Applicability of SAGD in Eastern Venezuela reservoirs

Transcription

1 PAPER Applicability of SAGD in Eastern Venezuela reservoirs JOSÉ ANTONIO PIÑA R. SCHLUMBERGER JOSÉ LUIS BASHBUSH SCHLUMBERGER EDGAR ALEXANDER FERNANDEZ SCHLUMBERGER This paper has been selected for presentation and publication in the Proceedings for the World Heavy Oil Congress All papers selected will become the property of WHOC. The right to publish is retained by the WHOC s Publications Committee. The authors agree to assign the right to publish the above-titled paper to WHOC, who have conveyed non-exclusive right to the Petroleum Society to publish, if it is selected. Abstract This paper describes the evaluation and optimization process of a steam-assisted gravity drainage (SAGD) project using a sector model from a field with representative oil and reservoir characteristics from an Eastern Venezuela formation. Due to the complexity and amount of variables involved in the process, SAGD presents multiple challenges from the design phase to its implementation. The goal of this investigation was to understand the impact of some key variables in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs, which have previously produced with primary recovery mechanisms. A preliminary work consisted of the reduction of the original 14 components identified in the existing PVT analysis into 2 and 3 pseudo-components, comparing the stability and results using both fluid characterizations to attain reasonable running times in the simulation process. Once the fluid behavior was successfully recreated and the model was set up, a sensitivity analysis was conducted using thermal simulation. The parameters analyzed were vertical well spacing, injection steam rate, well flowing pressure, and horizontal length. The effect on the oil recovery from the angle of dip in the reservoir and the orientation of the well pair in the reservoir is also analyzed. The conclusion presents a configuration for the SAGD well pair array that resulted in trebling the oil recovery attained by the initial well array. This study touches upon the effect of the component grouping for fluid characterization. 1

2 Introduction Venezuela has one of the largest heavy oil accumulations in the world. Due to the nature of the oil present in these fields and their viscosities at reservoir conditions, one of the challenges is to define suitable technologies to economically achieve a minimum recovery factor of 20%. Steam injection is one of the technologies being considered to increase the production associated to these fields located in the eastern of part of Venezuela. The advantages of the steam are well known and rely on effectively using its capacity to carry heat to the rock and fluids reducing the oil viscosity 1. Steam injection for thermal processes has been widely used for decades in many projects around the world 2. One of the steam injection technologies proposed to increase the production is the SAGD (Steam Assisted Gravity Drainage). SAGD consists on the injection of steam through a horizontal well in the upper part of the formation, heating the oil present in the reservoir decreasing its viscosity and increasing the mobility. This oil is produced by a horizontal well placed towards the base of the formation. The principal idea is to create a steam chamber that assist in providing heat to the fluids, decreasing their viscosities and stimulating the gravity segregation. Initially this technology was developed for the heavy oil and bitumen reservoirs of Canada 4 to recover the oil with high in-situ viscosities (larger than 50,000 cp). In order to apply SAGD for Venezuela s heavy oil reservoirs it is necessary to understand the process as it applies to the different conditions between the reservoir on both countries (Pressure, temperature, viscosity, etc), evaluating the level of productivity that could be expected from this technology and propose specific SAGD configurations that ensure the best SAGD performance. The aim of this investigation is to produce a simulation model, representative of the specific conditions for this type of accumulations so that the SAGD technology can be analyzed to obtain relevant information about the expected production response and behavior before starting the design of the pilot project. Results and Discussion PVT Analysis Thermal simulations are very sensitive to the compositional characterization of the fluids used in the models. The composition and properties of each component define the characteristics of the mixture 3. Heavy oils from Venezuela have considerable amounts of dissolved gas, unlike comparable accumulations elsewhere. The initial dissolved gas for the Venezuelan heavy oils typically range from 30 to 200 scf/stb. Therefore, in these fluids their light component fraction has to be considered, bringing added complexity to the representation, mixing behavior with the heavier fractions and simulation stability. In particular, the 13 o API heavy oil used in this study had an Rsi of 150 scf/stb, in spite of its low API gravity. A PVT adjustment process was performed to generate the parameters of the equation of state to replicate the fluid properties in the simulator using PVTi (of the ECLIPSE software suite of programs 5 ), and a modified Peng-Robinson three-parameter equation of state (EoS). Component grouping processes allowed carrying out reductions of components in the original mixture from 14 to three and two pseudo-components, respectively, with the principal idea of reducing the simulation times while still honoring, within a reasonable band, the oil properties measured in the PVT laboratory tests. The main PVT properties used in the adjustment process were Oil relative volumes, Bubble point pressure ( 1,315 psia ), Oil densities, Solution gas-oil ratios and Liquid viscosities versus pressure. Table 1 presents the mole fractions and molecular weights for the hydrocarbon groupings from the two- and three- pseudocomponent characterization results, while Table 2 summarizes the average differences (in percent), between the measured and calculated values for five of the dominant fluid properties versus pressure. It is apparent that both characterizations are comparable, with the 3-component set holding a small edge. Figure 1 presents the match for the formation volume factor for the oil (Bo) and Figure 2 for the solution gas-oil ratio (Rs). The oil relative volumes define the fluid expansion and the oil compressibility behavior versus pressure. This parameter has a high influence on the final recovery factor calculated under cold production conditions. Accordingly, the aim was to minimize the average error obtained for this parameter. In the regression process, it presented the narrower difference band from all the properties selected. Comparison between two and three pseudo-component model results In view of the good PVT matches obtained in both instances, a 66,000 grid base case model was prepared and run for a 10 year period to compare the SAGD results and run times of the 2 pseudo-component case versus the one obtained with 3 pseudocomponents. Again, the results were comparable; however the 2 pseudo-component case required a fraction of CPU times. For the purposes of this investigation, it was decided to carry out the current analysis with the 2-pseudo-component characterization, leaving the other one for a subsequent publication. Operational parameters adjustment The study of the SAGD was undertaken in a portion of a heavy-oil reservoir in Eastern Venezuela that had been previously characterized and mapped with its corresponding lithological and structural rock property variations. The reservoir thickness ranged from 80 to 100, the horizontal permeability from 100 to 800 md, the porosity from 28 to 32 % and having an average initial water saturation of 21 %. The vertical to horizontal permeability ratio in the model was set at 0.2 [Kv/Kh] for this fairly clean sand. The temperature at the top of the formation is 117 ºF, containing an oil of 540 cp viscosity at this reservoir 2

