Determination of Optimum Polymer Slug Size in Modified Polymer Flooding Based on Reservoir Simulation Results

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1 Determination of Optimum Polymer Slug Size in Modified Polymer Flooding Based on Reservoir Simulation Results А.I. Vafin, А.R. Vafin (TatNIPIneft Institute) Development of Tatarstan s oil fields using water flooding techniques has some particular challenges. Oil reservoir heterogeneity results in unswept or bypassed zones with low permeability and significant amount of remaining oil in place which can be classified as unconventional oil reserves. In turns, one of the main objectives of oil field development in Tatarstan is production of undrained oil reserves and increase of oil recovery. For this purpose physical and chemical enhanced oil recovery (EOR) methods have been successfully applied for decades in Tatarstan. [1] Generally, physical and chemical EOR methods are based on reservoir pressure maintenance techniques in which various chemicals are mixed with water to be injected into a reservoir. These methods are aimed at changing the viscosity of displacing and displaced fluids to control their mobility ratio. The Bobrik horizon of the Sabanchinskoe field has been chosen as a pilot area, since a lot of various chemical EOR methods are applied there (Fig. 1). Fig. 1 Application of chemical EOR methods in Bobrik horizon (as of ) Figure 2a shows that the vast majority of EOR methods, namely 7%, are referred to flow diversion technology. This fact points out the necessity of further analysis and simulation of technologies, which are based on polymer system injection, to improve its efficiency. 1

2 Сonformance Сontrol Flow Diversion Technology а) b) Fig.2 Application of physical and chemical EOR methods in injection wells (Bobrik horizon, the Sabanchinskoe field) Modified Polymer Flooding is aimed at oil recovery increase in heterogeneous, waterproducing reservoirs through volumetric sweep efficiency improvement. This is achieved by partial or complete isolation of high-permeability zones referred to as thief zones with subsequent alteration of fluid flow direction. This leads to oil production from previously unswept low-permeability zones and reduction in unwanted water production from highpermeability layers. Capsular polymer systems have proven highly efficient for oil recovery enhancement in Bobrik horizon of the Sabanchinskoe field (Fig. 2b). Using capsular polymers relies on injection of aqueous polyacrylamide solution. The main purpose of using polymers is to increase the viscosity of flood water, thus increasing volumetric sweep efficiency due to improved mobility ratio of the injected fluid (water) and oil. [1] Therefore, polymer slug injection can improve oil recovery efficiency in the pilot area and, subsequently, in the entire Sabanchinskoe field. [1] 2

3 Requirements for Application of Modified Polymer Flooding Using Capsular Polymer Systems [2] Pilot area for testing the technology under consideration should meet the following requirements: - type of reservoir: porous, terrigenous - water-flood system: pattern, line drive, or spot flooding systems - well-stream water cut: 98 % - injector location: within the oil zone - net oil thickness: minimum 2 m - permeability: minimum.1 mcm 2 - porosity: minimum 1 % - oil flow rate: minimum 5 t/d - connectivity between the injection and production wells - injectivity: minimum 1 m 3 /day (without choke) - well utilization rate: minimum 8% (on a monthly basis) during 18 months before the treatment and 24 months after the treatment. No workovers, well stimulations and other well interventions aimed at well performance optimization should be carried out in the pilot area. [2] Recommended polymer slug sizes based on the injection capacity are presented in Table 1. Table 1 Recommended size of polymer slug [2] Injection capacity, m 3 /d Polymer slug size, m 3 Mass fraction of components (capsular polymer system), % Polymer: polyacrylamide (PАА) More than Based on TATNEFT s experience in development of carbonate and terrigenous reservoirs, polymer slug size can vary from 3 to 2 m 3. [2] Areas with remaining oil in place have been identified based on the simulation model of the Sabanchinskoe field. The available data has been analyzed and injection wells with low volume of injected water were identified, which allowed selection of proper well candidates and a pilot area for testing Modified Polymer Flooding. 3

4 The selected pilot area meets all the requirements for application of modified polymer flooding. This area is located in Block 3 and is a continuous reservoir surrounded by an aquifer (Fig. 3a). Reservoir properties deterioration and reservoir thickness decrease can be observed in the south and south-east of the area. The reservoir is heterogeneous in terms of porosity and permeability due to non-uniform clay sedimentation, with clay content increasing towards the top of the reservoir (Fig. 3b). The pilot area has been produced since 1976 and is currently at the late or depletion stage of development. Approximately 8% of oil-initial-in-place has been produced to date. Reservoir pressure maintenance system was deployed in the field 1 years after the start of production. The initial plan involved peripheral water-flooding; later on, two injection wells were drilled in the center of Block 3. Thus, today there is a combined system comprising peripheral and center-to-edge water-flooding patterns. This system allows diverting fluids through alternate bringing the outer and center wells on line. а) b) Fig. 3 a) Pilot area location (Block 3) b) Permeability distribution: cross-section for wells Nos. 2191, 2154, 198, 193, 172, and

