This paper examines whether retention of partially hydrolyzed polyacrylamide (HPAM) is different under anaerobic versus aerobic conditions. Both static (mixing with loose sand) and dynamic methods (core floods) were used to determine HPAM retention. There are both advantages and disadvantages associated with determining polymer retention using static tests versus dynamic tests and using aerobic versus anaerobic conditions. From static retention measurements, polymer adsorption values on pure silica sand or Berea sandstone were small, and they showed little difference between experiments conducted aerobically or anaerobically. For both aerobic and anaerobic conditions, HPAM retention increased significantly with increased pyrite or siderite content. Static retention under anaerobic conditions ranged from 45-75 µg/g with 1% of either pyrite or siderite to 137-174 µg/g for 10% pyrite or siderite to 1161-1249 µg/g for 100% pyrite or siderite.
If iron minerals are present, the most representative polymer retention results are obtained (for both static and dynamic tests) if conditions are anaerobic. Retention values (from static measurements) under aerobic conditions were commonly twice those determined under anaerobic conditions. If iron minerals are present and retention tests are performed under aerobic conditions, TOC or some similar method should be used for polymer detection. Viscosity detection of polymer may provide retention values that are too high (because oxidative degradation can be misinterpreted as polymer retention). For a broad range of siderite content, retention from static tests did not depend on whether dissolved oxygen was present. However, for a broad range of pyrite content, HPAM retention was significantly lower in the absence of dissolved oxygen than under aerobic conditions. Theses results may be tied to iron solubility. When polymer solutions were mixed with 100% pyrite over the course of 12 hours, 360–480-ppm iron dissolved into polymer solutions under both aerobic and anaerobic conditions, whereas with 100% siderite, only 0–0.6-ppm iron dissolved. If dynamic methods (i.e., corefloods) are used to determine polymer retention under aerobic conditions, flow rates should be representative of the field application. Rates that are too high lead to underestimation of polymer retention. With 10% pyrite, dynamic retention was 211 µg/g at 6 ft/d versus 43.2 µg/g at 30 ft/d. In contrast, retention values were fairly consistent (40.6 – 47.8 µg/g) between 6 ft/d and 33 ft/d under anaerobic conditions.
Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.
Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Fan, Jian (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Xiaoxia (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC) | Li, Jianguo (State Key Laboratory of Enhanced Oil Recovery, Research Institute of Petroleum Exploration and Development, CNPC)
Chemical flooding technology is one of the effective enhanced oil recovery (EOR) methods for high water cut sandstone reservoirs with either medium and/or high permeability. Because of the small pore throat radius in the pore medium of low permeability reservoir, high molecular weight polymers cannot be injected in the low permeability reservoir. Therefore, many traditional chemical floodings (such as polymer flooding, alkali-surfactant-polymer (ASP) flooding and surfactant-polymer (SP) flooding) cannot be effectively applied in this case. Small-molecule viscoelastic surfactant (VES) has special rheological properties in porous medium. It showed both viscosified function and reduction of oil/water interfacial tension (IFT) performances under certain conditions, thereby providing the possibility of IOR/EOR potential application in low permeability reservoirs.
Most of reservoirs in Jilin Oilfield belong to low permeability reservoirs with permeability of around 50 mD in average. The recovery percent of reserves in Fuyu was only 23% by water flooding with water cut as high as 93%. A candidate EOR technique with chemical flooding has been proposed. Studies on VES flooding EOR methods targeting this reservoir condition were conducted. The rheological property, IFT property, viscosifying ability of VES and core flooding experiments of VES system were studied.
From VES screening experiment, a type of zwitterionic betaine surfactant with long carbon chain was selected. It showed viscosifying behavior, shear thinning property and low IFT performances at reservoir conditions. VES of EAB solutions showed a good viscosifying action at low surfactant concentration. Moreover, based on its shear thinning property under the wide shear rate conditions, VES exhibited a good injectivity performance. IFT between crude oil and formation water with EAB was 10-3-10-2 mN/m order of magnitudes. The results could be obtained at the concentration ranges of surfactants from 0.1wt% to 0.4wt%. Ultralow IFT (10-3 mN/m order of magnitudes) could be obtained in the presence of co-surfactants or alkalis (such as sodium carbonate). Core flooding experiments of VES flooding showed that the incremental oil recovery factors could reach up to 13%-17% over conventional water flooding at Fuyu reservoir conditions. Test results indicated that VES flooding might become a promise alternative EOR method for low permeability reservoir after water flooding.
