainage) [12]	Two closely-spaced horizontal wells, one above the other, form a steam-injector and producer pair. The reservoir oil is heated by the injected steam and drains to the producer under the effect of gravity	up to 60	Minimum heat loss, large energy expenditures [13]	Ashalchinskoye, Athabasca, Cold Lake, Asphalt Ridge
Thermal mining method	The reservoir warmed up to 60–80 °C. The production is made by wells drilled from the mine workings located at the bottom of the oil-saturated reservoir. Oil is pumped to the surface after preliminary separation of mechanical impurities and water	up to 50	Reservoir depth is up to 800 m	Yaregskoye, Lloydminster, Mordovo-Karmolskoye
Mine-well development	Drivage in rocks above the productive reservoir and vertical and deviated well pads are drilled into the reservoir for the oil accumulation in drivages	up to 10	Reservoir depth is up to 400 m, it requires a huge drivage through rocks that do not contain oil	Yaregskoye, Ashalchinskoye, Circle Cliffs

Table 1. Unconventional oil recovery technologies.

Production Technology	Description	Oil Recovery Factor, %	Application Features	Fields
CHOPS (Cold Heavy Oil Production with Sand)	Production of oil with sand by breaking weakly cemented collector and creating appropriate conditions for the movement of the oil and sand mixture in the formation [11]	up to 15	Not applicable for production of bitumen and on the fields with bottom water	Karajanbas, Lindbergh, Bodo, Duri
VAPEX (Vapor Extraction Process)	It involves the use of two horizontal wells. The injection of solvent into the upper well establishes the camera-solvent. Oil is diluted by diffusion and flows along the boundaries of the chamber to a producing well under the influence of gravitational forces	up to 60	Low energy costs, uncertainty in costs	Cold Lake, Peace River, Athabasca
Quarry development	Bitumen saturated rock is extracted by open method	up to 85	Reservoir depth is up to 50 m, after extracting rocks require additional work to obtain it from the hydrocarbons, capital and operating costs are low	Bemolanga, Syukeyevskoye, Spiridonovskoye, Vassilyevskoye, Fikov-Kolokskoye
Cleaning mine development	The rise of hydrocarbon saturated rock on the surface	up to 45	Reservoir depth is up to 200 m, a large amount of waste rock drivage is cost-effective only in case of the rare metals presence	Athabasca, Sunnyside, Tar Sand Triangle, PR Spring
SAGD (Steam-Assisted Gravity Drainage) [12]	Two closely-spaced horizontal wells, one above the other, form a steam-injector and producer pair. The reservoir oil is heated by the injected steam and drains to the producer under the effect of gravity	up to 60	Minimum heat loss, large energy expenditures [13]	Ashalchinskoye, Athabasca, Cold Lake, Asphalt Ridge
Thermal mining method	The reservoir warmed up to 60–80 °C. The production is made by wells drilled from the mine workings located at the bottom of the oil-saturated reservoir. Oil is pumped to the surface after preliminary separation of mechanical impurities and water	up to 50	Reservoir depth is up to 800 m	Yaregskoye, Lloydminster, Mordovo-Karmolskoye
Mine-well development	Drivage in rocks above the productive reservoir and vertical and deviated well pads are drilled into the reservoir for the oil accumulation in drivages	up to 10	Reservoir depth is up to 400 m, it requires a huge drivage through rocks that do not contain oil	Yaregskoye, Ashalchinskoye, Circle Cliffs

Chemical methods do not have significant potential use mainly because they are only implemented in highly permeable and highly porous layers. Use of these methods results in an increased economic cost, reduced profitability and additional oil production, especially in small field development [14,15,16]. Therefore, the most suitable are gas injection methods (mainly CO₂). It should be noted that the American experience with the technology is mainly due to the large area of fields and cannot be directly applied to the conditions of the East part of the Volga-Ural oil and gas region. In the case of method application at greater depths displacing agents may be replaced by nitrogen (N₂), which allows obtaining additional oil production. The applicability of the method is limited, mainly due to the high cost of the injected agent and the fact that small fields are far from the major producing areas and have a complex geological structure (significant heterogeneity), which leads to deviations from the project parameters [10,17].

