Optimization of Enhanced Oil Recovery by IWAG Injection at a Real Oil Field Reza Masoomi¹1, Ehsan Shekoohizadeh² Department of Petroleum Engineering, KubSTU, Russia¹, Islamic Azad University of Science and Research of Fars ²
[email protected]¹
[email protected] ²
Abstract WAG injection was proposed to improve efficiency of gas macroscopic displacement. This process can reduce the high mobility of gas phase in oil displacement process. In this study, used model has an active aquifer that affects on the performance of WAG injection. The parameters influencing on EOR process in WAG injection have been studied with compositional simulation methods in a model with an active aquifer. Also in this study shown that increasing in the oil production rate, higher than the optimal flow rate, would increase the water cut. At too high flow rates simulation program running was suspended in less than first 400 days period due to deviation from the defined limits (pressure limits and maximum water cut limits). At the end in a real oil field after history match, WAG injection was simulated for this reservoir then compared with immiscible gas injection and natural depletion projects in a 25 years period. Keywords: WAG Process, Compositional Simulation, Active Aquifer, Sensitivity Analysis
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Reza Masoomi
Kuban State University of Technology, Krasnodar, Russia
[email protected] +79384038655
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1. Introduction Displacement effect with WAG injection when is maximum, that we can optimize the balance of forces in the reservoir. There is a complex flow in the area behind the oil bank in WAG process. Thus WAG injection modeling is running by computer simulation that is based on mathematical models. Viscous and gravity forces are the most important forces on governing fluid flow in the WAG project. The mobility ratio between injected gas and displaced oil is very unfavorable in the gas injection process that is mainly because of low viscosity of injected phase. An unfavorable mobility ratio results in Viscose Fingering and reduced volumetric sweep efficiency. North Pembina field in Alberta Canada is the first field which this project was used successfully. Then it took advantage of this technique in many fields. 1.
Description of the considered field
2.1 Basic Model First to see the effects of various parameters on the WAG performance is used a model with the following properties. The reservoir characteristics are presented in Table1. In this simulated model, is intended an aquifer with the presented properties in Table 2. Numerical calculations of aquifer have been done by using Numerical Aquifer method. The PR EOS method has used for the PVT calculations .The rock and fluids data including three-phase relative permeability and capillary pressure available in the SPE “Fifth Comparative Solution Project: Evaluation of Miscible Flood Simulator”[5]were used in the basic model. That three-phase relative permeability and capillary pressure versus saturation are presented graphically in Figure 1.[5]It should be noted that for both basic and real models “Stone’s Second Model” was used for three-phase relative permeability calculations. Table 1 - Reservoir Properties Property
Value
Unit
Number of Grid Blocks in X-Direction
24
-
Number of Grid Blocks in Y-Direction
25
-
Number of Grid Blocks in Z-Direction
24
-
Length of Grid Blocks in X-Direction
418.43
ft
Length of Grid Blocks in Y-Direction
458.15
ft
Length of Grid Blocks in Z-Direction
31.251
ft
Reservoir Depth(Dept of First Layer)
8325
ft
Reservoir Porosity
0.19
-
Permeability in X-Direction
105
md
Permeability in Y-Direction
105
md
Permeability in Z-Direction
65
md
Reservoir Pore Volume
16390.7e6
Ft³
Initial Pressure
4070
psia
WOC Depth
8982
ft
GOC Depth
8300
ft
Table 2-The Properties of the Aquifer Property Value Lower I-coordinate of Cells to be Connected 1 Upper I-coordinate of Cells to be Connected 24 Lower J-coordinate of Cells to be Connected 1 Upper J-coordinate of Cells to be Connected 25 Lower K-coordinate of Cells to be Connected 21 Upper K-coordinate of Cells to be Connected 24 Face of the Cell to be Connected to the Aquifer I+ Cross-Section of the Aquifer 0.55e+5 Length of the Aquifer 18000 Aquifer Porosity 0.15 Aquifer Permeability 100
2
Unit ft² Ft md
