GAS PERMEABILITY OF COAL BEDS AND THERMOCHEMICAL RECOVERY OF VISCOUS OIL

Transcription

1 GAS PERMEABILITY OF COAL BEDS AND THERMOCHEMICAL RECOVERY OF VISCOUS OIL A THESIS SUBMITTED TO THE DEPARTMENT OF PETROLEUM ENGINEERING OF STANFORD UNIVERSITY IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE By Wenjuan Lin June 2006

2 c Copyright by Wenjuan Lin 2006 All Rights Reserved ii

3 I certify that I have read this thesis and that in my opinion it is fully adequate, in scope and in quality, as partial fulfillment of the degree of Master of Science in Petroleum Engineering. Prof. Anthony R. Kovscek Principal Adviser I certify that I have read this thesis and that in my opinion it is fully adequate, in scope and in quality, as partial fulfillment of the degree of Master of Science in Petroleum Engineering. Dr. Louis Castanier iii

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5 Acknowledgments The first part of the thesis was prepared with the support of Stanford University Global Climate & Energy Project. The second part of the thesis was prepared with the support of Tyco Thermal Controls, BP, and the SUPRIA industrial affiliates. This support is gratefully acknowledged. However, any opinions, findings, conclusions, or recommendations expressed herein are those of the author and do not necessarily reflect the views of the supporters. I wish to express my deepest appreciation to my advisor Prof. Anthony R. Kovscek for his guidance, support and confidence throughout my work. I would also like to specially thank Dr. Tom Tang for his guidance and encouragement in the lab, without which this work could not have been completed. Special thanks to Dr. Louis Castanier and all the other SUPRI-A members who contributed in bringing a friendly and nice work atmosphere. I wish to acknowledge all the professors from the department for their valuable support. I would like to thank my friends, officemates and classmates for their friendship and encouragements to give the best of myself and made my stay at Stanford a wonderful experience. The last but not the least important, I would like to thank my family for their countless support. v

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7 Abstract With increasing demand for energy worldwide, the price of crude oil and natural gas has risen dramatically. Under such circumstances, unconventional oil and gas recovery has increased in importance. These unconventional oil and gas resources include heavy oil, oil in complex reservoirs, and coalbed methane. Coalbed methane (CBM) is found in deep, unmineable coal seams. Coal bed gases usually contain roughly 90% CH 4 and trace amounts of ethane, propane, butane, carbon dioxide and nitrogen. Hence, CBM is a very clean burning fuel. Currently, CBM is mainly recovered by primary recovery methods, in which only 20% to 60% of the gas is produced and a large amount of water is produced. Injection of N 2 and/or CO 2 is of substantial interest as an enhanced coalbed methane (ECBM) recovery method. Anecdotal evidence suggests that the coal matrix swells/shrinks with adsorption/desorption of gas on the coal surface. In turn, the permeability of the coal beds is affected. Experiments were performed to measure the permeability change of a coal pack with injection of different gases and gas mixtures. Multicomponent adsorption was then calculated using the extended Langmuir isotherm to see the relationship between the amount of adsorption and the evolution of permeability. Similarly, heavy oil is an unconventional resource of great interest. Many methods for heavy-oil recovery have been developed and studied in the past few decades. Several heavy-oil EOR methods, either commonly used or newly becoming popular, were investigated in our study. A feasibility simulation study was done using CMG STARS to understand opportunities for EOR (enhanced oil recovery) in Ugnu-like reservoirs. A simple economic analysis was also performed, and it suggests that heavy oil can be recovered economically. vii

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9 Contents Acknowledgments Abstract v vii 1 Gas Permeability of Coal Beds Background CBM and Coal Beds: formation and storage of CBM, structure of coal beds Gas Adsorption Isotherm Methods of CBM Recovery: primary recovery and gas injection CO 2 Sequestration in Coal Beds Evolution of Coal Bed Permeability Experiment Experimental Setup Experimental Procedures Experimental Results Adsorption Calculation Relationship between Amount of Adsorption and Change of Permeability Experiments at High Temperatures Summary and Conclusions Future Work Bibliography 15 ix

10 2 Thermochemical Recovery of Viscous Oil Introduction Model Description Grid Definition Reservoir Model Fluid Model Relative Permeability Models Efficiency of different heavy-oil recovery methods Case Study Simulation Result Sensitivity study of important parameters Location of Producer Location of Injector Well Bottom-Hole Pressure Preheating Heterogeneity Relative Permeability Economic Analysis Discussion Conclusions Bibliography 53 A A Typical Input File for CMG STARS 79 x

11 List of Tables 2.1 Rock and reservoir properties of Ugnu Reservoir [5] Properties of the reservoir fluid components K v values for the reservoir fluid components Economics of electrical heating, cyclic steam injection and SAGD Economics of SAGD processes with different steam injection rate xi

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13 List of Figures 1.1 Coal bed dual porosity/permeability structure [4] Natural cleats/fractures in coal beds [14] Pictorial representation of gas molecules inside a coal pore [5] Migrigation of gas in coal beds [5] Primary recovery of CBM Mechanisms of permeability change of coal beds: (a) cleat closure due to an increase of effective pressure thereby decreasing permeability, and (b) matrix shrinkage due to desorption of gas thereby increasing permeability Experimental gas adsorption curves on Powder River Basin coal at 22 C [13] Schematic of the experimental setup at room temperature The coalholder system: (a) inner coal holder and outer steel tube, and (b) assembled coalholder Absolute permeability of the coal pack versus pore pressure for pure gases at 22 C, net overburden pressure 400 psi Absolute permeability of the coal pack versus pore pressure at 22 C, net overburden pressure 400 psi Fractional surface coverage versus permeability reduction for pure gases at 22 C, net overburden pressure 400 psi Fractional surface coverage versus permeability reduction for binary mixtures at 22 C, net overburden pressure 400 psi xiii

14 1.14 Critical temperature of N 2 and CO 2 binary mixtures estimated using Kay s rule Schematic of the experimental setup at high temperature Coalholder in oven: (a) outside of the oven, and (b) inside of the oven Absolute permeability of the coal pack versus pore pressure for CO 2, net overburden pressure 400 psi Reciprocal of permeability reduction versus pore pressure for CO 2, net overburden pressure 400 psi Steam assisted gravity drainage: (a) illustration of the SAGD process [8], and (b) steam chamber developed in a SAGD process [12] Grid used in CMG STARS Logarithmic permeability and porosity correlation of Ugnu sand Heterogenous reservoir porosity and permeability maps: (a) porosity map without correlation in any direction, (b) porosity map with great continuity in horizontal direction, (c) permeability map without correlation in any direction, and (d) permeability map with great continuity in horizontal direction Properties of reservoir components: P-T diagram (before and after lumping) Viscosity of reservoir fluid as a function of temperature Reservoir fluid properties: (a) volume factor of oil, and (b) gas-oil ratio Relative permeability curves I [6]: (a) water-oil relative permeability, and (b) gas-liquid relative permeability Relative permeability curves II: (a) water-oil relative permeability, and (b) gas-liquid relative permeability Incremental oil recovery versus system energy input for all EOR cases Sensitivity of well location of producer to cumulative recovery (electrical heating, without heat loss through over- and under-burden) Sensitivity of well location of producer to cumulative recovery (electrical heating, with heat loss through over- and under-burden) xiv

15 2.13 Cumulative oil recovery for different locations of the injector (VAPEX, homogeneous reservoir) Oil production rate for different locations of the injector (VAPEX, homogeneous reservoir) Producer well bottom-hole pressure for different scenarios of SAGD Cumulative oil recovery for different production scenarios of SAGD Cumulative oil recovery for SAGD and primary recovery (with/without preheating) Results of simulation for different degrees of heterogeneity of the reservoir Cumulative oil recovery for different relative permeability functions and heterogeneity (SAGD and electrical-heating-assisted recovery) Cumulative oil recovery for different relative permeability functions Reservoir fluid properties: (a) oil density, and (b) formation volume factor of water Temperature profiles at different time in SAGD xv

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17 Chapter 1 Gas Permeability of Coal Beds Abstract Coal bed methane has grown in importance as an energy source as effective means to release methane from this tight, fractured rock have been developed. Among several enhanced recovery methods, carbon dioxide injection stands out as an efficient way to both increase coal bed methane recovery and sequester greenhouse gases. One area of particular interest for enhanced coal bed methane recovery operations is the permeability change of the coal bed during CO 2 injection, because permeability decides injectivity into a coal bed. In this study, experiments measured the change of the absolute permeability of a coal pack as a function of the pore pressure and the injected gas composition. In the experiments for each composition, we saturated the coal pack at a series of increasing pore pressures at a constant net overburden pressure. Thus, the amount of adsorption varied. An analysis based on the experimental data and the measured pure component Langmuir gas adsorption isotherm, indicated a relationship between pore pressure, the change of permeability and the amount of adsorption. Results from the lab show that for a certain gas composition, the absolute permeability decreases with the increase of pore pressure. From gas adsorption isotherms, it is found that adsorption increases with the increase in pressure. Therefore, we conclude that loading of coal surfaces with adsorbed gas causes permeability reduction. Also, pure CO 2 leads to the greatest permeability reduction among CO 2, 1