2. Results and Discussion

2.1. Analysis of the Methods that Increase Field Development Efficiency on the Volga-Ural Oil and Gas Region

In 2008–2012 enhanced oil recovery methods have been actively used on the fields of the East part of the Volga-Ural oil and gas region, among which we can determine 22% hydrodynamic; 25% production intensification methods; 37% physical and 16% chemical approaches [18]. The efficiency criterion for enhanced oil recovery methods has taken instantaneous values (the difference between the flow rate of oil before and after the event) and the average annual (mean increase of oil for 12 months from the date of the event) above average growth in wells (Figure 1) [19]. As a consequence of the implementation of hydrodynamic methods in the Malo-Usinskoye region the field daily oil production rate gain of two wells was 40.9 and 31.2 tons. On the Pavlovskoye field production rates of seven wells have been increased on average by 3.4 t/day. As a result of enhanced oil recovery methods the average increase in daily oil production of unconventional reserve fields amounted to 8.13 t/day. The greatest number of operations was carried out on oil flow stimulation at the Pavlovskoye field with an average increase in oil production rate by 5.7 t/day. Using the acid composition agent DN 9010, consisting of a mineral acid, reaction inhibitor with the carbonate retarder reservoir component, homogenizing solvent, a corrosion inhibitor and surfactant, the additional oil rate was 20.7 t/day at the Nozhovskoye field (Figure 1). Physical methods implementation has allowed achieving an average proportion of daily oil production growth of 10 t/day, which is 2.4 times more, than chemical methods using (KARFAS reagent, including aluminium chloride, urea, sodium zeolite and water). Physical methods realization in clastic reservoirs (permeability is less than 0.05 µm²) according to this indicator was 2.5 times as effective, than in carbonates. The success of chemical methods on the fields of oil with viscosity of more than 30 mPa·s was three times higher than in fields with high gas-oil ratios. The efficiency of application of water shutoff technology in producing wells by using organosilicon reagents (AKOR complex mixtures of orthosilicic acid polyesters of varying degrees of polymerization and special additives) was 0.5 t/day, repair and insulation work −12.9 t/day, and an average increase of oil production was 5.6 t/day (Table 2). Fracturing is an effective enhanced oil recovery method in wells with low flow rates (up to 10 t/day), which allows and abrupt (and instantaneous) increase in the oil production rates of producing wells. The disadvantage in some cases is the short duration of the effect [20]. Sidetracking (horizontal wells)—is an effective method, especially in the development of unconventional oil reservoirs (an oil production increase by 11.8 t/day against the background of 134 well operations, each one with 300 m sidetrack in length). During the construction of sidetracking and directional wells rotary steerable systems are usually used to provide a given trajectory of the production well bore. Application of rotary steerable systems increases the rate of penetration and the quality of the well bore, reduces tortuosity, torsional and axial loads as well as the stick & slip phenomenon comparing with directional drilling using downhole motors. The use of rotary steerable systems allows longer drilling intervals with uniform well bore diameters, facilitating the descent of casing pipes.

Figure 1. Enhanced oil recovery methods efficiency on the field of the East part of the Volga-Ural oil and gas province (a) in carbonate reservoirs; (b) in clastic reservoirs.

Figure 1. Enhanced oil recovery methods efficiency on the field of the East part of the Volga-Ural oil and gas province (a) in carbonate reservoirs; (b) in clastic reservoirs.

Table 2. Enhanced oil recovery methods efficiency of the east part of the Volga-Ural oil and gas region fields.

Average Additional Oil Rate, t/day
Sidetrack	Hydraulic Fracturing	Acid hydraulic Fracturing	Average
11.8	13.1	10.9	11.2

Table 2. Enhanced oil recovery methods efficiency of the east part of the Volga-Ural oil and gas region fields.