3 temperature. A regular grid of 66,000 cells [44 x 75x 20] was superimposed to the area of interest as shown in Figure 3, with the producing well placed 2.5 feet above the base of the formation in all instances. Table 3 summarizes the simulation grid characteristics. The area considered for the placement of the well pair has an average angle of dip of 3.2 o. For this reason, and to take advantage of the favorable gravitational segregation effects (even at this low inclination of the reservoir), the heels of the well pair were placed up dip. The Eclipse Thermal simulator was used for this study activating the multi-segmented well option 5 to adequately represent the pressure drops and heat transfer effects along and to/from the downhole metal strings to the formation. Heat losses to the over- and under-burden were dully considered. The prediction runs were extended to 10 years in all cases. Five main variables were analyzed: 1 Four vertical spacings between producer and injector: [ 20, 40, 60 and 80 ] 2 Five steam injection rates: [ 100, 200, 300, 400 and 500 tons/day ] 3 Four flowing bottom-hole pressures: [ 300, 500, 900 and 1000 psi ] 4 Four horizontal well lengths: [ 1,700, 2,000, 2,200 and 2,500 ] 5 Two additional structural effects on well positioning: Flat horizontal reservoir and down dip positioning of the heels of the well pair Based on the results from the above 19 cases, a suitable configuration optimizing the cumulative recovery for the reservoir was selected. Vertical spacing between Producer and Injector The selected parameters for the first case are presented in Table 4. These parameters were also assigned to the initial base case trials used to investigate the sensitivity to 2 and 3 pseudo-component characterization effects. As indicated, the 2 pseudo-component characterization and its corresponding EoS match were selected for the rest of the simulation runs in this investigation. The initial case considered the injection of 100 tons of steam per day, equivalent to 629 barrels of water, converted to steam, per day; placing the injector 20 feet above a 1,500 long producer which was initially constrained at a bottom hole flowing pressure of 700 psi. Three additional cases were later generated, successively increasing the location of the injector to 40, 60 and 80 above and parallel to the producer. Figure 4 compares the Oil Production for this series of cases. In general, a clear trend is established showing a higher recovery for the larger well spacing. Table 5 summarizes the cumulative oil, water and steam-oil ratios [SOR] for each case. This later value is one of the handy indicators of the effectiveness of steam based processes, representing the amount of steam required to generate and inject, to produce a barrel of oil at the surface. For this set of four cases, the cumulative SOR decreases as the cumulative oil production increases. It is noteworthy to observe the oil production behavior during the first five years of prediction shown in Figures 4 and 5. During the first 100 days, the cumulative recovery is higher for the shorter spacing [20 feet] owing to the fact that a higher pressure gradient is imposed between injector and producer and that the heating effect of the incipient steam chamber in the close spacing quickly reduces the viscosity of the oil between both wells, favorably affecting the initial oil production rate. Between 100 and 450 days, a similar explanation is applicable to the effect noted for the 40 spacing, which shows at these times, a larger cumulative recovery than the 60 Case. After 1 ½ years and up to 5 years of production, the cumulative oil recovery for the 60 spacing is the largest, resulting in a positive effect on the net present worth of the case. After 5 years, the production from the Case with 80 spacing, finally overtakes that of the 60 Case. The slower uptake in production for the 80 Case is affected by two different phenomena: First, the beneficial effect of steam takes longer to stimulate the initially cold oil production, because the downward distance that the steam chamber has to grow is 80. Then, since the injector is located just 17.5 below the top of the formation, the heat losses to the overburden increase considerably with respect to the other cases. Therefore, less energy is available to heat the oil in the formation, partially offsetting the favorable gravitational effects of the larger spacing during the first five years of operation. The water production behavior is consistent with the geometry of the well arrays. In general, the closer the well spacing the more the water production. However, due to the superposition of multiple interactions between the injected steam, the cooling effect due to the contact with the rock and fluids in the reservoir and the overburden and the production of heat by the water and oil streams, the water production rates change with time. For the above reasons and notwithstanding that in the end the cumulative recovery from the 80 Case is the largest due to the beneficial effects of gravity, the 60 Case was selected as the one presenting the more favorable overall behavior from this series of cases. The 60 spacing was used for the next step in the optimization process, because of the net present value considerations mentioned above. Steam injection rate As in any steam injection based process, the optimum amount of water converted to steam is directly linked to the formation thickness and the economic balance of the additional oil recovered from an incremental amount of steam injected. Figure 6 presents the cumulative oil recovery profile proportionally increasing with higher steam injection rates, consistent with the sequential addition of energy provided to the reservoir by the process. 3