18 N 2, and CH 4. Pure CO 2 injection leads to significant loss of permeability, but 10% to 20% by mole of nitrogen in the injection gas helps to preserve permeability. 2

19 1.1 Background CBM and Coal Beds: formation and storage of CBM, structure of coal beds Coal bed methane is formed during the process of coalification and is trapped in the coal seams thereafter. Therefore, CBM has the same source rock and storage rock. The composition of the gas in coal seams is 90% of CH 4 and trace amounts of ethane, propane, butane, carbon dioxide and nitrogen [12]. One cubic foot of methane gas has a heating capacity of approximately 1000 BT Us (British thermal units). For the same amount of heat generated, CH 4 emits the least amount of CO 2 compared with the other hydrocarbons. Therefore, CBM is a very clean low CO 2 producing fuel. Besides that, coal beds are considered as potential sites of CO 2 sequestration along with depleted gas/oil reservoirs and underground saline aquifers. The coal beds mentioned in CBM recovery and CO 2 sequestration are deep, unmineable coal beds. Coal beds are known to have a dual porosity/permeability system, consisting of primary and secondary storage and mass transfer systems (Figure 1.1). The primary porosity system (PPS) refers to the pore space in the coal matrix. It accounts for the majority of the coal bed porosity. The PPS contains the vast majority of the gas-in-place volume. Thus, PPS is the major residence of the adsorbed gas in coal beds. The secondary porosity system (SPS) refers to the natural fractures/cleats in the coal beds (Figure 1.2). It accounts for the major part of permeability for fluid flowing in coal beds. The free gas in coal beds mainly resides in the SPS. Contrary to conventional natural gas resources in sandstone reservoirs, gases in coal beds exist in the coal seams mainly as adsorbed gas on the coal surface. Only a very small amount of gas (less than 10%) exists in the macropores and cleat network as free gas (Figure 1.3). The adsorbed gas in coal beds is said to have liquid-like density [11]. The gas stays adsorbed on the coal surface, until certain conditions are satisfied, for instance, a decrease of pressure. Then, the gas desorbs from the coal surface. The desorbed gas concentrates in the pore spaces of the coal matrix. With the increase of the gas concentration in the pore spaces, the gas diffuses to the 3

20 cleat/fracture network through the matrix and then flows to production wells through the cleat/fracture network. The flow of gas in the cleat/fracture network is Darcy flow. Therefore, the gas migrigation in coal beds includes three stages: desorption from coal surface, diffusion through coal bed matrix and Darcy flow in cleat/fracture network (Figure 1.4) Gas Adsorption Isotherm Knowledge of the competitive adsorption of gas on coal surfaces is important to understand the form of gas existence in coal beds, elucidate mechanisms for enhanced coal bed methane recovery, and design CO 2 sequestration in coal beds. Gas adsorption is a complex process. In the literature, the majority of the isotherms are classified into five types and numerical isotherm models were developed [15]. Among the numerous isotherms, the isotherm based on the Langmuir approach is the most widely used. The amount of pure gas adsorbed is calculated by the Langmuir equation: v = v mbp 1 + Bp (1.1) θ = v v m = Bp 1 + Bp (1.2) where, v is the amount adsorbed in volume in scf/t, v m is the monolayer amount adsorbed in scf/t, B is the Langmuir constant, p is pressure in psi, and θ is fractional surface coverage. For gas mixtures the extended Langmuir equation gives the amount of adsorption: v i = v mib i p i 1 + n (1.3) B j p j j=1 θ t = n θ i = i=1 Bi p i 1 + n (1.4) B j p j j=1 4

21 Tang et al [13] showed that Langmuir isotherm adequately models pure gas adsorption. Arri et al [2] showed that the extended Langmuir isotherm provided a reasonable correlation of the experimental data. In our study, we used the Langmuir isotherm to calculate the volume of the adsorbed gas for both pure gases and mixed gases Methods of CBM Recovery: primary recovery and gas injection Currently, coal bed methane exploitation occurs mainly through primary recovery using hydraulic fractures (Figure 1.5). In primary recovery, coal bed methane wells are completed open hole. Casing is set to the top of the target coal bed and the underlying target zone is under-reamed and cleaned out with a fresh-water flush. A down-hole submersible pump is then used to move water up the tubing. With the pumping out of water, the reservoir is depressurized. Methane desorbs from the coal surface, diffuse to the cleats/fractures and flow to the well bottom together with water. The gas then separates from the water and flows up the annulus. A form of hydraulic fracturing is usually employed in primary recovery to attain enough permeability in the near wellbore region, because coal beds usually have small permeability. The primary methods typically recover less than half of the methane resource in a coal bed. Also, primary methods have the disadvantage of producing a lot of water. Injection of nitrogen and/or carbon dioxide into coal beds are two means to increase the ultimate recovery and produce less water. Field test results are reported elsewhere [9]. Nitrogen is used because of its availability and typically gives earlier incremental recovery [16]. On the other hand, carbon dioxide may be preferred because it is effective in displacing methane, adsorbs strongly to coal surfaces thereby impeding premature breakthrough, and coal beds are effective geological sites for CO 2 sequestration. While substantial research on coal bed methane recovery has been done and is underway, there are numerous unanswered questions. One interesting area that needs more investigation is the permeability change of coal beds as gases adsorb/desorb. 5

22 Injecting N 2 and CO 2 as enhanced coal bed methane (ECBM) recovery methods employ different mechanisms. With the injection of N 2, the partial pressure of CH 4 in the coal seams deceases. Accordingly, CH 4 desorbs from the coal surface and is driven to the production well by the injected N 2. On the other hand, CO 2 displaces the methane on the coal surface, because coal has stronger affinity for CO 2 than CH 4. In both mechanisms, the desorbed methane diffuses through the matrix and flows to the production well through the fracture and cleat system and is thereby produced. In CO 2 injection, the injected CO 2 adsorbs on the coal surface and remains there CO 2 Sequestration in Coal Beds The three geologic settings under consideration for CO 2 sequestration are depleted oil and gas reservoirs, deep saline aquifers, and deep coal beds. Separate research on storage of CO 2 in these sites has been done extensively. The mechanisms of CO 2 storage in these geological settings are different. Oil and gas reservoirs initially exist because there is a geologic trap and seal. As long as the stress changes during production operations have not damaged the seal, these formations should retain buoyant CO 2 indefinitely within limits imposed by the pressure and stress changes that occur during CO 2 injection. Deep saline aquifers may or may not have an effective trap and seal. The mechanism of storing CO 2 in deep brine aquifers include structural trapping (if there is an effective seal or trap), solubility in the saline, residual trapping and mineralization. Storage in coal beds relies primarily on adsorption of CO 2 on the surfaces of coal to restrict movement of the CO 2, Figure Evolution of Coal Bed Permeability An important issue during gas injection into coal beds is the permeability change during gas production and injection. It is believed that two factors induce changes in coal bed permeability [6]. One is effective pressure related and the other is adsorption/desorption related. For example, the change of permeability in a coal bed during pore pressure decrease is the result of two competitive effects [3]. As pore pressure decreases under a constant overburden pressure, the effective pressure decreases and 6

23 permeability decreases due to the cleat compression, i.e. closure of fractures (Figure 1.6(a)). On the other hand, as pressure decreases, the adsorbed gas desorbs from the matrix of the coal bed, which causes the shrinkage of the matrix and an increase in permeability (Figure 1.6(b)). The role of effective stress and/or matrix shrinkage/swelling on coal bed permeability has been investigated by many researchers [3], [6], [10], [7]. Palmer and Mansoori s theoretical formulation for stress-dependent permeability, take into account both the effect of stress and matrix shrinkage under uniaxial strain condition. 1.2 Experiment Between the two mechanisms of coal bed permeability change, we were interested in investigating the adsorption/desorption related permeability change. We did experiments using a coal pack. We kept the net overburden pressure constant to eliminate the effect of changing efficient pressure Experimental Setup The experimental apparatus is illustrated schematically in Figure 1.8. The apparatus includes two high pressure gas containers for injected gas and overburden supply, a coal pack with the coal holder system, a pressure regulator for measuring the pressure drop across the coal pack and a flow meter for measuring the gas flow rate. We used a soap bubble flow meter in our experiments. The heart of the setup is the coal holder system (Figure 1.9). The coal sample is from the Powder River Basin, Wyoming. The depth of the coal beds is about 800 to 1200 f t. It was delivered to Stanford filled with formation water. The coal sample was then dried and ground to a particle size of 60 meshes. Thereafter, it was stored in an air-tight vessel under vacuum to avoid oxidation. The ground coal was tightly packed into a rubber sleeve and compacted to form a semi-consolidated porous medium. The porosity and permeability of the pack were uniformly distributed. The rubber sleeve is tightly fixed in a second sleeve with holes in it to allow confining 7