Average Additional Oil Rate, t/day
Sidetrack	Hydraulic Fracturing	Acid hydraulic Fracturing	Average
11.8	13.1	10.9	11.2

Despite the fact that rotary steerable system may replace hydraulic downhole motors, the validity of their use in most cases can only be guaranteed with thorough well planning and by recording engineering-technical features.

2.2. Classification of Well-Candidates for the Use of Enhanced Oil Recovery Methods

Based on the analysis of enhanced oil recovery methods wells it is proposed to divide wells into three groups to select the influence method, according to the increases obtained, both instantaneous and average annual:

Group I—wells that have instant and average annual growth. Wells belonging to the group have high values of the remaining recoverable reserves and improved reservoir properties, low water cut, obtained oil rate increase, which is held at a stable level (Figure 2a);

Group II—wells which achieve an instant production increase, but did not reach the average. Flow rate is reduced to the original value, due to the presence of remaining recoverable reserves around the wells and low reservoir permeability in the remote zones (Figure 2b);

Group III—wells, which did not achieve instant and average annual growth rates, characterized by low values of the permeability remote formation zone, the remaining recoverable reserves, low reservoir pressure and high water cut after enhanced oil recovery methods (Figure 2c).

For each group well parameters were used to assess the effectiveness of diverse enhanced oil recovery methods (Table 3): production rate, permeability, the presence of residual recoverable reserves, the water cut (before enhanced oil recovery methods) [21,22].

Table 3. Allocated parameters of the wells to assess the effectiveness of enhanced oil recovery methods.

No.	Parameter	Group I		Group II	Group III
1	Oil production (t/day)	3.58–12.02 *	0–2.31	1.13–9.64	0.65–1.16	0–3.21
		6.31	2.15	4.03	0.92	2.12
2	Watercut (%)	12.1–25.7	0–36.1	9.4–31.1	35–49.4	0–34.1
		18.3	26.4	16.7	42.2	22.8
3	Net pay thickness (m)	3.1–5.1	4.4–9.3	3.8–6.1	3.1–4.4	2.2–6.2
		4.3	6.0	5.1	3.7	3.9
4	Reservoir pressure (MPa)	8.3–9.8	10.8–12.6	8.1–9.9	9.7–10.3	8.9–14.5
		8.9	11.8	9.1	10.0	11.0
5	Permeability (µm2)	0.045–0.278	0.011–0.042	0.018–0.072	0.001–0.003	0.002–0.060
		0.131	0.020	0.041	0.002	0.006

* Note: in the numerator of the change there is an interval value, in the denominator—the average value.

Table 3. Allocated parameters of the wells to assess the effectiveness of enhanced oil recovery methods.

No.	Parameter	Group I		Group II	Group III
1	Oil production (t/day)	3.58–12.02 *	0–2.31	1.13–9.64	0.65–1.16	0–3.21
		6.31	2.15	4.03	0.92	2.12
2	Watercut (%)	12.1–25.7	0–36.1	9.4–31.1	35–49.4	0–34.1
		18.3	26.4	16.7	42.2	22.8
3	Net pay thickness (m)	3.1–5.1	4.4–9.3	3.8–6.1	3.1–4.4	2.2–6.2
		4.3	6.0	5.1	3.7	3.9
4	Reservoir pressure (MPa)	8.3–9.8	10.8–12.6	8.1–9.9	9.7–10.3	8.9–14.5
		8.9	11.8	9.1	10.0	11.0
5	Permeability (µm2)	0.045–0.278	0.011–0.042	0.018–0.072	0.001–0.003	0.002–0.060
		0.131	0.020	0.041	0.002	0.006

* Note: in the numerator of the change there is an interval value, in the denominator—the average value.

Figure 2. The dynamics of production well technological parameters, where enhanced oil recovery methods were applied: (a) a group of Example I wells; (b) a group of Example II wells; (c) a group of Example III wells.

Figure 2. The dynamics of production well technological parameters, where enhanced oil recovery methods were applied: (a) a group of Example I wells; (b) a group of Example II wells; (c) a group of Example III wells.

