Various techniques of Enhanced Oil Recovery (EOR) exist and amongst them water and gas injection are the most widely used. It has been shown that combining water and gas injection in a WAG (water alternating gas) scheme can result in additional oil recovery. Interest in WAG injection has increasingly grown in recent times with many reservoirs around the world now under WAG injection.
Numerical simulation of WAG requires reliable three-phase relative permeability and hysteresis data which are normally obtained from models available in commercial simulators. This paper utilizes core-flood experimental data from literature to investigate validity of these models.
The findings from this study provide evidence that different three-phase relative permeability models were found to behave differently giving varying recovery factors in a WAG simulation scheme. While the effect of irreversible hysteresis was studied, it was observed here that imbibition (stage I) and drainage (stage II) processes gave results that deviated from conventional hysteresis. Simulations were run with and without hysteresis for different three phase relative permeability models with different effects observed for the recovery factor.
The results of this work show that a good understanding of the three phase relative permeability model in use is very important for a more robust reservoir simulation model. Also, the effect of irreversible hysteresis in WAG injection should be adequately modelled in order to obtain reliable results. Lastly, the results reveal the importance of optimum WAG ratio for maximizing oil recovery by preventing a gas tongue forming at the top of the reservoir and a water tongue forming at the bottom of the reservoir.
Uribe Hidalgo, Carlos Andres (Universidad Industrial de Santander) | Munoz Navarro, Samuel Fernando (Universidad Industrial de Santander) | Oliveros Gomez, Luis Roberto (Universidad Industrial de Santander) | Naranjo Suarez, Carlos Eduardo (Ecopetrol S.A)
In order to determine the best operating scheme, and taking into account the increase in demand for oil and the need of increasing the recovery of existing fields, enhanced recovery techniques are an alternative to the oil industry.
In Colombia, the stratified deposits of heavy oil have become the focus of oil exploration with EOR methods, including the one which is conceptually evaluated in this paper. However, the production of these fields has been restricted to strata having considerable thickness, forgetting about certain amounts of hydrocarbons from thin strata, representing significant potential for increasing production and reserves.
In search of the best alternative for extracting heavy oil reserves are contained in thin strata reservoir, this paper shows the technical and financial evaluation of applying cyclic steam injection using horizontal wells in these fields, using the injectivity and the benefit of the location Horizontal wells, and viscosity reductions product with steam heating. To carry out this process, It was evaluated the effect of each operational and reservoir parameters. Subsequently, due to the uncertainty of the distribution of steam in the reservoir and the importance of heterogeneities in this effect, the numerical simulation was performed with homogeneous and heterogeneous models, comparing productive behavior of each stage, to determine the best model to use in optimizing operational parameters.
Once the best scenario was determined it was performed a sensitivity and process optimization, seeking operating conditions that showed the best results with cyclic steam injection in horizontal wells, for further financial analysis that would provide a comprehensive feasibility study .
The complex physics of the displacement processes involved in three-phase flow in porous media in the tertiary oil recovery processes is yet to be understood. Three phase relative permeability are usually calculated from two phase experimental data due to the complexity of three phase measurements and its duration, hence introducing uncertainty in the adopted models. Pore-scale laboratory studies have shown strong irreversibility in the relative permeability among the successive drainage and imbibitions cycles and its path dependency, which is called hysteresis. Understanding this phenomenon and its effect play a major role in evaluation and success of any tertiary recovery processes such as WAG EOR. Several models have been proposed to predict this mechanism, three phase zone and predict the true residual oil saturation. To better evaluate and mitigate the risks involved, the impact of many parameters used in the current predictive tools and hysteresis models should be fully understood and investigated.
In this work relative permeability hysteresis, three phase region and various involved parameters affecting the hydrocarbon recovery have been investigated. A heterogeneous sector model supported with actual SCAL data were used for the purpose of this study. The results of the study and the adopted methodology have been later compared and verified with the actual real field performance data under the same processes.
Generally the results show significant difference in term of residual oil saturation whether or not a relative permeability hysteresis modeling is employed. The study also demonstrates the necessity of fine-tuning the hysteresis model parameters to the actual SCAL data to obtain more realistic parameters to be used in prediction phase. Reservoir heterogeneity play a major role in balancing the viscous and gravity forces as well as the three phase region size to achieve higher hydrocarbon recovery.