24 pressure to be exerted on the pack (Figure 1.9(a)). There was a third steel sleeve that covered the inner coal holder and formed an annulus to hold the overburden pressure (Figure 1.9(b)). The compositions of the injected gases used in the experiments are as follows: pure CH 4, pure N 2, 25% CO 2 +75% N 2, 50% CO 2 +50% N 2, 75% CO 2 +25% N 2, 85% CO 2 +15% N 2, and pure CO 2. For pure gases, we used high pressure lab gases. The mixtures were made according to partial pressure. We made the mixtures to have a total pressure of 800 psi. Then we could do experiments with the pore pressure as high as 600 psi. We made two one-liter bottles of mixture together using two containers connected, then we isolated them and used one after another. Otherwise, it is not possible to achieve 600 psi. For each gas composition, gas was injected into the coal pack and the system was allowed to reach steady state. After measurement of pressure drop and gas flow rate through the coal pack, the pore pressure was increased, while the net overburden pressure was kept constant at 400 psi. For every pore pressure, steady state was achieved in one or two days. Saturation was considered to be achieved when the pressure in the inner coal holder did not change significantly after shutting off gas injection for about 2 hours. The temperature was constant at the lab temperature, 22 C, throughout this set of experiments Experimental Procedures We followed the following procedures. 1. Make a coal pack: Put a rubber sleeve into the inner coal holder; Pack some ground coal tightly into the inner coal holder, taking care that all part of the coal pack has uniform porosity and permeability; Seal the inner coal holder with two caps and solvent resistant sealant at both ends and wait until the sealing agent dry; Connect two tubes at the outlets of the both end of the inner coal holder (Figure 1.9(a)); 8

25 Put the inner coal holder into the outer holder and seal the out holder with two caps at both end, with the tube on the end of the inner holder going through the holes in the center of the out holder caps (Figure 1.9(b)). 2. Check the coal holder system for leakage: the overburden pressure and the pore pressure should be well isolated from each other. 3. Measure and calculate the initial porosity of the coal pack using helium(net overburden pressure=400 psi). Helium was chosen because it was thought not to adsorb on coal. 4. Connect apparatus as shown in Figure 1.8. Examine the system carefully before experiments to make sure that there is no leakage along the line. 5. Measure and calculate the initial permeability of the coal pack. Helium was injected at 400 psi overburden pressure, and Darcy s Law (Equation (1.5)) was used to obtain the permeability. 6. Measure and calculate the permeability of the coal pack at a series of increasing pore pressures under the same net overburden pressure (400 psi) for different gas compositions. Saturate the coal pack overnight with the tested gas at a certain pore pressure. Let the tested gas flow through the coal pack at different pressure gradients and measured the flow rate after steady flow rate were reached. Calculate the permeability using Darcy s Law (Equation (1.5)) Experimental Results The permeability of the coal pack to gas could be calculated using Darcy s Law for gas flow: k g = 2000µ g q g p g L A[(p 1 + p 2 )(p 1 p 2 )] (1.5) 9

26 where, k g is the absolute permeability of the coal pack in md, µ g is the gas viscosity in cp, q g is the gas flow rate at atmosphere pressure in cc/s; p a is the standard atmosphere pressure in atm, L is the length of the coal pack in cm, A is the cross sectional area of the coal pack in cm 2, p 1 and p 2 is the inlet and outlet pressures of the coal holder in atm. The results of our experiments are shown in Figure 1.10 and Figure Figure 1.10 is for pure gases and Figure 1.11 is for mixture gases together with curves for pure N 2 and pure CO 4 for comparison. Each figure plots permeability versus pore pressure. From the figures, it is seen that the permeability of the coal pack decreases with the increase of the pore pressure. That is, in all cases, as the amount of gas adsorbed increases, the permeability decreases. With the increase of pore pressure, the amount of adsorption increases (Figure 1.7). More pore spaces were occupied by the molecules of adsorbed gas. Therefore, the permeability decreases with the increase of pore pressure, at a constant net confining pressure. From Figure 1.11, it is seen that permeability reduction is negligible for N 2, greater for CH 4 and the greatest for CO 2. Similar trends were measured for the mixture gases. With an increase of CO 2 in the mixture, the permeability decreases markedly. This is also reasonable, because we know that CO 2 is more readily adsorbed on coal beds than CH 4, and CH 4 is more readily adsorbed on coal beds than N 2 (Figure 1.7). Therefore, at the same pore pressure, as the fraction of CO 2 increases in the injected gases, there is an increasing amount of gas adsorbed, which caused more permeability reduction. At the same time, we noticed that the permeability did not change much for the mixture gases where CO 2 were 25%, 50% and 75% CO 2, while the permeability changed dramatically for the mixture of 85% CO 2. This last result indicates that a little bit of nitrogen (around 25%) helps to preserve permeability Adsorption Calculation According to the pressure versus adsorption relationship (Figure 1.7), the amount of adsorption increases with the increase in pressure. We calculated the amount of adsorption using the Langmuir equations and related the measured permeability and 10

27 the calculated amount of adsorption to see the effect of adsorption on permeability change. The volume of adsorption of pure gases and gas mixtures were calculated using Equation (1.1) and Equation (1.3). Then, the coverage of the adsorbed gas was calculated as follows. We used the concept of cross-sectional area of adsorbed gas molecules [8]. By doing this, we get values of coverage larger than 1 for CO 2. This represents multi-layer adsorption. Molecular cross-sectional area of N 2 is 16.2 Å 2 [1], CH 4 is 17.7 Å 2, and CO 2 is 19.5 Å 2. First, we assume that N 2 has monolayer adsorption on surface and when the surface is fully saturated the coverage of the adsorbed molecules is 1. Therefore, we calculated the specific surface area of the coal pack in our experiment using the adsorption data of pure nitrogen N m,n2 = 28.33v m,n 2 v 0 (1.6) A s = N m,n2 N a ξ N2 (1.7) The coverage is defined as the area occupied by the adsorbed molecules divided by the total specific surface area of the coal pack. If there is more than one gas species that is adsorbed on the coal surface, coverage for each gas is calculated and the sum of them accounts for the total coverage of adsorbed gases θ i = N m i N a ξ i A (1.8) θ t = θ i (1.9) where, N m is the monolayer moles adsorbed in mol, v 0 is the standard molar volume of gases in L/mol, N a is the Avogadro s number equaling molecules per mole, A s is the specific surface area of adsorbate in m 2, and ξ is the molecular cross-sectional area of adsorbed gas in m 2. We defined permeability reduction as the ratio of the primary permeability of the 11

28 coal pack to the experimental permeability after adsorption. R K = K i K(p) (1.10) After calculating the coverage of adsorbed molecules and permeability reduction, we can plot coverage versus permeability reduction Relationship between Amount of Adsorption and Change of Permeability From the adsorption versus permeability reduction plots, it is found that the permeability reduction became greater as the amount of gas adsorption increased (Figure 1.12 and Figure 1.13). For pure gases, the experimental permeability data versus the fractional surface coverage produced a trend line that is well described by a logarithmic relation. For the binary mixtures, however, the experimentally measured permeability data versus the fractional coverage computed from the extended Langmuir equations, could not be reduced to a single trend for all gas compositions, Figure From the plot of pure gases, it seems that the amount of adsorbed molecule coverage controls permeability reduction. This does not seem true for the mixture cases. Therefore, the hypothesis of the same amount of coverage of different gases leading to the same amount of permeability reduction may not be true. The answer to this question lays on the understanding of the mechanism of so-called swelling. We will investigate swelling more in future work Experiments at High Temperatures All of the experiments above were conducted at a room temperature of 22 C. For pure CH 4, pure N 2, 25% CO 2 +75% N 2, 50% CO 2 +50% N 2, 75% CO 2 +25% N 2, and 85% CO 2 +15% N 2, the critical temperature is all below 22 C (Figure 1.14). For pure CO 2, however, its critical temperature is 31 C that is above the experimental temperature. Therefore, phase behavior may exist in the experiments using pure 12