Based on the performed analysis, it follows that in order to implement enhanced oil recovery methods well-candidates must meet the Group I requirements (Figure 2a).

3. Experimental Section

3.1. Geological and Physical Conditions of Enhanced Oil Recovery Methods Modeling

To estimate enhanced oil recovery methods using hydrodynamic modeling two carbonate reservoirs have been selected (Figure 3). Geological and physical characteristics of the objects are listed in Table 4.

Figure 3. Geological map of selected fields. UKD—The Upper-Kama depression; PA—Perm anticline; BA—Bashkir anticline; 1—Kliegopskaya shaft shaped zone; 2—Nozhovskiy protrusion; 3—Kuedinskiy shaft; 4—Moskudinskiy shaft; 5—Dubovogorskaya terrace.

Figure 3. Geological map of selected fields. UKD—The Upper-Kama depression; PA—Perm anticline; BA—Bashkir anticline; 1—Kliegopskaya shaft shaped zone; 2—Nozhovskiy protrusion; 3—Kuedinskiy shaft; 4—Moskudinskiy shaft; 5—Dubovogorskaya terrace.

Table 4. Geological and physical characteristics of selected objects.

No.	Parameter	Field No. 1	Field No. 2
1	The average depth of the roof (m)	933	1613
2	Average reservoir thickness (m)	4.2	6
3	Porosity, etc. units	0.162	0.132
4	Permeability (µm2)	0.123	0.0515
5	Net-To-Gross ratio, fr.units	0.27	0.389
6	Coefficient of compartmentalization, fr.units	4.3	8.28
7	Initial reservoir pressure (MPa)	10.5	16.9
8	Oil viscosity at reservoir conditions (mPa·s)	6.38	48.8
9	Oil density at reservoir conditions (t/m3)	0.852	0.914
10	Oil density at surface conditions (t/m3)	0.869	0.915
11	The altitude of oil-water contact (m)	−853	−1422
12	Oil Saturation pressure (MPa)	8.35	9.9
13	Gas content (m3/t)	29.6	8
14	Average total thickness (m)	15.8	25
15	Oil formation volume factor, share	1.067	1.011
16	Water viscosity at reservoir conditions (mPa·s)	1.57	1.51

Table 4. Geological and physical characteristics of selected objects.

No.	Parameter	Field No. 1	Field No. 2
1	The average depth of the roof (m)	933	1613
2	Average reservoir thickness (m)	4.2	6
3	Porosity, etc. units	0.162	0.132
4	Permeability (µm2)	0.123	0.0515
5	Net-To-Gross ratio, fr.units	0.27	0.389
6	Coefficient of compartmentalization, fr.units	4.3	8.28
7	Initial reservoir pressure (MPa)	10.5	16.9
8	Oil viscosity at reservoir conditions (mPa·s)	6.38	48.8
9	Oil density at reservoir conditions (t/m3)	0.852	0.914
10	Oil density at surface conditions (t/m3)	0.869	0.915
11	The altitude of oil-water contact (m)	−853	−1422
12	Oil Saturation pressure (MPa)	8.35	9.9
13	Gas content (m3/t)	29.6	8
14	Average total thickness (m)	15.8	25
15	Oil formation volume factor, share	1.067	1.011
16	Water viscosity at reservoir conditions (mPa·s)	1.57	1.51

3.2. Field Number 1

In order to estimate the possible increase in production rate after the implementation of enhanced oil recovery methods hydrodynamic modeling of radial drilling and acid treatment was performed for three wells in field number 1 (Table 5).

Table 5. Input parameters of the Field number 1 for hydrodynamic modeling.

Well No.	Flow Rate (t/day)		Water Cut (%)	Reservoir Pressure (MPa)	Permeability (µm2)
	Oil	Liquid
1	3.9	4.7	17	8.7	0.1400
2	3.6	4.2	14.5	8.6	0.0746
3	8.2	9.0	8.8	8.8	0.0746
Average value	5.2	6.0	13.4	8.7	0.2892

Table 5. Input parameters of the Field number 1 for hydrodynamic modeling.