5 Oil Saturation Fig. 4 Oil saturation map with current production and injection rates (Block 3, the Sabanchinskoe field) Well performance has been analyzed and injection wells have been selected for modified polymer flooding application using capsular polymer systems (Fig. 4). The injection capacity of candidate wells is over 1 m 3 /d. These wells are located in the areas with net pay thickness of 2 to 7 m. Wellstream water cut in the pilot area is about 9%, and the average oil production rate is more than 5 t/d. All wells meet the requirements for application of modified polymer flooding. Table 2 Recommended candidate wells Injection well No. Injectivity, m 3 /d Oil net thickness, m Production well No. Wellstream water cut, % Polymer slug size, m 3 Polymer concentration (Polyacrylamide DP9-8177), %

6 Pilot Area Reservoir Simulation and History Matching Simulation of Block 3 was performed by Roxar s Tempest reservoir simulator. The pilot area has been taken from the full-field model, and flux boundary conditions have been written for time saving and simulation simplification. Several scenarios using various volumes of polymer solution were simulated. Recommended polymer slug size for injection wells with 1-25 m 3 /d intake capacity: Case 1: 3 m 3 Case 2: 4 m 3 Case 3: 5 m 3 Moreover, based on the experience of water control treatments, larger volumes of polymer solution can be injected; therefore, three additional cases were simulated, including: Case 4: 1 m 3 Case 5: 15 m 3 Case 6: 2 m 3 Experience in using capsular polymer systems shows that the most frequently used polymer concentrations are the following: Case 1:.1% Case 2:.2% Case 3:.3% In addition to the above mentioned cases, another case was simulated with maximum polymer concentration of.5%: Case 4:.5%. Polymer Properties for Simulation Model Under standard conditions, (i.e. at the surface and during injection) polymer solution has a relatively low viscosity, which means that it can easily flow through porous media. Figure 5 shows polyacrylamide aqueous solution viscosity vs polymer concentration. 6

7 Fig. 5 Dynamic viscosity of DP PAA solution versus mass fraction of polymer Some other polyacrylamides can also be used for preparation of polymer solution. They must meet all the requirements and be capable of forming gels in combination with an appropriate cross-linker. Polymer Adsorption Effect Due to the lack of laboratory test data, three different functions of polymer adsorption on the rock surface were analyzed in this paper (Fig. 6). These functions were taken from the thesis of Hongjiang Lu, Improving Oil Recovery (IOR) with Polymer Flooding in A Heavy-Oil River- Channel Sandstone Reservoir. [3] Polymer adsorption, kg/kg Dynamic viscosity, mpa*s Mass fraction of PAA, % 1. g/cm g/cm g/cm 3 Polymer concentration, kg/m 3 Fig. 6 Polymer adsorption function 7

8 Figure 6 shows that maximum adsorption of polymer on the rock surface for function 1 is 5 mg/kg, for function 2 1 mg/kg, and for function 3 2 mg/kg, with polymer concentration of 5 kg/m 3. Simulation Results for Modified Polymer Flooding Using Capsular Polymer Systems As Figure 7 shows, many production wells in the pilot area respond to polymer injection via well No That is why the simulation results are presented for a group of wells, including wells Nos. 1899, 191, 2274, 172, 1827, 1898, 192, and Fig.7 Simulation of stream lines in the pilot area 1. Effect of Polymer Slug Size and Polymer Concentration on Oil Production Rate and Watercut Simulation results for polymer slug size of 5 m 3 and 1 m 3. Simulation results presented in Figure 8 show that the higher the polymer slug size and polymer concentration, the higher the oil production rate. In turns, the higher the 8

9 Water-cut, % Oil Production Rate - Qoil, t/day polymer slug size and polymer concentration in the solution, the lower the water cut (Fig. 9) Oil Production Rate vs Time Time, days Base Case (Without FDT) Slug Size - 1 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 5 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 1 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 5 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 1 m3; C(polymer) -.5; A-1 mg/kg Slug Size - 5 m3; C(polymer) -.5; A-1 mg/kg Fig. 8 Oil production rate vs time for various slug sizes (5 m 3 ; 1 m 3 ) and polymer concentrations (.1%,.3%,.5%). 56 Water-cut vs Time Time, days Base Case (Without FDT) Slug Size - 1 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 5 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 1 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 5 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 1 m3; C(polymer) -.5; A-1 mg/kg Slug Size - 5 m3; C(polymer) -.5; A-1 mg/kg Fig. 9 Water cut vs time for various slug sizes (5 m 3 ; 1 m 3 ) and polymer concentrations (.1%,.3%,.5%). 9