29 CO 2. To eliminate phase behavior and examine supercritical CO 2, we conducted experiments at 50 C. Figure 1.15 shows the photographic picture of the setup of the experiments at high temperatures. The setup is similar to the setup in the experiments at room temperature, except that the coal holder system was put in an oven (Figure 1.16). A new coal pack was made for the experiments at high temperatures. We did experiments using pure CO 2 at 50 C. Following the same procedures, we got the pressure versus permeability plot as shown in Figure From the figure, we found the same trend of decreasing permeability with the increase of pore pressure at high temperature. To see the magnitude of permeability reduction, we plotted pore pressure versus reciprocal of permeability reduction (p versus K 0 /K, Figure 1.18). From the figure, it is found that at the same pore pressure the permeability decreased to a greater extent at 22 C than at 50 C. This is because the volume of gas gas adsorbed at a given pressure decreases with the increase of temperature. 1.3 Summary and Conclusions N 2 and CO 2 injection are commonly considered as methods of ECBM. One issue worthy of attention for gas injection into coal beds is the permeability change of the coal. Two reasons are thought to cause the permeability changes. One the role of the effective overburden pressure. The other is gas adsorption/desorption related. Experiments were performed to investigate the adsorption/desorption related permeability change of a coal pack with the injection of different gases at room temperature and high temperatures. From the results of the experiments and adsorption calculation, we draw the following conclusions. 1. With the injection of pure gases, at the same pore pressure, permeability reduction is greatest for CO 2 followed by CH 4, and N Gas adsorption causes permeability reduction: the pore spaces in our coal pack or real coal beds are of the size of several gas molecules. With the adsorption of gases, the pore spaces were occupied by the adsorbed molecules. 13

30 3. When injecting N 2 and CO 2 mixtures, permeability reduction is reduced by maintaining N 2 within the mixture. A small amount of nitrogen (around 25%) greatly reduces the permeability reduction. 4. At high temperatures, the same trend of permeability reduction with the increase of pore pressure was observed. At the same pore pressure, lesser permeability reduction was observed at greater temperature. 1.4 Future Work In spite of the observation that coal bed permeability change correlates with gas adsorption and desorption, the mechanism for the phenomenon is unclear. Swelling and shrinkage have been proposed. These concepts explain the change of permeability as related to expansion and contraction of the coal matrix. We still do not know what causes the so-called swelling and shrinkage. Thus, it is helpful to understand the following: 1. the mechanism of gas adsorption on coal surfaces by studying the bounding forces, and 2. the form of existence of adsorbed gases. Based on the understanding on gas adsorption on coal surfaces, the following issues are suggested as future work: 1. efficiency of gas injection recovery, such as how much gas in place is recovered and how fast the injected gas breaks through, 2. other interesting aspects of coal beds and ECBM methods, such as the efficiency of CO 2 sequestration in coal beds and other ECBM methods, and 3. efficiency of CO 2 sequestration in coal beds 14

31 Bibliography [1] A.W. Adamson and A.P. Gast. Physical Chemistry of Surface. John Wiley & Sons, Inc., New York, sixth edition, [2] L.E. Arri, W.D. Yee, and M.W. Jeansonne. Modeling coalbed methane production with binary gas sorption. SPE presented at the SPE Rocky Mountain held in Casper, WY U.S.A., May [3] I. Gray. Reservoir engineering in coal seams: Part 1 -the physical process of gas storage and movement in coal seams. SPE presented at SPE Reservoir Engineering, February [4] S. Harpalani and G.L. Chen. Influence of gas production induced volumetric strain on permeability of coal. Geotechnical and Geological Engineering, 15: , [5] S. Harpalani and R.A. Schraufnagel. Shrinkage of coal matrix with release of gas and its impact on permeability of coal. Fuel, 69: , May [6] S. Harpalani and X. Zhao. The unusual response of coal permeability to varying gas pressure and effective stress. Rock Mechanics as a Guide for Effective Utilization of Natural Resources, Khair (ed.), pages 65 72, [7] Palmer I. and J. Mansoori. How permeability depends on stress and pore pressure in coalbeds: A new model. SPE presented at SPE annual Technical Conference and Exhibition in Colorado, the USA, revised for publication from SPE 36737, October

32 [8] S. Lowell and J.E. Shields. Powder surface area and porosity. London; New York: Chapman and Hall, pages 17 30, [9] M.J. Mavor, W.D. Gunter, and J.R. Robinson. Alberta multiwell micro-pilot testing for CBM properties, enhanced methane recovery and CO 2 storage potential. SPE presented at the SPE Annual Technical Conference and Exhibition held in Huston, TX U.S.A., September [10] J.P. Seidle and L.G. Huitt. Experimental measurement of coal matrix shrinkage due to gas desorption and implications for permeability increases. SPE presented at the International Meeting on Petroleum Engineering in Beijing, China, November [11] J.Q. Shi and S. Durucan. Drawdown induced changes in permeability of coalbeds: A new interpretation of the reservoir response to primary recovery. Transport in Porous Media, 56:1 16, [12] R. C. Surdam. The coal section: Coalbed methane information. Wyoming State Geological Survey, September [13] G.Q. Tang, K. Jessen, and A.R. Kovscek. Laboratory and simulation investigation of enhanced coalbed methane recovery by gas injection. SPE presented at the 2005 SPE Annual Technical Conference and Exhibition, Dallas, TX U.S.A., October [14] J.E. Warren and P.J. Root. The behavior of naturally fractured reservoirs. SPEJ, pages , September [15] R.T. Yang. Gas separation by adsorption processes. Butterworths Publishers, Johannesburg, South Africa, pages 26 51, [16] J.C. Zhu, K. Jessen, A.R. Kovscek, and F.M. Orr Jr. Analytical theory of coalbed methane recovery by gas injection. SPE presented at the 2002 SPE/DOE Improved Oil Recovery Symposium in Tulsa, OK U.S.A., April

33 Figure 1.1: Coal bed dual porosity/permeability structure [4]. 17

34 Figure 1.2: Natural cleats/fractures in coal beds [14]. 18

35 Figure 1.3: Pictorial representation of gas molecules inside a coal pore [5]. 19

36 Figure 1.4: Migrigation of gas in coal beds [5]. 20

37 Figure 1.5: Primary recovery of CBM. 21

38 (a) (b) Figure 1.6: Mechanisms of permeability change of coal beds: (a) cleat closure due to an increase of effective pressure thereby decreasing permeability, and (b) matrix shrinkage due to desorption of gas thereby increasing permeability. 22

39 Figure 1.7: Experimental gas adsorption curves on Powder River Basin coal at 22 C [13]. 23

40 Figure 1.8: Schematic of the experimental setup at room temperature. 24

41 (a) (b) Figure 1.9: The coalholder system: (a) inner coal holder and outer steel tube, and (b) assembled coalholder. 25

42 Figure 1.10: Absolute permeability of the coal pack versus pore pressure for pure gases at 22 C, net overburden pressure 400 psi. 26

43 Figure 1.11: Absolute permeability of the coal pack versus pore pressure at 22 C, net overburden pressure 400 psi. 27

44 Figure 1.12: Fractional surface coverage versus permeability reduction for pure gases at 22 C, net overburden pressure 400 psi. 28

45 Figure 1.13: Fractional surface coverage versus permeability reduction for binary mixtures at 22 C, net overburden pressure 400 psi. 29

46 Figure 1.14: Critical temperature of N 2 and CO 2 binary mixtures estimated using Kay s rule. 30

47 Figure 1.15: Schematic of the experimental setup at high temperature. 31

48 (a) (b) Figure 1.16: Coalholder in oven: (a) outside of the oven, and (b) inside of the oven. 32

49 Figure 1.17: Absolute permeability of the coal pack versus pore pressure for CO 2, net overburden pressure 400 psi. 33

50 Figure 1.18: Reciprocal of permeability reduction versus pore pressure for CO 2, net overburden pressure 400 psi. 34

51 Chapter 2 Thermochemical Recovery of Viscous Oil Abstract Viscous and heavy-oil exploitation has increased in importance over the past decades as conventional oil reserves have depleted. Secondary recovery methods and EOR (Enhanced Oil Recovery) are employed widely in heavy-oil exploitation. In our study, several EOR methods that are currently of interest in the industry were investigated using reservoir and fluid data from the Ugnu reservoir, North Slope of Alaska. Primary recovery, electrical-heating-assisted recovery, cyclic steam injection, vapor extraction (VAPEX), heated VAPEX, and steam-assisted gravity drainage (SAGD), were simulated using CMG STARS (2004). Results showed that, with the same amount of energy input, SAGD enhanced oil recovery to the greatest degree. Nevertheless, all of the EOR methods studied yielded greater recovery than primary recovery. A key finding is that the rate of energy input to the reservoir must be relatively large to affect recovery from this cold, viscous reservoir setting. A sensitivity study was conducted on the location of the producer, location of the injector in two-well gravity drainage configurations, well bottom-hole pressures (BHPs) in the SAGD process, preheating in the SAGD process, heterogeneity and relative permeability. In addition 35

