XU, Ke (The University of Texas at Austin) | Zhu, Peixi (The University of Texas at Austin) | Tatiana, Colon (Polytechnic University of Puerto Rico) | Huh, Chun (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin)
Injecting oil-in-water (O/W) emulsions stabilized with nanoparticles or surfactants is a promising option for enhanced oil recovery (EOR) in harsh-condition reservoirs. Stability and rheology of flowing emulsion in porous media are key factors for the effectiveness of the EOR method. The objective of this study is to use microfluidics to (1) quantitatively evaluate the synergistic effect of surfactants and nanoparticles on emulsion's dynamic stability and how nanoparticles affects the emulsion properties, and (2) investigate how emulsion properties affect the sweep performance in emulsion flooding.
A microfluidic device with well-defined channel geometry of a high-permeability pathway and multiple parallel low-permeability pathways was created to represent a fracture – matrix dual-permeability system. Measurement of droplets’ coalescence frequency during flow is used to quantify the dynamic stability of emulsions. A nanoparticle aqueous suspension (2 wt%) shows excellent ability to stabilize macro-emulsion when mixed with trace amount of surfactant (0.05 wt%), revealing a synergic effect between nanoparticles and surfactant.
For a stable emulsion, it was observed that flowing emulsion droplets compress each other and then block the high-permeability pathway at a throat structure, which forces the wetting phase into low-permeability pathways. Droplet size shows little correlation with this blocking effect. Water content was observed much higher in the low-permeability pathways than in the high-permeability pathway, indicating different emulsion texture and viscosity in channels of different sizes. Consequently, the assumption of bulk emulsion viscosity in the porous medium is not applicable in the description and modeling of emulsion flooding process.
Flow of emulsions stabilized by the nanoparticle-surfactant synergy shows droplet packing mode different from those stabilized by surfactant only at high local oil saturation region, which is attributed to the interaction among nanoparticles in the thin liquid film between neighboring oil-water interfaces. This effect is believed to be an important contributing mechanism for sweep efficiency attainable from nanoparticle-stabilized emulsion EOR process.
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.
It is generally assumed that while the presence of foam reduces the mobility of the gas phase, it does not alter the mobility of the liquid phase. Here, the effect of surfactant type and concentration on the behavior of nitrogen foam flow in porous media is investigated by simultaneous injection of gas and surfactant into Bentheimer sandstone cores. Different surfactant types, viz., anionic alpha-olefin-sulfonate (AOS) and zwitterionic Betaine with different surfactant concentrations from critical-micelle-concentration (CMC) to higher concentration are used in this study. The foam strength is quantified by measuring the pressure drop in different sections of the core. The liquid saturation is measured by analyzing the X-ray images obtained in a medical CT-scanner.
It is shown that the connate water saturation is reduced by increasing the surfactant concentration, and therefore the relative permeability relation for the aqueous phase should be modified when fitting the data to the foam models. It is observed that it is not possible to fit one monotonic liquid relative permeability curve to all the data points, obtained with different surfactant type and concentration in one rock type. Moreover, increasing AOS concentration above a certain value does not have a significant effect on the mobility reduction of the gas phase; however it modifies the liquid relative permeability. These results indicate that the water relative permeability measured in absence of surfactant should not be used to model the flow of foam in porous media, as it can lead to erroneous calculations of the liquid saturation.
Yao, Chuanjin (China University of Petroleum) | Xu, Xiaohong (China University of Petroleum) | Wang, Dan (China University of Petroleum) | Lei, Guanglun (China University of Petroleum) | Xue, Shifeng (China University of Petroleum) | Hou, Jian (China University of Petroleum) | Cathles, Lawrence M. (Cornell University) | Steenhuis, Tammo S. (Cornell University)
Micron-size polyacrylamide elastic microspheres (MPEMs) are a smart sweep improvement and profile modification agent, which can be prepared controllably on the ground through inverse suspension polymerization using acrylamide crosslinked with an organic crosslinker. MPEMs can tolerate high temperature of 90 °C, high salinity of 20000 mg/L and wide pH value range of 4.0–10.3. MPEMs suspension almost has no corrosion effect on the injection pipeline and equipment. MPEMs can suspend in produced water easily and be pumped into formation at any rate. More importantly, MPEMs can reach the designed size after hydration swelling in oil formation and a reliable blockage can be formed; MPEMs can deform elastically and move forward step by step to realize a moveable sweep improvement and profile modification process in reservoirs. The pore-scale visualization experiment shows that there are four migration patterns for MPEMs transport in porous media and they are smooth passing, elastic plugging, bridge plugging and complete plugging. MPEMs can deform depending on their elasticity and pass through these pore-throats. Parallel-sandpack physical modeling experiment under the simulated reservoir conditions shows that MPEMs mainly enter into and plug high permeability layer whose permeability is reduced from 3.642 µm2 to 0.546 µm2, and almost do not clog low-permeability layer whose permeability is reduced from 0.534 µm2 to 0.512 µm2. Field application results of MPEMs treatment in a serious heterogeneous, high temperature and high salinity reservoir show that MPEMs can effectively improve swept volume and displacement efficiency. Because of the excellent properties, MPEMs treatment will become a cost-effective method for sweep improvement and profile modification to serious heterogeneous, high temperature and high salinity reservoirs with fractures and channels.
Yeganeh, Mohsen (ExxonMobil Research and Engineering Co.) | Hegner, Jessica (ExxonMobil Research and Engineering Co.) | Lewandowski, Eric (ExxonMobil Research and Engineering Co.) | Mohan, Aruna (ExxonMobil Research and Engineering Co.) | Lake, Larry W. (The University of Texas at Austin) | Cherney, Dan (ExxonMobil Research and Engineering Co.) | Jusufi, Arben (ExxonMobil Research and Engineering Co.) | Jaishankar, Aditya (ExxonMobil Research and Engineering Co.)
A capillary desaturation curve (CDC) depicts the relationship between residual oil saturation, Sor, (i.e. oil left behind in a well-swept permeable medium) and capillary number. A CDC is one of the most fundamental curves of oil recovery as it reveals flow conditions required for good oil displacement in porous media. Despite the importance of this critical curve, the fundamentals describing the physics of a CDC are still incomplete.
We present a physical model to describe the capillary desaturation curve. The model balances the capillary pressure and applied viscous stresses caused by flow and takes advantage of contact angle hysteresis that occurs in porous media. It defines a critical oil ganglia length that depends inversely on capillary number and depends on porosity, permeability, and wettability. We have combined the critical oil ganglia expression and ganglia length distribution in porous media to arrive at an expression for the capillary desaturation curve. The model suggests that when a trapped oil ganglion is larger than the critical ganglia length, the applied pressure difference can mobilize the trapped oil ganglion. We describe the differences and similarities between our critical ganglia length expression and previously reported expressions. The model describing the relationship between residual oil saturation and capillary number was successfully verified with microfluidic experiments using various crude oils and displacing fluids. We have also demonstrated that the model applies to previously reported coreflood CDCs from sandstone and carbonate media. Extension of the model led to a single curve representation of variations in Sor with reduced pressure. This representation is independent of the chemistry of the displacing fluid.
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.
An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.
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.
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.