10 Water-cut, % Oil Production Rate - Qoil, t/day Simulation results for polymer slug size of 15 and 2 m 3. As can be seen from Figure 1, the higher the polymer slug size and polymer concentration, the higher the oil production rate. In turns, the higher the polymer slug size and polymer concentration in the solution, the lower the water cut (Fig. 11). Oil Production Rate vs Time Time, days Base Case (Without FDT) Slug Size - 2 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 15 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 2 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 15 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 2 m3; C(polymer) -.5; A-1 mg/kg Slug Size - 15 m3; C(polymer) -.5; A-1 mg/kg Fig. 1 Oil production rate vs time for various slug sizes (15 m 3 ; 2 m 3 ) and polymer concentrations (.1%,.3%,.5%). 56 Water-cut vs Time Time, days Base Case (Without FDT) Slug Size - 2 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 15 m3; C(polymer) -.1; A-1 mg/kg Slug Size - 2 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 15 m3; C(polymer) -.3; A-1 mg/kg Slug Size - 2 m3; C(polymer) -.5; A-1 mg/kg Slug Size - 15 m3; C(polymer) -.5; A-1 mg/kg Fig. 11 Water cut vs time for various slug sizes (15 m 3 ; 2 m 3 ) and polymer concentrations (.1%,.3%,.5%). 1

11 Incremental Oil Production, tons Incremental Oil Production, tons Thus, simulation results have shown that there is no need to increase the injected volumes of polymer over 15 m 3, since this does not result in further increase of oil production and reduction of water cut. 2. Effect of Polymer Adsorption on Incremental Oil Production Incremental Oil Production in 219 Polymer Concentration.1% 5 Slug Size vs Incremental Oil at Polymer Concentration.1% Polymer Adsorption - 5 mg/kg Polymer Adsorption - 1 mg/kg Polymer Adsorption - 2 mg/kg Fig. 14 Polymer slug size vs incremental oil production for various polymer adsorption values Polymer Concentration.3% (5 mg/kg, 1 mg/kg, 2 mg/kg). 1 Slug Size vs Incremental Oil at Polymer Concentration.3% Polymer Adsorption - 5 mg/kg Polymer Adsorption - 1 mg/kg Polymer Adsorption - 2 mg/kg Fig. 15 Polymer slug size vs incremental oil production for various polymer adsorption values (5 mg/kg, 1 mg/kg, 2 mg/kg). 11

12 Incremental Oil Production, tons Incremental Oil Production, tons Polymer Concentration.5% Slug Size vs Incremental Oil at Polymer Concentration.5% Polymer Adsorption - 5 mg/kg Polymer Adsorption - 1 mg/kg Polymer Adsorption - 2 mg/kg Fig. 16 Polymer slug size vs incremental oil production for various polymer adsorption values (5 mg/kg, 1 mg/kg, 2 mg/kg). Incremental Oil Production in 22 Polymer Concentration.1% Slug Size vs Incremental Oil at Polymer Concentration.1% Polymer Adsorption - 5 mg/kg Polymer Adsorption - 1 mg/kg Polymer Adsorption - 2 mg/kg Fig. 17 Polymer slug size vs incremental oil production for various polymer adsorption values (5 mg/kg, 1 mg/kg, 2 mg/kg). 12

13 Incremental Oil Production, tons Incremental Oil Production, tons Polymer Concentration.3% Slug Size vs Incremental Oil at Polymer Concentration.3% Polymer Adsorption - 5 mg/kg Polymer Adsorption - 1 mg/kg Polymer Adsorption - 2 mg/kg Fig. 18 Polymer slug size vs incremental oil production for various polymer adsorption values (5 mg/kg, 1 mg/kg, 2 mg/kg). Polymer Concentration.5% Slug Size vs Incremental Oil at Polymer Concentration.5% Polymer Adsorption - 5 mg/kg Polymer Adsorption - 1 mg/kg Polymer Adsorption - 2 mg/kg Fig. 19 Polymer slug size vs incremental oil production for various polymer adsorption values (5 mg/kg, 1 mg/kg, 2 mg/kg). 13