52 to enhanced recovery, we are interested in the economics of an EOR process. Economic analysis showed that SAGD had better economics than electrical heating for the Ugnu-like reservoir. 36

53 2.1 Introduction Since 1859, the beginning of the so-called oil age, oil has played an increasingly important role in industries and human life. Due to the large amount of oil already consumed, current reserves of exploitable conventional oil have decreased. Therefore, the exploitation of unconventional petroleum resources, of which heavy oil is important, is drawing more and more interest. Methods of heavy-oil exploitation include primary recovery, steam injection (cyclic steam injection, steam drive, and SAGD), in-situ combustion, solvent injection (VAPEX), and electrical-heating-assisted recovery. Primary recovery, with the exception of the so-called foamy oil, produces little heavy oil [13], [14]. Heavy oil is very viscous making its mobility low and it generally contains little solution gas such that natural drive energy is low. Therefore, enhanced recovery methods are usually employed in the development of heavy-oil resources. Most recovery methods for heavy and viscous oil aim to improve the mobility of oil in-situ by heating and/or dilution of the crude. Cyclic steam injection is commonly used as a stand-alone enhanced recovery method as well as before steam drive, SAGD, or other enhanced oil recovery methods to preheat the reservoir and establish thermal communication. If operated properly, cyclic steam injection also helps to establish a pressure gradient around producers and aids injectivity by producing some oil around injectors. Steam drive [9] employs a principle similar to water flooding in that pressure gradients are established between injectors and producers and reservoir pressure is maintained. Steam injection aids recovery mainly by reducing the oil-phase viscosity significantly as the reservoir is heated. Steam drive is the most widely used method of heavy-oil recovery in the world at present. Steam drive, however, usually employs vertical well configurations in thick reservoirs where heat losses to adjoining formations are minimized. Additionally, steam override and channeling through high-permeability streaks can be a problem in steam drive. Newer recovery methods, such as electrical heating, SAGD and VAPEX, employ horizontal well configurations and are gravity stable. VAPEX may be applicable to thin formations where heat losses are prohibitive. Well patterns for SAGD [3] usually contain one horizontal production well at 37

54 the bottom of the formation and one horizontal well or several vertical injection wells above the production well (Figure 2.1(a)). The distance between injector and producer is a sensitive parameter. In SAGD, steam is injected to the formation and forms, ideally, an expanding steam chamber (Figure 2.1(b)). At the perimeter of the steam chamber, the steam heats the oil and condenses. The condensed steam transfers heat to the oil zone beyond the oil-steam interface. A thin layer of condensate and hot, low-viscosity oil is formed ahead of the steam chamber front. This hot, lowviscosity mixture drains by gravity downwards along the boundary of the chamber to the producer that is located at the bottom of the formation. The steam chamber expands upwards until it hits the top of the formation and then expands sidewards. A large part of the formation is thereby swept and a fair amount of oil is produced. One advantage of SAGD is that heated oil flows to the producer directly without having to displace the uncontacted oil in the reservoir. Disadvantages of SAGD may include significant steam requirements and the possibility of premature steam breakthrough to the producer. VAPEX [7] employs well configurations and gravity drainage principles similar to SAGD. In the process, hydrocarbon vapors (solvents), usually propane and/or butane are injected into a horizontal injection well that forms an expanding vapor chamber. At the perimeter of the vapor chamber, the injected solvents disperse/diffuse into the heavy oil and dilute it thereby reducing viscosity. The diluted, or in some cases, deasphalted oil drains downwards by gravity to a horizontal production well located at the bottom of the reservoir. VAPEX may be employed with the injectant at roughly reservoir temperature or with heated injectant. We refer to the latter as heated VAPEX. Electrical heating using mineral insulated (MI) cables [1] placed in a wellbore is, perhaps, the most conceptually simple thermal recovery process studied in this report. The heating element may be installed in the production well or in a gravity drainage fashion with the heater positioned above the producer. In electrical-heating-assisted recovery, electrical heaters are introduced in the formation. Alternating current flows along the heaters. The temperature of the heaters increases and then heats the oil around them. A lot of description of the history and principles of this method is 38

55 found in the literature [10]. This type of electrical heating method does not require surface or downhole-steam generation, potentially allows differential heating in the horizontal direction, and does not suffer from steam breakthrough from the injector to the producer. Potentially, there are significant capital cost savings as costly steam generation and hot fluid handling facilities are obviated. For all of the successes and potential of cyclic steam injection, steam drive and SAGD, heat loss from the formation to the under and overburden is still a concern. The application of electricalheating-assisted recovery was motivated by the advantages mentioned above and the premise that energy could be saved by reducing heat loss in the surface facilities and along the well bore in comparison to steam injection. In our study, we used a pattern simulation approach to understand the benefits and drawbacks of various recovery methods for viscous oil. The simulator employed is CMG STARS (2004), a thermal and compositional simulator. The reservoir and fluid models employed were developed using data available in the literature for Ugnu and other Alaskan North Slope reservoirs. Heavy-oil resources in the Ugnu deposit alone are estimated to be more than 6 billion bbl [6] thereby motivating study of recovery processes. In this report, six representative cases are explored to detect the recovery efficiency of various heavy-oil recovery techniques. A sensitivity study performed for several parameters that were considered critical in field production and economic analysis for SAGD and electrical heating is presented. 2.2 Model Description Basic rock and reservoir properties that were selected as representative are shown in Table 2.1. In our simulation, several models of the distribution of permeability and porosity were created. All are 2D grid models. In addition to the model describing the porosity and absolute permeability of the reservoir, a fluid model describing the reservoir fluid components and properties, and relative permeability models were developed for the simulations. Details follow. 39

56 2.2.1 Grid Definition The grid is a 2D vertical model of size 1 by 39 by 19 grid blocks (Figure 2.2), representing a 1 ft by 525 ft by 95 ft volume section of the reservoir. The dimensions of the grid blocks were y = 93.5, 46.6, 7*10, 21*5, 7*10, 46.6, 93.5 ft for 525 ft (160 m) total, and z =19*5ft for 95 ft (29 m) total Reservoir Model Representative permeability and porosity data from the Ugnu reservoir were provided by BP. The permeability in the sample data is in the range of 388 md to 1094 md, with an average of 762 md. The porosity in the sample data is in the range of to 0.34, with an average of The logarithm of permeability and porosity has a correlation as shown in Figure 2.3. Using the histogram of the field data, several permeability and porosity distributions were simulated using WinGslib (sequential Gaussian simulation). Figure 2.4 shows a realization of the heterogeneous distribution of permeability and porosity without continuity in any direction and a realization of heterogeneous permeability and porosity distribution with great continuity in the horizontal direction (correlation ratio :1). After obtaining porosity and permeability realizations, the reservoir simulation grid model was populated with these porosity and permeability data. For the homogeneous cases, the whole grid was assigned a uniform porosity (0.33) and permeability (762 md) Fluid Model The reservoir fluid is represented as a six-component model (water, four oil components and solvent). A multi-component fluid analysis of the component properties of Schrader Bluff crude oil [5] was used to construct the 4 representative oil-phase components. The component compositions were adjusted to give a greater fraction of heavy components and thereby obtain a sample of greater gravity than Schrader Bluff oil. The Schrader Bluff formation underlies the Milne Point Unit located on Alaska s North Slope. In the absence of compositional data for Ugnu, this appeared to be the best approach. 40

57 The initial compositional description of the Schrader Bluff crude oil contained 12 components, CO 2, C 1, C 2, C 3, nc 4, nc 5, C 6, C 7 9, C 10 13, C 14 19, C 20 35, and C 36+. Properties of these components, including critical pressure, critical temperature, specific volume, and accentric factor, are listed in Table 2.1. The properties of all of these components were imported into CMG WinProp (2004) and then lumped into several new pseudocomponents. Adjacent components were combined to obtain roughly equal mass fractions of the pseudocomponents. The initial 12 components were lumped into 4 new components: C 1, C 2 14, C 20 35, and C 36+. The names of the lumped components reflect the lumping strategy. The range of subscripts represents the range of carbon numbers of each pseudocomponent. The molecular fraction of the four components in the oil phase is 0.273, 0.423, 0.164, and respectively. Adding H 2 O and C 3, we created a new six-component fluid model for simulation. PVT calculations with the lumped components, such as computation of the PT envelope, showed that the lumped component model produced virtually identical results (Figure 2.5) as the expanded description. WinProp provides the fluid data, including the viscosity table, that are used in the input files for STARS directly (Table 2.2 and Table 2.3). Figure 2.6 shows the viscosity versus temperature correlation of the reservoir fluid. Figure 2.7 plots the formation volume factor, Bo, and solution gas oil ratio, R s. The bubble point pressure is about 1170 psi and the initial solution gas-oil ratio is about 106 SCF/bbl. The oil gravity is 14.6 AP I Relative Permeability Models Two sets of relative permeability were used in our study. The first is from the literature[6] (Figure 2.8(a) and Figure 2.8(b)) and the second is made up using Coreytype functions [5] (Figure 2.9(a) and Figure 2.9(b)). 41

