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CO2 ENHANCED OIL RECOVERY BASED ON RESERVOIR COMPACTION, THERMAL MODELING, AND FORMATION DAMAGES : 저류층압밀, 열모델링, 지층손상에기반한CO2증진오일회수
| DC Field | Value | Language |
|---|---|---|
| dc.contributor.advisor | Jonggeun Choe | - |
| dc.contributor.author | 일리아스 | - |
| dc.date.accessioned | 2017-07-13T05:59:21Z | - |
| dc.date.available | 2017-07-13T05:59:21Z | - |
| dc.date.issued | 2014-08 | - |
| dc.identifier.other | 000000021696 | - |
| dc.identifier.uri | https://hdl.handle.net/10371/118172 | - |
| dc.description | 학위논문 (박사)-- 서울대학교 대학원 : 에너지시스템공학부, 2014. 8. Jonggeun Choe. | - |
| dc.description.abstract | Ilyas Khurshid
Department of Energy Systems Engineering College of Engineering Seoul National University The primary objective of this dissertation is to develop new, simple, and robust methods and practices for enhance oil recovery (EOR) and CO2 storage. For this purpose a step by step structure is developed, which will provide a good understanding of interrelationships between rock compaction and CO2 injection time, CO2 thermal modeling, CO2 related formation damages, and methods to minimize these damages. The first objective is to develop an analytical model using the concept of pore arrangement at macroscopic level. This model along with the proposed failure-line methodology determines a minimum reservoir pressure. This pressure represents the pressure after which permanent pore collapse will occur and it can be used to determine optimal time ranges for CO2 injection. On the basis of detail analysis, an optimal CO2 injection time ranges are to inject it before touching the failure line. This practice will enhance oil recovery and CO2 storage. The second objective is to determine CO2 temperature profile in wellbore, factors affecting it, and formation damages caused due to heated CO2. For this purpose a simulator is developed and experimental determined specific heat values of CO2 are used to predict the temperature of CO2. This approach results in accurate CO2 temperature predictions, because the thermodynamic properties of CO2 vary with temperature and pressure. From sensitivity analyses of CO2 injection parameters, it is found that the injection rate, injection time, geothermal gradient, and surface temperature play a key role in controlling CO2 temperature in sequestration activities. When carbon dioxide enters in a reservoir, it may react with the formation leading to immense formation damages such as asphaltene deposition, rock dissolution, and particle precipitation. The third objective is to develop a simulator to model chemical reactivity, pH shift, asphaltene deposition, and particle dissolution and precipitation. It is found that these processes may lead to cementation and result in irreversible damages to the porous media. It is observed that this cementation depends on the amount and reactivity of asphaltene, and the reactivity of CO2 with water and rock. It is also analyzed that substantial amount of cementations occurs for high injection rate and long injection period. From the sensitivity analysis, it is established that deep oil and gas reservoirs are better candidates for CO2 sequestration than shallow reservoirs due to low formation damages. The final objective of this study is to develop an integrated methodology to minimize asphaltene deposition, and to increase oil recovery and CO2 storage. When CO2 is injected at immiscible conditions, asphaltene deposition is low with less recovery. However, when the conditions are miscible, recovery increases but it also triggers asphaltene deposition. From detail simulation study, it is found that there are a number of minimum miscibility pressures (MMP), but three are important: near, at, and above MMP. For the first MMP there is high asphaltene deposition. When the pressure is at and above the MMP, the deposited asphaltene is removed from the reservoir, because CO2 develops contact with asphaltene at high pressure leading to its redissolution and removal. Key words: Reservoir compaction, Carbon dioxide injection, Optimal injection time ranges, Thermal modeling, and Formation damage. Student ID: 2011-31311 | - |
| dc.description.tableofcontents | TABLE OF CONTENTS