14 Incremental Oil Production, tons Performance Indicators in 217 Feasibility analysis has been performed for five years after polymer injection. The main conclusion is that the post-treatment effect will be observed during 217 or during 1 year after polymer injection. Incremental oil production increases with polymer solution volume. However, in case of slug size over 15 m 3 no further growth of incremental oil production is observed. The same is true for various polymer concentrations. Optimum polymer slug size can be selected based on the results shown in Figures 2 and 21. It ranges from 138 m 3 to 15 m 3 in terms of incremental profit. The results of economic analysis are presented in Table 3. It should be noted that incremental profit increases when polymer slug size is within 15 m 3 ; however, for slug size over 15 m 3, it tends to decrease. Thus, the optimum slug size doesn t exceed 15 m Slug Size vs Incremental Oil Production Polymer Concentration -.5% Polymer Concentration -.3% Polymer Concentration -.1% Fig. 2 Polymer slug size vs incremental oil production for various polymer concentrations Incremental Profit, RUB* Slug Size vs Incremental Profit Polymer Concentration -.5% Polymer Concentration -.3% Polymer Concentration -.1% Fig. 22 Polymer slug size vs incremental profit for various polymer concentrations 14

15 Incremental Oil Production, tons Table 3 Incremental oil production and incremental profit for various polymer slug sizes (5 m 3, 1 m 3, 15 m 3, and 2 m 3 ) and concentrations (.1%,.3%,.5%). Incremental Oil Production, tons Incremental Profit, RUB*1 3 Polymer Concentration, % Polymer Concentration, % Performance Indicators in Slug Size vs Incremental Oil Production Polymer Concentration -.5% Polymer Concentration -.3% Polymer Concentration -.1% Fig. 23 Polymer slug size vs incremental oil production for various polymer concentrations 15

16 Incremental Profit, RUB* Slug Volume vs Incremental Profit Slug Volume, m 3 Polymer Concentration -.5% Polymer Concentration -.3% Polymer Concentration -.1% Fig. 24 Polymer slug size vs incremental profit for various polymer concentrations Table 4 Incremental oil production for various polymer slug sizes (5 m 3, 1 m 3, 15 m 3, and 2 m 3 ) and polymer concentrations (.1%,.3%,.5%). Incremental Oil Production, tons Incremental Profit, RUB*1 3 Polymer Concentration, % Polymer Concentration, % Performance Indicators in 22 In addition, feasibility analysis has been performed for 22, since the post-treatment effect will end up 5 years after polymer injection. As can be seen from Figures 25 and 26, incremental oil production grows with the slug size increase. However, no further increase of incremental oil production is observed in case of slug size over 15 m 3. The same is true for polymer concentrations. Optimum polymer slug size ranges between 1 m 3 and 15 m 3 in terms of incremental profit. Economic analysis results are presented in Table 5. 16

17 Incremental Oil Production, tons Slug Size vs Incremental Oil Production Slug Size, m 3 Polymer Concentration -.5% Polymer Concentration -.3% Polymer Concentration -.1% Fig. 25 Polymer slug size vs incremental oil production for various polymer concentrations Incremental Profit, RUB* Slug Size vs Incremental Profit Polymer Concentration -.5% Polymer Concentration -.3% Polymer Concentration -.1% Fig. 26 Polymer slug size vs incremental profit for various polymer concentrations 17

18 Table 5 Incremental oil production for various slug sizes (5 m 3, 1 m 3, 15 m 3, and 2 m 3 ) and polymer concentrations (.1%,.3%,.5%) Incremental Oil Production, tons Incremental Profit, RUB*1 3 Polymer Concentration, % Polymer Concentration, % Summary and Conclusions results: The following conclusions can be drawn based on the performed analysis and simulation - There is no need to use large volumes of polymer solution (over 15 m 3 ). - The optimum slug size ranges from 1 m 3 to 15 m 3. - It is critical to take into account polymer adsorption during simulation, since this parameter can have a significant effect on incremental oil production, skin-factor in the near-wellbore zone and reservoir permeability. - Modified Polymer Flooding is aimed at long-term enhanced oil recovery. - Reservoir simulation enables us to evaluate the efficiency of Modified Polymer Flooding application in mature fields, such as the Sabanchinskoe field. As each well is unique, individual approach to well performance analysis and subsequent simulation is required. References 1. Eremin N. А., Zolotukhin А. B., Nazarova L. N., Chernokov О. А. Selection of Enhanced Oil Recovery Method for Petroleum Reservoir. Moscow, RD Regulation on Technology of Polymer and Micro-Gel System Injection for Enhanced Oil Recovery (Technology MGS-K), Hongjiang Lu, Dissertation Improving Oil Recovery (IOR) with Polymer Flooding in A Heavy-Oil River-Channel Sandstone Reservoir, Farid Abadli, Master Thesis, Simulation Study of Enhanced Oil Recovery by ASP (Alkaline, Surfactant and Polymer) Flooding for Norne Field C-Segment, MORE Tempest. Technical Reference, MORE Tempest. Technical Description,