Zhang, Xiaoqin (Daqing Oilfield Co. Ltd.) | Pan, Feng (Daqing Oilfield Co. Ltd.) | Guan, Wenting (Daqing Oilfield Co. Ltd.) | Li, Dan (Daqing Oilfield Co. Ltd.) | Li, Xia (Daqing Oilfield Co. Ltd.) | Guo, Songlin (Daqing Oilfield Co. Ltd.)
The molecular weight of polymer is important to the efficiency of polymer flooding. Polymer solutions with higher molecular weight have better absorption, better capitation, higher resistance and residual resistance coefficients. All these imply higher recovery factor. But for reserviors of middle and low permeability, higher injected molecular weight means more unswept pore volume, lower controlling degree and recovery factor. Therefore, both higher injected molecular weight and controlling degree must be fully considered, so as to obtain a higher recovery factor in a given block.
On the basis of lab experiments and numerical simulations, two matching charts are formed. One is about the relationship between molecular weight and layers and the other is about controlling degree on recovery rate. They are used to optimize the molecular weight for polymer flooding. This new method is applied in the project for polymer flooding in secondary layers of Daqing oilfield and an enhanced recovery factor of more than 8% is obtained.
In polymer flooding, the solution viscosity is enhanced and water phase permeability is reduced. Sweeping volume is enlarged to increase recovery factor. Polymer molecular weight is the main factor in polymer flooding. Higher molecular weight means lower water phase permeability and higher recovery rate. However, in the industrialization of polymer flooding in Daqing Oilfield, it is indicated molecular weight should be optimized in accordance with permeability. Ultrahigh molecular weight needs high injection pressure and causes blocks in the layers, which leads to poor development. To the question, a new method is put forward to optimize the molecular weight.
Optimum solvent composition is a vital decision in ensuring the economic viability of the VAPEX process. The ideal optimum is dictated by reservoir characteristics such as temperature, pressure and bitumen properties. Condensation can be prevented through the addition of a non-condensable gas and if the partial pressure of the solvent mixture remains lower than the vapor pressure at reservoir temperature. In this work, different solvent mixtures were examined to investigate the performance of VAPEX process in heavy oil recovery in an Iranian reservoir. The optimum solvent composition was found through the comprehensive simulation work. Effects of injection rate and diffusion coefficient were tested. Optimum solvent composition for all cases was found as mixture of C1/C3 with 55/45 molar ratio. Results indicate that the recovery factor, the oil production rate and the cumulative oil production will be higher for solvent mixtures with diffusivity coefficient compare to solvent mixtures without diffusivity coefficient as well for optimum solvent. Effect of diffusivity on process is acknowledged well by peclet dimensionless number and this shows that at low injection rate, effect of diffusivity is more than displacement.
Keywords: VAPEX, Heavy oil, Solvent system, Diffusivity, Oil recovery
Miscible gas injection in oil fields in general results in a better microscopic displacement efficiency compared to water injection; however, higher mobility ratio and lower macroscopic sweep of gas is a major disadvantage compared to water injection. Considering this situation, water alternating gas (WAG) was proposed and implemented as a method to improve macroscopic sweep efficiency of gas using cyclic water injection to reduce its high mobility ratio.
In this simulation study, a systematic parameter study was carried out to investigate the effect of different parameters in a miscible WAG process using a horizontal sector model and both black-oil and compositional simulators. The base model was first built using a black-oil simulator but a compositional model was later implemented in order to investigate the differences in results for the two models.
This study shows that WAG injection is advantageous compared to both water and gas injection in term of oil recovery factor. Changes of cycle time did not affect the recovery factor significantly while in this particular model recovery is sensitive to the changes of gas half cycle time. It is not possible to find a simple dependency between half cycle time and oil recovery factor but it is obvious that recovery factor is a function of both gas slug size and half cycle time and that an optimum value exists for each case. The effect on recovery by changes in water half cycle time is on the other hand not significant.
Injection of water through all layers improved the advance of stable front and improved final oil recovery for all cases. However, the gas injection interval needs to be optimized for each case based on the ratio of vertical and horizontal permeabilities of the reservoir, and thus the injection perforation strategy for gas must take this into consideration.
In the model used, which has no aquifer or gas cap, increased dynamic forces by simultaneous increase of field production and injection rates resulted in increased oil recovery.
There is good consistency between black-oil and compositional base models with only ±4% OIIP differences in term of field oil recovery.