ABSTRACT i TABLE OF CONTENTS iii LIST OF TABLES vi LIST OF FIGURES vii 1. INTRODUCTION AND OVERVIEW 1 1.1 Backgrounds 1 1.2 Overview of CO2 Enhanced Oil Recovery 3 1.3 Mechanism of CO2 Enhanced Oil Recovery 5 1.4 Review of Current CO2 Enhanced Oil Recovery 7 1.5 Research Objectives and Motivation 9 1.6 Outline of the Dissertation 11 2. ANALYTICAL MODEL TO DETERMINE MINIMUM RESERVOIR PRESSURE AND OPTIMAL TIME RANGES FOR CO2 INJECTION IN A RESERVOIR 13 2.1 Reservoir Compaction 13 2.2 Interaction of Pore Pressure and Stress 14 2.3 Effect of Reservoir Compaction 20 2.4 Reservoir Compaction Prediction Model 21 2.5 Results and Discussions 25 2.6 Methodology for Field Applications 30 2.7 Validation and Case Study 31 2.8 Summary 34 3. THERMAL MODELING OF CARBON DIOXIDE DURING ITS INJECTION IN SHALLOW AND DEEP RESERVOIRS 35 3.1 Thermal Modeling 35 3.2 Development of CO2 Thermal Model 38 3.3 Heat Transfer from Formation to CO2 40 3.4 Validation and Comparison 45 3.5 Factors Affecting CO2 Temperature 50 3.6 Results and Discussions 54 3.7 Summary 56 4. FORMATION DAMAGE BY CO2 INJECTION: ASPHALTENE DEPOSITION, CARBONATE DISSOLUTION AND PRECIPITATION, WITH THEIR CEMENTATION 58 4.1 Formation Damage 58 4.2 Physics of the Problem 61 4.3 Formation Damage Model 62 4.4 Surface Area Modifications 70 4.5 Validation and Verification 71 4.6 Factor Affecting Formation Damage and Cementation 73 4.7 Summary 80 5. REDISSOLUTION AND REMOVAL OF DEPOSITED ASPHALTENE WITH INCREASEING CO2 STORAGE AND OIL RECOVERY 82 5.1 Asphaltene and its Deposition 82 5.2 Methodology of Optimization 86 5.3 Validation and Comparison 87 5.4 Factors Affecting Asphaltene Deposition 90 5.5 Summary 99 6. CONCLUSIONS AND RECOMMENDED FUTHER WORK 100 REFERENCES 105 ACKNOWLEGMENTS 115 ABSTRACT IN KOREAN 117 LIST OF TABLES Table 3.1 Well and formation properties 45 Table 3.2 Data for comparison and validation of CO2 temperature 48 Table 4.1 Physical properties of reservoir used for formation damage modeling 73 LIST OF FIGURES Fig. 1.1 Options for CO2 geologic storage 3 Fig. 1.2 Schematic for CO2 EOR 6 Fig. 2.1 Mohrs circle at assuming total stresses independent of pore pressure 16 Fig. 2.2 Mohrs circle for normal stress regime 17 Fig. 2.3 Mohrs circle for thrust stress regime 18 Fig. 2.4 Flowchart for the determination of minimum reservoir pressure 21 Fig. 2.5 Body-centered pores in a cubic lattice at macroscopic level 22 Fig. 2.6 Behaviors of porosity and pore collapse stress at different stress levels 25 Fig. 2.7 Plot of average values of stresses versus porosity at different initial porosity 27 Fig. 2.8 Matching of the model parameters with experimental average values 29 Fig. 2.9 Matching of experimental data with the analytical solution to determine an optimal time for CO2 injection 31 Fig. 2.10 Validation and comparison of the developed model with field 33 Fig. 3.1 Pressure-Temperature phase diagram for CO2 36 Fig. 3.2 Flowchart for the prediction of carbon dioxide CO2 behaviors 39 Fig. 3.3 Schematic of heat transfer to CO2 in a wellbore 41 Fig. 3.4 Carbon dioxide temperature profile inside the tubing 44 Fig. 3.5 Comparison of carbon dioxide and drilling mud temperature profile 46 Fig. 3.6 Simulator comparison with field measured data 47 Fig. 3.7 Comparison with field measured data 48 Fig. 3.8 Comparison for the use of experimental and constant thermodynamic properties of CO2 49 Fig. 3.9 Effect of geothermal gradient 51 Fig. 3.10 Effect of injection rate 52 Fig. 3.11 Effect of surface temperature 53 Fig. 3.12 Porosity variations and effect of using CO2 thermodynamic properties 54 Fig. 3.13 Porosity variations and effect of CO2 injection at different depths 55 Fig. 4.1 Flowchart for formation damage analysis 61 Fig. 4.2 Schematic of CO2, water, rock interaction and different phases 62 Fig. 4.3 Schematic of carbonate and asphaltene depositions 69 Fig. 4.4 Comparison of simulation results with experimental data 72 Fig. 4.5 Loss of porosity during calcium asphaltene cements vs the distance from the CO2 injection point 75 Fig. 4.6 Effect of injection rates on porosity change in the formation 77 Fig. 4.7 Effect of reservoir temperature on porosity change in the formation 78 Fig. 4.8 Effect of particle size heterogeneity on porosity change 80 Fig. 5.1 Flow chart of the developed methodology 85 Fig. 5.2 Asphaltene deposition at different CO2 injection rates 88 Fig. 5.3 Comparison of asphaltene deposition at CO2 and water injection 89 Fig. 5.4 Effect of CO2 injection rate on oil recovery 92 Fig. 5.5 Effect of immiscible and miscible pressure on asphaltene deposition 93 Fig. 5.6 Effect of different pressures on asphaltene deposition 94 Fig. 5.7 Effect of different MMP on asphaltene deposition 96 Fig. 5.8 Effect of different heterogeneities on asphaltene deposition 97 Fig. 5.9 Effect of asphaltene percentage in oil 98 | - |
| dc.format | application/pdf | - |
| dc.format.extent | 1601307 bytes | - |
| dc.format.medium | application/pdf | - |
| dc.language.iso | en | - |
| dc.publisher | 서울대학교 대학원 | - |
| dc.subject | Petroleum Engineering | - |
| dc.subject.ddc | 622 | - |
| dc.title | CO2 ENHANCED OIL RECOVERY BASED ON RESERVOIR COMPACTION, THERMAL MODELING, AND FORMATION DAMAGES | - |
| dc.title.alternative | 저류층압밀, 열모델링, 지층손상에기반한CO2증진오일회수 | - |
| dc.type | Thesis | - |
| dc.description.degree | Doctor | - |
| dc.citation.pages | 129 | - |
| dc.contributor.affiliation | 공과대학 에너지시스템공학부 | - |
| dc.date.awarded | 2014-08 | - |
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