58 2.3 Efficiency of different heavy-oil recovery methods Case Study To compare the efficiency of different oil recovery methods, we designed six cases corresponding to different recovery methods as follows: Case 1: Single horizontal well, 4000 days of primary production. Case 2: Single horizontal well, 500 days of primary production and then 3500 days of electrical-heating-assisted production at a continuous heating rate of 300 BT U/(hr/ft). Case 3: Single horizontal well, 500 days of primary production and then cyclic steam injection (50 days of steam injection, 10 days of shut-in, and 100 days of production for each cycle) for 22 cycles until 4000 days of production. Case 4: Two horizontal wells in a dual-well gravity drainage configuration, 500 days of primary production and then continuous propane injection with no heating of the injection gas for 3500 days. Case 5: Two horizontal wells, 500 days of primary production and then continuous propane injection that is heated electrically at 150 BT U/hr/f t for 3500 days. Case 6: Two horizontal wells in a dual-well SAGD configuration, 500 days of primary production and then continuous steam injection for 3500 days Simulation Result All of the above cases were run for a duration of 4000 days with the first 500 days specified as primary production. The intent of a primary-production period was to reduce reservoir pressure somewhat and establish flow into the producer. For the injection cases (SAGD, cyclic steam injection, VAPEX and heated VAPEX), a horizontal production well was located 7.5 ft above the lower boundary of the grid, and a horizontal injection well was located 20 ft above the producer. The BHPs (bottom-hole pressure) of the injectors were all 1305 psi which was a little bit greater than the initial reservoir pressure (1300 psi); and the BHPs of the producers were 42

59 1285 psi which was not very much below the reservoir initial pressure. This producer BHP was chosen because the main driving force for SAGD and VAPEX is gravity, therefore, we did not need to establish a significant pressure difference between the injector and the producer. This pressure also kept the reservoir above its bubble point pressure. Lower producer BHPs were also tried. When the producer BHP was low, the injector BHP still needs to be somewhat high to inject steam into the reservoir. For example, when the producer BHP is 100 psi, the injector BHP should be as great as about roughly 800 psi to inject any steam at the end of the 500 days of primary production. This is because the oil is very viscous; therefore, 500 days of primary recovery did not deplete the reservoir pressure greatly. Significant pressure difference between the producer and injector gave large pressure gradient between the two wells and is not consistent with operation of SAGD. Therefore, wells were operated at substantial pressures with some reduction in pressure over time. Initial attempts at optimizing the operating pressure are presented in the sensitivity analysis section. Figure 2.10 plots the cumulative oil recovery versus energy input for the above six cases. All of the six cases operated at the same BHPs, and all of the EOR methods have the same total energy input. The energy as equivalent oil and natural gas volumes are also plotted on the x axis. The conversion factor from energy to volume of oil is BT U/bbl and from energy to volume of natural gas is 1000 BT U/SCF [10]. In the case of SAGD it appears that 25 bbl of oil are produced for every 1 bbl of oil input as steam energy. For cyclic steam injection and electrical heating these ratios are about 16 and 8, respectively. Recovery for the cyclic steam and electrical heating cases per unit of energy input could be substantially greater if the producer bottom-hole pressure was in the range of 100 to 400 psi. Heating to reduce oil viscosity and low producer pressures makes more effective use of the reservoir s natural drive energy. Electrical heating assisted recovery and the role of producer bottom-hole pressure are discussed in reference [10]. Cumulative oil recovery increases with the decrease of bottom-hole pressure, and the best recovery is obtained with the minimum BHP and the maximum heat input. From comparison of Figure 2.10, we find that SAGD has the greatest incremental oil recovery among all of the six cases with the same energy input, except for the 43

60 primary recovery case that has no heat input. The cumulative oil recovery resulting from SAGD was more than 6 times that of primary recovery. All of the other EOR methods including cyclic steam injection, electrical-heating-assisted recovery, heated VAPEX, and VAPEX, gave greater oil recovery than the primary case, by factors of 5, 3, 2, and 1.5 respectively. For the cyclic steam injection case, 22 cycles were conducted in total on about 160-day cycles. The duration of steam injection was fairly intensive, but is not atypical for cyclic steam injection during field applications. Although not explored explicitly, cyclic steam injection does not appear to be approaching an economic limit. That is cumulative recovery increases substantially during each cycle. The oil recovery associated with the electrical-heating-assisted method increases as the heating rate increases [10], as is expected intuitively. With the same energy input, however, SAGD had greatest recovery because the injected steam helps to maintain reservoir pressure and establishes a pressure gradient throughout the reservoir. 2.4 Sensitivity study of important parameters Many factors should be considered to determine not only the method to choose for a particular reservoir, but also the conditions to choose for a particular method to get good economics in the development of a reservoir. Sensitivity study of six parameters that were considered important in heavy-oil reservoir development was conducted. The study is not exhaustive given the large number of parameters (more than 10) and possible cases to be run Location of Producer The producer was located at different grid blocks and simulations were run for the electrical-heating-assisted recovery case. For all of the cases, the BHP of the producer is 450 psi; the heating rate is 300 BT U/(hr/ft). Without heat loss through the overand under- burden formations (Figure 2.11), cumulative oil recovery decreases as the producer is raised from the bottom of the reservoir (grid block number 1, 20, 18) to the top of the reservoir (grid block number 1, 20, 2). This is because when 44

61 the producer was at the bottom of the reservoir, there is more heated oil above the producer that was drained. When there was heat loss through the over- and underburden formations (Figure 2.12), the well had greater cumulative oil recovery for the lower locations. The lowest position case no longer gave the greatest oil recovery due to heat loss through the over- and under- burden formations. Given the advantage of a bottom producer that maximizes gravity drainage forces for SAGD and VAPEX, the producer was located at the bottom of the grid (grid block number 1, 20, 18) in our simulation Location of Injector For the two-well configurations (SAGD, VAPEX and heated VAPEX cases), the affect of the location of the injector on oil production was also studied. The producer was set at the bottom of the grid (grid block number 1, 20, 18) for all cases. For both homogeneous and heterogeneous grids, the location of the injector with increased separation between the injector and producer was tested. From the results shown in Figure 2.13 and Figure 2.14, locating the injector lower in the reservoir and closer to the producer gave greater oil production rate at the beginning of production. In short, the closer the injector and producer the sooner that thermal communication is established. The advantages of an injector low in the formation, however, were lost at the late stage of production. For all the cases run, when the injector is 20 ft above the producer (injector at grid block 1, 20, 14), the producer had largest cumulative oil recovery at the end of 4000 days of production. Similar results were obtained for the heterogeneous cases. Injectors positioned lower in the formation had greater oil recovery at the beginning, even though the best recovery case was different from the homogeneous cases. The different results for the homogeneous cases and the heterogeneous cases indicate that the effect of reservoir layering is also important to study before deciding well configurations for SAGD and VAPEX. 45

62 2.4.3 Well Bottom-Hole Pressure Even though all of the six cases used the same well constraints in our simulation in part 3 for good comparability between different recovery methods, these choices of well constraints were not necessarily the best for all of the cases. If we choose different production and/or injection conditions, the oil recovery is different for each case. Take SAGD as an example, if we use a schedule of BHP of the producer and the injector versus time, the results are different. Figure 2.15 shows several scenarios with different producer BHP. For the first SAGD case (SAGD 1), the BHP of producer was constant (1285 psi) during the duration of production. For the second case (SAGD 2), the BHP of the producer was 1285 psi from the beginning to the 1600th day, and 1265 psi for the last days of production. For the third case (SAGD 3), the BHP of the producer was 1285 psi from the beginning to the 1600th day, 1265 psi from the 1600th day to the 2300th day, and 1245 psi for the last days of production. Similarly, for SAGD 4, the BHP of the producer was 1285 psi from the beginning to the 1600th day, 1265 psi from the 1600th day to the 2300th day, 1245 psi from the 2300th to the 3200th day, and 1225 psi for the last days of production. For all scenarios, the BHP difference between the producer and the injector was the same (20 psi). Figure 2.16 shows that the cumulative oil recovery for these different scenarios increases as the operating pressure is decreased. That is, reducing gradually the reservoir pressure over time results in greater recovery. This is not necessarily an optimized case and more aggressive reduction in pressure over time is possible. Optimization of pressure reduction for the other recovery methods is also possible to obtain greater recovery Preheating The effect of preheating was also studied. We supposed that preheating with electrical heaters increased the oil recovery at the beginning of production and established earlier communication between the producer and the injector, and thus increased the injectivity afterwards. Figure 2.17 shows the cumulative oil for primary recovery and SAGD. For the primary recovery case, preheating the reservoir for the first 150 days increased the oil recovery during the period of preheating, but it did not affect 46