4 Table 6 summarizes the results from the four steam injection rates analyzed, from 200 to 500 tons/d. It also shows that the SOR s increase as the injection rates increase. Based on economic considerations and prices of fuel, steam generator, fresh water for steam generation and operating expenses, a cut-off of 4 for the SOR is commonly used in steam based projects. On this account, the third case, corresponding to the injection rate of 400 tons/d was selected as the basis for the next series of sensitivities. Sensitivity to production bottom hole flowing pressures The importance of optimizing the bottomhole flowing pressure of the producers in a SAGD project is based on the difficulty of empirically balancing the effects of the multiple parameters that impinge on the process. In isothermal normal conditions, imposing a larger pressure drop between the reservoir and the producer should result in higher oil production rates. However, for a SAGD well pair, a large pressure drop would tend to excessively pull down the steam from the injector, counteracting its natural tendency to rise within the reservoir and contribute to the formation of the steam chamber and heat the fluids and the rock. Conversely, a small pressure drop will not necessarily bring to the producer all the oil that may be efficiently produced from the array. Figure 7 and Table 7 illustrate the above reasoning indicating that for the reservoir conditions of this example, an optimum is obtained at a bottom hole flowing pressure of 900 psi. That condition shows not only the highest cumulative oil recovery (2.65 MM stbo) but also the lowest SOR (3.45). Lowering the bottom hole flowing pressure in the producer, result in quickly deteriorating SOR s. This again points that for a SAGD process in a high permeability reservoir, a relatively low differential pressure is preferred to allow a better utilization in the reservoir of the energy from the steam and allow the gravity drainage process to shed its full beneficial effects. Sensitivity to the horizontal length of the wells Horizontal length of the wells is another of the important parameters that affect the economics of the process because not only directly impacts the reservoir drainage, maximum oil production rates and cumulative recoveries, but also the costs of drilling the pair of wells for each set. Table 8 presents the results from the four additional well-pair lengths investigated [notice that all previous sensitivities were performed for a 1,500 long pair of wells]. These lengths are somewhat shorter than those from other horizontal wells completed in heavy oil reservoirs in the area. The best SOR [ 2.99 ] and Oil Recovery [ 3.06 MM stbo ] were obtained for the 2,000 long well-pair. Under these circumstances, a 2,500 long well-pair, cost more, produces 1/3 less oil and its SOR increases by almost 60%, reinforcing the importance on the economics of the project of the determination of the pair length. Figure 8 depicts the improvement sequence achieved during the optimization process obtained by the best case, representing a 2,000 long pair of SAGD wells, separated by 60, injecting 400 ton/d of water converted to steam at a differential pressure between produced and injector of about 200 psi. Table 9 summarizes the cumulative oil production and the incremental recovery for each phase of the optimization process. Gravity and Reservoir Structure effects The very uniform temperature and saturation distributions observed at the end of ten years of operation of the 2,000 long array optimized in the previous steps ( see Figures 9, 10, 11 and 12), are positively influenced by having oriented the toe of the wells down dip from their respective heels. To substantiate this result and as a complement to the optimization methodology, two variations were formulated maintaining all fluid, reservoir parameters and rock properties equal, with the exception of the structural shape of the reservoir. In the first variation, the reservoir was flattened to a completely horizontal position. In the second variation, the average angle of dip (3.2 o ) was inverted in the reservoir, incorporating an up dip climb of the wells from the heel to the toe. Table 10 compares the results from these three cases illustrating the significant effects of gravity, even at the very low contrasting angles analyzed. The original case, placing the heel up dip recovered 15% more oil than the variation where the heel was placed down dip and 8.5% more oil than in the variation with the horizontal orientation in the wells and the reservoir. This case and its two variations underscore the beneficial effects of gravitational segregation when it is advantageously allowed to operate as part of the reservoir production mechanisms 6. On this vein, Figures 13 and 14 illustrate the gravity driven growth of the steam chamber in two perpendicular vertical planes, one year after commencing the steam injection. At this time, the steam has reached the top of the reservoir in the 60 well spacing case. Conversely, Figures 15 and 16 respectively depict the saturation of oil and the temperature profiles at the end of the 10 year injection period. Conclusions 1. The adjustment of the parameters of the EoS reproduced the fluid characterization from laboratory tests with a maximum error below 8%. This depiction was achieved in spite of the initial solution gas oil ratio of 150 scf/stb. 2. The 60 feet vertical well spacing generated a good balance between the steam breakthrough on the producer well and the heat losses and steam production effects. This array recovered more oil than the others during the first five years of the project. 3. A steam injection rate of 400 tons/d provided the optimum cumulative SOR for the cases analyzed. 4. The adjustment of the well flowing pressures on the producer represented a significant effect on the SAGD performance. A relatively low differential pressure of about 200 psi (flowing bottom hole pressure of 900 psi) improved the oil recovered and decreased the SOR. 4