In contrast to the complexity of ASP/SP combination system, VES flooding could avoid chromatographic effects in the reservoir based on their simple formula (single surfactant compound). This new chemical flooding technique might have a great potential for EOR application in the low permeability reservoirs.
It is now common knowledge among EOR practitioners that the combination of ferrous iron (Fe2+) and oxygen causes severe oxidative degradation to EOR polymers, resulting in a lowering of molecular weight and hence a loss of viscosity. During the design of polymer flooding projects, an important question is thus the acceptable levels of Fe2+ and dissolved oxygen that can be tolerated in injection water specifications. Furthermore, we would like to be able to predict the extent of degradation in the case of excess Fe2+ or oxygen ingress.
However, despite over fifty years of research and a general understanding of the degradation mechanism involved, quantitative prediction of the extent of degradation has proven elusive and dependent on the measurement protocol. This is likely due to the fastidious experimental protocols required to work under anaerobic or limited-oxygen conditions.
We examine existing protocols and demonstrate that experiments in which either Fe2+ or oxygen are the limiting reagent yield equivalent results when the stoechiometry of the Fe2+ oxidation reaction with oxygen is taken into account. Based upon these findings, a novel, easy approach is proposed to quantify polymer oxidative degradation as a function of either dissolved oxygen or Fe2+ content.
The limits of 225 ppb Fe2+ and 32 ppb dissolved oxygen are fixed for Flopaam 3630S in 6 g/l brine in the concentration range 500-1500ppm in order to ensure degradation of low-shear plateau viscosity does not exceed 10%. Higher levels will lead to severe polymer degradation. The influence of polymer concentration, temperature and salinity is also investigated. At last, evolution of redox potential and pH during Fe2+ oxidation are discussed.
There is a direct practical application of these finding for the design of surface facilities for polymer dissolution and transport and for the prediction of degradation in case of oxygen ingress. Moreover, a simple and easily performed protocol is proposed for the evaluation of polymer oxidative degradation.
With the synergy of horizontal drilling and hydraulic fracturing techniques, commercial production of Unconventional Liquid Reservoirs (ULR) has been successfully demonstrated. Due to the low recovery factor of these reservoirs, it is inevitable that Enhanced Oil Recovery (EOR) will ensue. Experimental results have shown promising oil recovery potential using CO2. This study investigates oil production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies, and evaluates the potential of using CO2 huff-n-puff process to enhance the oil recovery in ULR with nano-Darcy range matrix permeability in complex natural fracture networks.
This study fully explores mechanisms contributing to the oil recovery with numerical modeling of experimental work, and provides a systematic investigation of the effects of various parameters on oil recovery. The core scale modeling utilizes two methods of determining properties that are used to construct 3D heterogeneous models. The findings are then upscaled to the field scale where both simple and complex fractures in a single stage are modeled. The effects of reservoir properties and operational parameters on oil recovery are then investigated. In addition, this study is the first to present simulation results of CO2 huff-n-puff using complex fracture networks which are generated from microseismic-constraint stochastic models.
Diffusion is proven to be the dominant oil recovery mechanism at the laboratory scale. However, the field-scale reservoir simulation indicates diffusion is negligible compared to the well-known mechanisms accompanying multi-contact miscibility. This includes swelling, viscosity reduction, and gas expansion in the matrix. Overall, the CO2 huff-n-puff process was found to be beneficial in both models in terms of enhancing the ultimate oil recovery in ULR.
Solvent Aided-Steam Flooding (SA-SF) focuses on maximizing the oil production by reducing the economic and environmental challenges created by steam generation. However, the solvent selection is vital due to the interaction of solvents with asphaltenes. Moreover, the polar nature of asphaltenes also enables asphaltene-steam interaction which may result in emulsion formation. This study investigates solvent-asphaltene-steam interaction during SA-SF with low and high molecular weight asphaltene insoluble solvents.
Two different solvents were tested; n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5) with four flooding experiments; two miscible flooding (E1 and E2) and two SA-SF (E4 and E5) experiments. Results were compared with steam flooding (E3) experiment. The performance evaluation of different enhanced oil recovery methods was accomplished by comparing the oil recovery rates. The asphaltene content of produced oil samples was determined by standard methods. The asphaltene-steam interaction was analyzed with microscopic images, and the water content of produced oil samples was measured by Thermogravimetric Analysis (TGA).