63 recovery afterwards. A similar result was obtained for the SAGD cases. Different preheating time, either from the 1st day to the 150th day, or from the 150th day to the 300th day, or from the 350th day to the 500th day, did not give substantially different results. For all of the SAGD cases here, the producer BHP was 1285 psi, and the injector BHP was 1305 psi which was slightly greater than the reservoir pressure. This pressure for the injector is very high. If we want to use lower injector and producer BHP without increasing the pressure drop between injector and producer, preheating is needed to establish earlier communication between the two wells and greater initial oil production. When the producer BHP was 1000 psi and the injector BHP was 1020 psi, without preheating, at the end of the first 500 days of primary recovery, the pressure near the injector was about 1160 psi. No steam could be injected at 1020 psi. If we had a 500-day preheating period using an electrical heater in the producer and the injector with a heating rate of 600 BT U/hr/day, it is possible to inject steam. During field production when a desired injection pressure has been decided, preheating strategy, (heating rate, heating duration, etc.) most be decided accordingly Heterogeneity Simulations for heterogeneous absolute permeability and porosity as mentioned above in the reservoir model part (Figure 2.4) were run for all of the six cases. Results (Figure 2.18 and Figure 2.19) show that the heterogeneous cases have somewhat smaller cumulative oil recovery and oil rate Relative Permeability Two sets of relative permeability were used in our simulation (Figure 2.8 and Figure 2.9). Also, different methods to estimate three-phase relative permeability from twophase data (STONE1, STONE 2 and Baker [5]) were used. All cases ran equally well with each 3-phase relative permeability method. Results for different three-phase relative permeability estimation methods gave similar recovery (Figure 2.19). On the 47

64 other hand, results for different relative permeability sets were different (Figure 2.20). 2.5 Economic Analysis From the results of the simulation, we see that the enhanced oil recovery methods investigated do increase the oil recovery efficiently. EOR methods, however, demand extra energy to be put into the reservoir. This means greater investment. Economic analysis is needed before deciding to conduct an EOR method. In our study, we did a basic economic analysis of cyclic steam injection, SAGD, and electrical heating. In conducting the economic analysis, we calculated the net present value (NPV) of a process. Table 2.4 shows the results of the economic analysis. All of the three cases produced at a BHP of 1285 psi, and had the same amount of total energy input. All of the calculations are based on an oil price of $20/bbl. From the results, cyclic steam injection has better economics than SAGD and electrical heating, even though it has less oil recovery than SAGD, because only one well is needed. SAGD has better economics than electrical heating. In the above calculation, all of the three cases were based on a producer BHP of 1285 psi, and had the same amount of total energy input. The BHP was such chosen because it was not much lower than the steam injection pressure of 1305 psi in the SAGD case. The energy input was based on the practical heating rate of an electrical heater, 300 BT U/hr/f t. At the above conditions, none of the three methods made a profit. The above conditions were set to make a basis for comparison of the three cases, but they are not necessarily the optimal conditions for each case. We can use lower producer BHP in cyclic steam injection and electrical heating to have greater oil recovery. Also, we can use more than one electrical heater to get a greater heating rate and make a profit. Steam injection rate is an important parameter that greatly affects the oil recovery and economics of a SAGD process. To decide the steam injection rate in SAGD, first we used Butler s equation to calculate the rate of oil drained along the edge of the steam chamber [2]: 48

65 q o = 2L 2φ S o kgαh mν o (T s ) (2.1) where, q o is oil rate in m 3 /s or ( m 3 /d); L is the length of the producer; k is effective permeability to oil in m 2 ; g is acceleration due to gravity, 9.81 m/s 2 ; α is thermal diffusivity of reservoir in m 2 /s; S o is mobile oil saturation in the steam chamber, S o = S oi S or, S oi and S or are initial oil saturation and residual oil saturation in the steam chamber; t is time in s; ν o (T s ) is the kinematic viscosity of oil at steam temperature in m 2 /s; h is the effective reservoir height in m; m is the exponent in viscosity equations, that is defined from the following equation. 1 T s dt = mν s ν(t T R ) T R (2.2) This rate is considered to be the oil rate at the wellbore when a steam chamber is fully developed. Then we calculate an optimal steam injection rate based on an WOR of in SAGD processes [4]. Q surface injection Qbottom oil B w (W OR) (2.3) For our case, L = 1ft; φ = 0.33; S o = 0.24; k = = md; g = 9.81m/s 2 ; α = ft 2 /day [11]; h = 95ft; µ o (T s ) = 1cp; ρ o (T s ) = 59.09lb/ft 3 (Figure 2.21(a)); B w = (Figure 2.21(b)), and we used m = 3 and W OR = 2. Using Equation 2.1 and Equation 2.3, the optimal steam injection rate is bbl/day/f t. Then the steam injection rate over the whole length of the well (1600 ft) is bbl/day. This calculated injection rate gives some sense of an appropriate steam injection rate. In our study, we chose steam injection rates of , , , , and bbl/day/f t. The first injection rate corresponded to same energy input as 300 BT U/hr/f t of electrical heating. The third rate corresponded to the calculated optimal steam injection rate. From Table 2.5, we find that, the greater the steam injection rate, the greater the oil recovery rate and the greater the profit. A steam injection rate of

66 bbl/day/f t and an injection rate of bbl/day/f t recovered almost the same amount of oil and made almost the same amount of profit. An injection rate of bbl/day/f t, however, involves more steam condensate that must be removed from the reservoir. When injecting at the calculated optimal steam injection rate, the oil recovery and profit were also high, so the optimal steam injection rate does give us a good sense of the proper steam injection rate. 2.6 Discussion From the results of our simulation, it appears that SAGD was the most effective and economical method to recover viscous Ugnu oil. This is largely a result of the heat delivered and the pressure maintenance associated with steam injection. In our opinion, SAGD combines the advantage of electrical-heating-assisted recovery and VAPEX. In electrical-heating-assisted recovery, the heater heated the oil around the well, thereby reducing the viscosity of the oil; the heated oil drained downwards to the well bore. The direction of fluid flow and the direction of heat transfer is counter current, and this impedes the heat transfer somewhat. In the SAGD process, the heated oil flowed downwards along the perimeter of the steam chamber and the heat was carried upwards by the injected steam thereby maintaining contact with the unheated oil at the steam front. Therefore, the heat utilization was better in the SAGD process than in electrical-heating-assisted recovery. In the process of VAPEX, even though the diluted oil was also drained along the perimeter of a solvent chamber, it seemed that dilution was not as efficient as heating to reduce the viscosity of the heavy oil when the same amount of energy in the form of gas was injected. Even though electrical-heating-assisted recovery is not as effective as SAGD in terms of the energy consumed, it deserves more attention for field application because of its relative simplicity. If a heater is placed in a production wellbore, no injection wells need to be drilled. It also seems feasible to place heaters in the reservoir in a dual well configuration relatively easily. Certainly, super-insulated injection wells do not need to be installed. Likewise, almost no additional surface facilities are needed for the electrical-heating-assisted recovery method. Also, recovery is further enhanced 50

67 if the heater configuration and heating rate are optimized [10]. The sensitivity study concluded that well locations, well bottom-hole pressures, heterogeneity and relative permeability of reservoir rock all affected oil recovery. Therefore, these parameters must be considered not only in choosing a recovery method, but also in deciding well conditions after a recovery method has been determined. Preheating to facilitate earlier communication between the injector and producer for the SAGD process was investigated. Its effect, however, did not appear to be appreciable because the oil flowed under cold conditions. Economic analysis shows that cyclic steam injection had better economics than SAGD and electrical heating for the reservoir under study. Steam injection rate is an important parameter in SAGD processes. An optimal steam injection rate was estimated using Butler s equation [2]. This optimal equation gives some sense of an appropriate steam injection rate. The real optimal injection rate is decided through theoretical calculation combined with practical experiences. The conditions we used in our study based on the same producer BHP and the same amount of total energy input. These conditions are not necessarily the optimal conditions for production for all of the six cases. The initial pressure of the reservoir is pretty high. Reservoir pressure can be reduced by producing for some time by cyclic steam injection or electrical heating before conducting SAGD. 2.7 Conclusions Generally, electrothermal, conventional steam-based and thermal gravity drainage enhanced oil recovery techniques appear to be applicable to prime Ugnu reservoir conditions to the extent that reservoir architecture and fluid conditions are modeled faithfully in the representative 2D vertical section employed here. The model presents favorable recovery characteristics such as oil that is mobile at reservoir temperature, moderate solution gas-oil ratio, and an average permeability of roughly 760 md. All characteristics aid recovery of this viscous oil. The extent of reservoir layering and vertical communication are important factors affecting recovery. Specific summary items and conclusions include the following. 51