5 5. The case with the best oil production performance was obtained for horizontal lengths of 2,000. At this value the oil production reached a maximum and the SOR a minimum. 6. The angle of dip in a formation plays an important roll in a gravity segregation process like SAGD. 7. Proper well placement accounting for the dip angle of the portion of the reservoir where it is located has an impact on recovery. 8 SAGD technology shows a considerable potential to increase the oil recovery factors from Eastern Venezuela heavy oil reservoirs. Recommendations 1. Economic analyses should accompany the final optimization sequence, to incorporate financial and technical considerations for the selection design of the SAGD pilot. 2. Geomechanical models for the SAGD process should help to account for the effects in the reservoir of changing rock properties with temperature and pressure stresses. 3. Incorporation of heat losses in the surface piping, facilities and the well bores of the producer and injector, will complement the design of the SAGD pilot. REFERENCES 1. ALI, S.M. FAROUQ, Practical Heavy Oil Recovery ; HOR Heavy Oil Recovery Technologies Ltd., October ALVARADO, D., BANZERS, C., Reedited and revised by RINCÓN, A., Recuperación Térmica, 343 pp., BRULÉ, M., WITHSON, D., Phase Behavior ; Monograph SPE, Vol. 20, pp 47-65, BUTLER, R, Thermal Recovery for Oil and Bitumen ; GravDain s Blackbook, First Edition, 496 pp., SCHLUMBERGER, ECLIPSE Reference Manual ; 1829 pp., BASHBUSH, J.L., Enhanced Oil Recovery from Heavy Oil Reservoirs, Course Notes: Universidad Nacional Autónoma de México,