Fig.1. Three-phase relative permeability and capillary pressure versus saturation As Table 2 is clear that active aquifer contacts with last four layers of 21 to 24 and in fact 4Lines of Numerical Aquifer with using the data in Table 2should be defined in this model that it was done. In this study we were divided the reservoir in the 14400 grid blocks in the Cartesian system with the dimensions given in Table 1, and different scenarios have simulated and analyzed by changing sensitive parameters such as production and injection rates, vertical /horizontal Permeability ratio, the cycle time of injection, period of half cycles injection, the number of production and injection wells, viscosity of injected water, etc in this reservoir with an active aquifer. Of course for studied field other scenarios of EOR such as gas injection project has simulated and compared with WAG project .Also the ultimate recovery of hydrocarbons, for the case which any EOR project is not defined for the field have simulated and results analyzed and compared with the WAG and gas injection projects. In this study for the first scenario were used a single injection well and a single production well, that bottom hole pressure limited at least equal 2000 Psia and maximum oil production rate was considered equal 10000 STB/D for the production well. As mentioned in the WAG process injected water volumes per gas injected volumes should be between 0.5 to 4 water/ gas volume at the reservoir condition. So optimizing the injected water volume per injected gas volume is an important parameter in getting satisfactory results. Thus at first stage we started to optimization of this parameter with Eclipse 300 software, it is noteworthy, according to previous studies has shown that the Compositional simulation method had better performance. [6] Therefore in this study the same method is used to simulate. Initially, water and gas injection rate have defined equal to 2500 STB/D for water and 2500 MScf/D for gas injection well. So for the first stage water/gas injection ratio was equal to 1:1. The next stage gas injection rate of 5000 MScf/D and water injection rate of 2500 STB/D was changed to achieve water/ gas injection ratio of 1:2. Also in the third stage injected gas volume has increased to have a better view of gas break through. In this stage gas injected volume of 8000 MScf/D and water injected volume of 2000 STB/D was chosen. The next step was observed that increase in the water injection rate to 8000 STB/D have a significant effect on the ultimate recovery of hydrocarbons.
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In reviewing the performance can be said that increasing in water injection rate to 8000 STB/D has caused the gravity increases in this reservoir with an active aquifer against to the reservoirs without active aquifer, because in this study, injection of alternating water and gas is done in the upper part of the oil zone, and the density difference between oil and water and gas phases has caused gravity force overcome the capillary force and improved the oil bank macroscopic sweep efficiency in this case unlike the previous studies that were on the reservoirs without active aquifer [7], because the area of the reservoir in contact with the water phase (as a fluid is injected in a half cycle) increases and subsequently will increase the ultimate recovery of hydrocarbons. Of course it was ultimate rate of water injection because with further increase in water injection rate was observed rapid increase in water cut in production well. The result of this simulation is presented in Figure 2. Now can consider content expressed more clearly with respect to pressure changes versus elapsed time curve. The reservoir has produced for two years with natural depletion energy and as we see in Figure 3 along this two years initial reservoir pressure is reduced from 4070 Psia to 3922 Psia. WAG project started after two years. At the first half cycle water injection with a high rate of 8000 STB/D for 365.25 days and a second half cycle of the gas rate of 5000 MScf/D begins and as of Figure 2 found, reservoir pressure is increased from 3922 Psia to 3982 Psia with increasing the rate of water injection in the first half cycle. Pressure is reduced to 3932 Psia upon completion of half-cycle of water injection and beginning of half-cycle of gas injection. But both half-cycle of water and gas injections have caused improving in reservoir pressure than first two years of production and increasing trend is observed in all 20 years of the forecast period. But in other scenario that gas injection rate was 8000 MScf/D and water injection rate was 2000 STB/D, we carefully will find that due to the high volume of gas injection Fingering phenomenon and subsequently gas break through happened and step by step during the half-cycle reservoir pressure has declined to below 3740 Psia. Thus the optimal injection rate of about 8000 STB/D for water and 5000 MScf/D for the gas were selected. At the other word the water/gas volume ratio of 1.6 was selected as optimal injection rate in this model.