68 1. Reservoir and fluid models were built to resemble a representative section of the Ugnu reservoir. The properties of the reservoir rock, such as porosity and permeability distribution, and the properties of reservoir fluids, such as composition and viscosity, affect the results of simulation substantially. Further knowledge of the reservoir helps to build more realistic models. 2. With similar rates of energy input, SAGD had the greatest recovery among the six methods. Figure 2.22 shows the temperature profile during a SAGD process and substantial temperatures are distributed throughout the model. Electrical-heating-assisted recovery and cyclic steam injection also enhanced recovery substantially. 3. Operating conditions among the various recovery options were similar to allow straightforward comparison. Production conditions of each method are quantities to be optimized to obtain better recovery. For example, recovery associated with electrical heating clearly benefits from the smallest practical pressure in the production well. 4. Locations of the producer and injector, well conditions, heterogeneity and relative permeability have an effect on the recovery of heavy oil. Therefore, they should be carefully considered before determining the production method for a reservoir and deciding the production conditions after a method of recovery has been determined. 5. Economic analysis showed that cyclic steam injection had better economics than SAGD and electrical heating for the reservoir under study. Steam injection rate is an important parameter for the SAGD process. Different steam injection schemes in SAGD led to different oil recovery and economics. There is an optimal injection rate that is estimated by analytical calculation. 52

69 Bibliography [1] K.H. Afkhampour. A novel approach to solving downhole fluid flow problems by use of an electric heating system. IEEE, pages , [2] R.M. Butler and D.J. Stephens. The gravity drainage of steam heated heavy oil to paralell horizontal wells. JCPT, pages 90 96, April-June [3] C. Chakrabarty and J.P. Fossey. SAGD process in the East Senlac Field: from reservoir characterization to field application. PanCanadian Resources, pages , [4] P. Egermann, G. Renard, and E. Delamaide. SAGD performance optimization through numerical simulations: methodology and field case example. SPE presented at the SPE International Thermal Operations and Heavy Oil Symposium held in Porlamar, Margarita Island, Venezula, March [5] B. Guler, P. Wang, M. Delshad, G. A. Pope, and K. Sepehrnoori. Three- and four-phase flow compositional simulations of CO 2 /NGL EOR. SPE 71485, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 30-October [6] R.J. Hallam, E.J. Plekenbrock, A.S. Plekenbrock, A.M. Garon, T.W. Putnam, M.C. Weggeland, and K.J. Webb. Resource description and development potential of the Ugnu Reservoir, North Slope, Alaska. SPE Formation Evaluation, pages , September

70 [7] Q. Jiang and R.M. Bulter. Selection of well configuration in Vapex process. SPE presented at the International Conference on Horizontal Well Technology held in Calgary, Canada, November [8] T.N. Nasr and O.R. Ayodele. Thermal techniques for the recovery of heavy oil and bitumen. SPE presented at SPE Improved Oil Recovery Conference in Asia Pacific held in Kuala Lumpur, Malaysia., December [9] M. Prats. Thermal recovery, volume 7. Society of Petroleum Engineers, Dallas, Texax, second edition, [10] E.R. Rangel-German, J. Schembre, C. Sandberg, and A.R. Kovscek. Electricalheating-assisted recovery for heavy oil. Journal of Petroleum Science and Engineering, 45: , [11] B.C. Sharma, S. Khataniar, S.L. Patil, V.A. Kamath, and A.Y. Dandekar. A simulation study of novel thermal recovery methods in the ugnu tar sand reservoir, North Slope, Alaska. SPE presented at the SPE Western Regional/AAPG Pacific Section Joint Meeting held in Anchorage, Alaska, U.S.A., May [12] A.K. Singhal, S.K. Das, S.M. Leggitt, M. Kasraie, and Y. Ito. Screening of reservoirs for exploitation by application of steam assisted gravity drainage/vapex processes. SPE presented at the International Conference on Horizontal Well Technology held in Calgary, Canada, November [13] G.Q. Tang, T. Leung, L.M. Castanier, A. Sahni, F. Gadelle, M. Kumar, and A.R. Kovscek. An investigation of the effect of oil composition on heavy-oil solution gas drive. SPE Journal, pages 58 70, [14] G.Q. Tang, A. Sahni, F. Gadelle, M. Kumar, and A.R. Kovscek. Heavy-oil solution gas drive in consolidated and unconsolidated rock. SPE Journal, June 2006, to appear. 54

71 Table 2.1: Rock and reservoir properties of Ugnu Reservoir [5]. Porosity 0.33 Permeability 762 md Initial pressure 1300 psi Initial temperature 58 F Initial oil saturation 0.6 Initial water saturation 0.4 API 14.6 Efficient formation compressibility BT U/(ft 3 F ) Table 2.2: Properties of the reservoir fluid components. Component Molecular Critical Critical Critical Acentric Weight Pressure Temperature Volume Factor (g/mol) P c (psi) T c ( F ) (l/mol) H 2 O C C C C C

72 Table 2.3: K v values for the reservoir fluid components. H 2 O C 1 C 2 14 C C 36+ C 3 KV E E E E E+5 KV KV KV KV Table 2.4: Economics of electrical heating, cyclic steam injection and SAGD. Electrical Heating Cyclic SAGD1 ($0.01/kW h) Prescribed Injection Rate n/a (bbl/day/f t)) Cumulative Oil Produced (bbl) Oil Recovery (%) Cumulative Water Injected n/a (bbl) Cumulative WOR NPV ($) -1,971, ,292-1,773,407 Note: All the cases produced at the same BHP and had the same amount of total energy input. 56

73 Table 2.5: Economics of SAGD processes with different steam injection rate. SAGD1 SAGD2 SAGD3 SAGD4 SAGD5 Prescribed Injection Rate (bbl/day/f t)) Cumulative Oil Produced (bbl) Oil Recovery (%) Cumulative Water Injected (bbl) Cumulative WOR NPV ($) -1,773,407 2,691,082 17,348,821 19,040,642 19,797,625 corresponds to the calculated optimal steam injection rate using Butler s equation [2]. 57

74 (a) (b) Figure 2.1: Steam assisted gravity drainage: (a) illustration of the SAGD process [8], and (b) steam chamber developed in a SAGD process [12]. 58

75 Figure 2.2: Grid used in CMG STARS. Figure 2.3: Logarithmic permeability and porosity correlation of Ugnu sand. 59

76 Figure 2.4: Heterogenous reservoir porosity and permeability maps: (a) porosity map without correlation in any direction, 60(b) porosity map with great continuity in horizontal direction, (c) permeability map without correlation in any direction, and (d) permeability map with great continuity in horizontal direction.

77 Figure 2.5: Properties of reservoir components: P-T diagram (before and after lumping). 61

78 Figure 2.6: Viscosity of reservoir fluid as a function of temperature. 62

79 (a) (b) Figure 2.7: Reservoir fluid properties: (a) volume factor of oil, and (b) gas-oil ratio. 63

80 (a) (b) Figure 2.8: Relative permeability curves I [6]: (a) water-oil relative permeability, and (b) gas-liquid relative permeability. 64

81 (a) (b) Figure 2.9: Relative permeability curves II: (a) water-oil relative permeability, and (b) gas-liquid relative permeability. 65

82 Figure 2.10: Incremental oil recovery versus system energy input for all EOR cases. 66

83 Figure 2.11: Sensitivity of well location of producer to cumulative recovery (electrical heating, without heat loss through over- and under-burden). 67

84 Figure 2.12: Sensitivity of well location of producer to cumulative recovery (electrical heating, with heat loss through over- and under-burden). 68

85 Figure 2.13: Cumulative oil recovery for different locations of the injector (VAPEX, homogeneous reservoir). 69

86 Figure 2.14: Oil production rate for different locations of the injector (VAPEX, homogeneous reservoir). 70

87 Figure 2.15: Producer well bottom-hole pressure for different scenarios of SAGD. 71

88 Figure 2.16: Cumulative oil recovery for different production scenarios of SAGD. 72

89 Figure 2.17: Cumulative oil recovery for SAGD and primary recovery (with/without preheating). 73

90 Figure 2.18: Results of simulation for different degrees of heterogeneity of the reservoir. 74

91 Figure 2.19: Cumulative oil recovery for different relative permeability functions and heterogeneity (SAGD and electrical-heating-assisted recovery). 75

92 Figure 2.20: Cumulative oil recovery for different relative permeability functions. 76

93 (a) (b) Figure 2.21: Reservoir fluid properties: (a) oil density, and (b) formation volume factor of water. 77

94 Figure 2.22: Temperature profiles at different time in SAGD. 78