Well No.	Flow Rate (t/day)		Water Cut (%)	Reservoir Pressure (MPa)	Permeability (µm2)
	Oil	Liquid
1	3.9	4.7	17	8.7	0.1400
2	3.6	4.2	14.5	8.6	0.0746
3	8.2	9.0	8.8	8.8	0.0746
Average value	5.2	6.0	13.4	8.7	0.2892

An initial three-phase black oil model was used, built in the Eclipse 100 software. Simulations were performed on producing wells in the liquid extractions mode (including statistical information applied to enhanced oil recovery method wells and considering average annual well production by liquid at optimum bottom hole pressure of PBH = 0.75P_Sat). During the modeling of the radial drilling technology method of exposing additional cells in the horizontal direction from the main trunk was used (Figure 4a). The model skin factor of acid treatment is 3 (Figure 4b) [23]. Well production was considered without implementation of enhanced oil recovery methods, as well as after the radial drilling and the acid treatment (with a 3 year forecast).

Figure 4. Cross section along the borehole (an example of current oil saturation cube). (a) Radial drilling; (b) Acid treatment.

Figure 4. Cross section along the borehole (an example of current oil saturation cube). (a) Radial drilling; (b) Acid treatment.

According to the results of the simulation radial drilling and acid treatment have an average technological efficiency of 3 and 1.8 years, respectively (Table 6).

Table 6. Additional oil production as a result of the hydrodynamic modeling (tons).

	No. of Well	1	2	3	Average Value
Method
Radial drilling		4952	3927	3699	4193
Acid treatment		2867	1925	2274	2355

Table 6. Additional oil production as a result of the hydrodynamic modeling (tons).

	No. of Well	1	2	3	Average Value
Method
Radial drilling		4952	3927	3699	4193
Acid treatment		2867	1925	2274	2355

Since the hydrodynamic simulator in predictive options calculations ignores the deterioration of the natural bottom zone to predict the well, which held an event, it is necessarily to calculate the average oil falling rate per month. For radial drilling −0.95 and for acid treatment −0.91.

3.3. Field Number 2

An example of Field 2 shows the efficiency of simulation of water-alternated-gas injection during the displacement of miscible homogeneous oil and gas mixtures, which consist of a liquid phase in the form of tiny bubbles (supercritical carbon dioxide). This system may penetrate into pore channels of different sizes. The viscosity of Tournaisian stage reservoir oil (48.8 mPa∙s) exceeds 30 mPa∙s, from which the water-oil displacement becomes sufficiently effective [24,25,26,27,28,29,30,31].

In order to simulate the water-alternated-gas injection the plots of nine wells that work off one pump station have been selected. Initial oil saturation and reservoir pressure for the simulated area are isolated from current fields for a complete model of 01.01.2012.

The simulations were performed in ROXAR Tempest MORE software, with grid sizes 26 × 19 × 19. The model used the following scaling principle: in each cell the relative permeability is given as a function of water saturation S_w, including critical water saturation S_wc and oil saturation S_oc. Initial cube critical values of water and oil saturation were used in accordance with the full model. Residual oil saturation (0.357) is constant for all the cells and does not change during adaptation [32,33].

A model adaptation was based on the actual development indicators carried out in accordance with the information about the operation of wells (production, injection), and the values of downhole formation pressures from 01.01.2010 to 01.01.2012. Adaptation parameters have undergone communicability “well-layer” downward, that can explain the deterioration of the bottom zone formations. In terms of watercut dynamics the model was tuned by the relative permeability factors in the bottom-hole zone of the wells. Then these factors were interpolated to the crosshole space, the most focused on the adaptation of the accumulated value of oil and water on each well. Average simulated and measured pressure in all producing wells of the field are correlated among themselves: bottom hole is 11.2 and 11.3 MPa and reservoir is 18.0 and 17.9 MPa, respectively.