Even though similar cumulative oil productions were obtained by the end of E1 (n-hexane-flooding) and E2 (CS-flooding), the produced oil quality varied due to asphaltene and clay contents. While higher clay content was measured for E1, E2 had a lower quality, due to higher asphaltene contents. This finding is due to the heavy dearomatized hydrocarbons composition of the CS which ranges from C11 up to C16 and enables more asphaltene production. Even though, E5 yielded the highest liquid production among all experiments; the produced liquid was composed of emulsified oil. The solvent aided-steam flooding (SA-SF) experimental results, which have been conducted with n-hexane/steam (E4) and CS/steam (E5) injections, suggest that as the asphaltene content increases in produced oil samples, more hard-to-break emulsions are formed. The unusual stability of these emulsions can be attributed to the nature of the asphaltene present in the produced oil.
From the results presented, it is recommended the use of lower carbon number solvents to leave the larger amounts of asphaltenes in the reservoirs. The solvents differed in their interactions with the asphaltenes present in the oil and with the steam that has a direct impact not only on the quantity of oil produced but the quality as well. Hence, the wise selection of the appropriate solvent cannot be ignored during solvent aided-steam flooding processes.
Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
Sharma, Himanshu (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Recent studies on the use of ammonia as an alkali for performing alkali-surfactant-polymer (ASP) floods have shed light on its advantages over conventional alkalis such as lower alkali requirements, ease of transportation and storage. This study is aimed towards understanding surfactant adsorption in sandstone and carbonate rocks in the presence of ammonia. Zeta potential measurements were performed to characterize Bandera brown sandstone and Silurian dolomite surfaces in the presence of ammonia and sodium carbonate. A series of experiments were performed with and without ammonia such as static surfactant adsorption experiments on crushed Bandera brown sandstone and Silurian dolomite rocks, single phase surfactant transport experiments in sandstone and carbonate cores, surfactant phase behavior to identify an ultra-low interfacial tension (IFT) surfactant formulation, and oil recovery coreflood experiments using these surfactant formulations. Zeta potential measurements showed a reduction in zeta potential of Bandera brown and Silurian dolomite by adding ammonia to increase the pH. Surfactant adsorption experiments showed that ammonia was able to reduce the adsorption on sandstones, but not much difference was observed for carbonates. The ultra-low IFT surfactant formulations developed with and without ammonia showed very similar phase behavior. High oil recoveries and very low surfactant retentions were observed in the oil recovery experiments performed in sandstones.
Wang, Haitao (Petroleum Exploration & Production Research Institute, Sinopec) | Lun, Zengmin (Petroleum Exploration & Production Research Institute, Sinopec) | Lv, Chengyuan (Petroleum Exploration & Production Research Institute, Sinopec) | Lang, Dongjiang (Petroleum Exploration & Production Research Institute, Sinopec) | Pan, Weiyi (Petroleum Exploration & Production Research Institute, Sinopec) | Luo, Ming (Petroleum Exploration & Production Research Institute, Sinopec) | Wang, Rui (Petroleum Exploration & Production Research Institute, Sinopec) | Chen, Shaohua (Petroleum Exploration & Production Research Institute, Sinopec)
Nuclear magnetic resonance (NMR) was used to investigate the exposure between CO2 and matrix with permeability of 0.218 mD at 40 °C and 12 MPa. Before NMR experiment, the core was saturated with oil. To investigate the effects of exposure time on EOR, the saturated core was exposed to CO2 and T2 test was continuously performed with NMR system until the obtained T2 spectrum was unchanged. After the first exposure, CO2 and matrix reached equilibrium state. The second exposure started when CO2 injection was under a constant pressure of 12 MPa and at a constant rate to keep fresh CO2 in system. The procedure of T2 test was unchanged. The third and fourth exposures were conducted in sequence. The results showed that (1) Oil in all pores can mobilize as exposure time increases. (2) The recovery is 46.6% for oil in pores with the diameter of pore larger than 1 µm, this result is higher than the recovery (12.8%) for oil in pores with the diameter of pore smaller than 1 µm. (3) Recovery can be divided into two stages according to the exposure time: a fast-growing stage and a slow-growing stage. (4) Initially, the oil exists in pores with maximum radius of 21 µm in the originally saturated core. After CO2 injection, oil flows to pores with radius greater than 21 µm, suggesting that oil in tight matrix "diffuses" to the surface of core with exposure between CO2 and matrix. (5) The final recoveries of 1st, 2nd, 3rd, 4th exposure experiments are 23.7%, 7.2%, 2.6% and 1.5%, respectively.