Fig.2.Effect of water/gas vol. on hydrocarbon ultimate recovery in WAG injection Fig.3.Pressure changes v.s. time for various water/gas volume 2.4. The impact of oil production rate of the field Oil production rate was a parameter to consider the effects of oil production rates on the final efficiency of the WAG process in this study. The influence of various production rates is presented in Figure 6. At first a small oil production rate was selected. Next steps flow rate increased with respect to defined limitations for producing wells and simulation performed for each flow rate by definition limits of the minimum bottom hole pressure of 1000 Psia and the maximum Water Cut of 0.5, while the WAG ratio and the cycle time were kept constant for all flow rates. Ultimate recovery of hydrocarbon has increased at higher rates because viscous forces dominated over gravity forces that increase Darcy´s velocity and reduce the time for the gravity effects that cause fluid segregation. So three-phase zone of mixture expands in an untouched zone that increase recovery factor. But rising flow rates more than optimal value increases Water Cut rapidly and so high flow rates that were possible by definition of new production wells, simulation running was stopped less than 400 days. Cause of stopped simulation running in too high flow rates can justify with extremely pressure drop (deviation from the defined limits) that is shown in Figure 6.
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Fig.6.The impact of oil production rates on hydrocarbon ultimate recovery in WAG injection 3. WAG injection simulation in a real reservoir 3.1. Characterization of studied reservoir Studied oil field is located about 100 km of southwest of Lavan Island and fifty miles northwest of Salman field of Iran. Sarvak and Darian are the main reservoirs of this field. Simulation was done on Sarvak reservoir .This reservoir is a fractured reservoir with gravity drainage mechanism. The reservoir also includes a 5 fault and 3 wells that 2 wells are vertical and the other is horizontal. The reservoir started to produce at first by a vertical well in 1999 by rate of 500 STB/D .This rate is increased with elapsed time and reached approximately to 9000 STB/D.Of course there were fluctuations in production rates. Daily production rates have reached 6000 with declining production rates in 2004. The reservoir model contains blocks with dimensions of 30*30*32. Figure 12 shows a three-dimensional view of the reservoir. In this reservoir to predict performance of WAG injection process initially did history matching process. We rewrite the changeable parameters of the reservoir that were not tune due to the lack of comprehensive studies in the past, to eventually history match happen. Results relating to history match process are presented in Figure 13.
Fig.12.A three-dimensional view of the reservoir, Fig.13.Results relating to history match process These parameters were the fracture permeability and rock compressibility. It was observed that changing in the fracture permeability from current value of 800 md to a minimum of 350 md, and also changing in rock compressibility from current value of 1.244E-06 to maximum value of 4E-06 have a good effect on the history matching process and made tune between observation and simulated data. After history match, WAG injection was simulated for this reservoir then immiscible gas injection and natural depletion were simulated and has been forecast for the next 25 years. Results are presented in Figures 14 and 15.
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Fig.14.prediction of function of natural depletion and immiscible gas injection and WAG injection projects for the next 25 years, Fig.15.prediction of pressure changes for natural depletion and immiscible gas injection and WAG injection projects 4.
Results
- At first, with increasing in flow rate hydrocarbon recovery increased, but increasing in flow rate more than the optimal value caused a rapid increase in water cut and simulation running was stopped in much higher flow rates due to deviation from the defined constraints. - The optimal number of production and injection wells for this model is 12 wells that arranged with using Five-Spot Pattern method. - Although the ultimate recovery of hydrocarbons in the WAG process was slightly higher than the gas injection process, but also economically WAG injection is more affordable. Acknowledgments The author acknowledges the assistance of the Iranian Research Institute of Petroleum Industry (IRIPI) and National Iranian Central Oil Company. References 1- Killough,J.E.,Kossack,C.A.,:” Fifth Comparative Solution Project: Evaluation of Miscible Flood Simulator”,APE paper 16000,presented at Ninth SPE Symposium of Reservoir Simulation held is San Antonio,Texas,1987 2- Green,D.W. and G.P. ,Willhite:”Enhanced Oil Recovery”, Textbook Series, SPE , Richardson, TX(1998)6, 168174 3- Namani, M. and J.Kleppe:”Investigation of the Effect of Some Parameters in Miscible WAG process Using Black-Oil And Compositional Simulators”, SPE,2011 4- Patton, J.T., Coats, K.H., and G.T., Colergrove :”Prediction of Polymer Flood Performance”,SPE,1971,72-84 5- Craft, B.C. and M.F., Hawkins:”Applied Petroleum Reservoir Engineering”, Prentice-Hall, 1990
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