Indicators of the oil displacement process by a water-gas mixture are calculated according to the method adopted in [34,35] and based on laboratory studies. Then the calculated land residual oil saturation in each cell in the displacement of water-gas mixtures was assumed equal to the residual oil saturation in the cell in the displacement of water, multiplied by a factor depending on the gas content. The calculation considered that the viscosity of the oil at the front displacement in contact with a water-gas mixture is changed due to the dissolution of gas oil (Table 7). Polymers based on polyacrylamides like Flopaam 5205 VHM and Flocculant FM-1B3 are usually applied in the Volgo-Ural areas. To track changes in the gas content in each computational cell the POLYMER option of the Tempest MORE simulator was used. It was decided to inject into the formation gas mixture with zero polymer adsorption and the properties of the water-gas mixture. Viscosity of the polymer is equal to water-gas mixture viscosity given by a linear function of gas content G:

μ = μ₀(1 + 2.5G)

Table 7. Parameters of water-gas mixture depending on the added amounts of gas.

No.	Parameters	Added Amounts of Gas (vol%)
		0	6	12	25	30
1	Density, kg/m3	917	912	908	903	902
2	Viscosity, mPa∙s	54.02	42.0	33.7	28.3	28.0
3	Gas content, m3/m3	13.5	19.3	24.6	27.3	27.5
4	Volume factor, the proportion of units	1.031	1.072	1.098	1.109	1.111

Table 7. Parameters of water-gas mixture depending on the added amounts of gas.

No.	Parameters	Added Amounts of Gas (vol%)
		0	6	12	25	30
1	Density, kg/m3	917	912	908	903	902
2	Viscosity, mPa∙s	54.02	42.0	33.7	28.3	28.0
3	Gas content, m3/m3	13.5	19.3	24.6	27.3	27.5
4	Volume factor, the proportion of units	1.031	1.072	1.098	1.109	1.111

The stimulation of oil displacement by a water-gas mixture is performed in the way of its launching after a period of one year. In the simulation injection started on the wells No. 1205 and 1307 since 1 January 2012. The simulation period was 15 years. As a reference case conventional water injection (gas content in the mixture is equal to zero) was selected. During the simulation of scenarios displacement of the front of mixture with time was analyzed. Depending on gas content the residual oil saturation and PVT-properties of each cell change. Initially seven tables were input that characterized the oil property changes with an increase of gas content of mixture from 0% to 29% in steps of 5%. Figure 5 shows the results of the simulated scenarios in terms of cumulative oil production for all wells.

Figure 5. Results of calculation of cumulative oil production when gas mixtures are injected.

Figure 5. Results of calculation of cumulative oil production when gas mixtures are injected.

In comparison with the reference scenario an increase of scenario oil production of 29% of gas is 11.3% (157.45 × 103 m³). Economic efficiency of water-alternated-gas injection was evaluated by the method of the branch of “LUKOIL-Engineering” “PermNIPIneft” in Perm. It shows that the scenario with the highest gas content could bring a net profit in the amount of $10 mln for 15 years. According to this fact water-alternated-gas injection is useful for implementation on the oil Field No. 2.

4. Conclusions

Implementation of hydrodynamic simulation allows evaluation of the effectiveness of enhanced oil recovery methods including the design phase. A performance criterion for enhanced oil recovery methods was taken as instantaneous and average annual growth above the well average. It is found that well-candidates for enhanced oil recovery methods must satisfy the parameters of Group I (high residual recoverable reserves and improved reservoir properties, low water cut, an obtained increase in oil rate, which is kept at a stable level).

In order to assess the possible increase in production rate after implementation of enhanced oil recovery methods on the Field No. 1 hydrodynamic modeling of radial drilling and acid treatment for three wells were performed. In the context of the development of the object efficient radial drilling is handled. Reservoir simulation efficiency of water-alternated-gas injection was performed on water-gas deposits of Field No. 2. Economic efficiency evaluation of the enhanced oil recovery methods showed the possibility of water-alternated-gas injection in similar geological and physical conditions.