6 Table 1. Mole fractions and Molecular weights of the groupings for each PVT characterization 2 pseudocomponents 3 pseudocomponents Component Zi Mi Zi Mi C C2-C C Table 2. Average differences from the PVT adjustment process for each pseudo-component model Difference (%) Parameter 2 pseudo- components 3 pseudo-components Avg. Bo Avg. Rs Avg. ρ Avg. Sat. Press Avg. µo Table 3. Grid simulation resolution characteristics Grid Dimensions X interval (feet) Y interval (feet) Z interval (feet) Nº. cells X Nº. cells Y Nº. cells Z Length on X direction Length on Y direction Total Area 880 feet 3000 feet Acres Table 4. Initial simulation system conditions Parameter Value Well spacing, feet 20 Steam injection rate, ton/d 100 Well flowing pressure, psi 700 Horizontal length, feet 1,500 Initial reservoir pressure, psi 1,100 Average permeability, md 440 Steam injection temperature, ºF 500 Steam quality, % 75 CASE Table 5. Sensitivity to well separation [feet] oil at 10 years, MSTB water at 10 years, Steam-Oil ratio ,

7 Table 6. Sensitivity to steam injection rate [Metric Tons per Day] CASE oil at 10 years, water at 10 years, MSTB Steam-Oil ratio Table 7. Sensitivity to well flowing pressure [psi] Well flow pressure oil production at 10 years, water production at 10 years, Steam-Oil ratio , Horizontal length of the well pair Table 8 Sensitivity to horizontal length [feet] oil production at 10 years, water production at 10 years, Steam-Oil ratio 1, , , , Table 9 Oil Production for each phase of the optimization process Simulation cases Cum.Oil Production: Best Case Incremental Cum. Oil Vertical Distance Steam injection rate Well flowing pressures Horizontal length Table 10 oil production comparison between East Venezuela reservoir model, horizontal reservoir and up dip placement of well pair Simulation cases Total oil production for best case, Optimized Case 3.06 Horizontal Reservoir 2.82 Up dip Placement

8 Observed EOS calculated Observed EOS calculated Solution gas ratio, rb/stb Figure 1 Oil relative volume comparison (2 pseudo-component match) Figure 2 Solution gas-oil ratio comparison (2 pseudo-component match) 537 oil production behavior for different vertical distances Oil production, STB Vertical Distance = 20 feet Vertical Distance = 40 feet Vertical Distance = 60 feet Vertical Distance = 80 feet Time, days Figure 3 Reservoir sector with the simulation grid superimposed used for the SAGD study (property showed: permeability). Figure 4 Sensitivity to vertical separation of wells in the SAGD pair 8

9 1200 Oil production rate behavior for different vertical distances 4,00 Oil production behavior at differents steam injection rates Steam injection rate = 200 tons/d Steam injection rate = 300 tons/d ,50 Steam injection rate = 500 tons/d Steam injection rate = 400 tons/d Oil production rate, STB/D Vertical Distance = 20 feet Vertical Distance = 40 feet Vertical Distance = 60 feet Vertical Distance = 80 feet Oil production, 3,00 2,50 2,00 1,50 1,00 0, Time, days Figure 5 Oil production rate sensitivity for different vertical distance between the wells 0, Time, Days Figure 6 Sensitivity to steam injection rates oil production for different well flowing pressures 3.50 SAGD optimization process oil production, MMBN Well flowing pressure= 300 psi Well flowing pressure = 500 psi Well flowing pressure = 900 psi Well flowing pressure = 1000 psi B Oil production cumulative, MMST Step 1: SAGD Base Case Step 2: Vertical Distance between the wells Step 3: Steam injection rate Step 4: Well flowing pressure Step 5: Horizontal length of the wells Time, days Figure 7 oil production for different well flowing pressures Sensitivity steps Figure 8 Evolution of the SAGD optimization process for each of the sensitivity cases Figure 9 Oil saturation profile at the end of the SAGD process Figure 10 Gas saturation profile at the end of the SAGD process 9

10 500 ºF 200 ºF Figure 11 Temperature surfaces at 10 years of the process: Red - 500ºF; Yellow - 120º, ( 3 ºF above the initial reservoir temperature) Horizontal length: 2,000 Case Figure 12 View from above of the steam chamber showing temperature distribution at end of the process 1 Figure 13 Steam fraction showing the vertical chamber growth in a plane perpendicular to the wells: at 1 year into the process Figure 14 Steam fraction showing the vertical chamber growth in the plane of the wells: at 1 year into the process Figure 15 Oil saturation profile at the end of the process in the vertical plane of the wells 10 Figure 16 Temperature profile depicting steam chamber growth at 10 years of the process

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