Achieving maximum oil recovery utilizing CO2 has limitations when operating at, or very close, to the Minimum Miscibility Pressure (MMP) of the CO2 in the oil. A modular source of CO2 would allow Enhanced Oil Recovery (EOR) flooding of "stranded" and shallow reservoirs. Unfortunately, modular sources of CO2 production often include CO and N2 mixed with the CO2. Thus, testing for EOR application of a mixed gas-containing CO2, N2, and CO was initiated.
Bench scale testing using Rising Bubble Apparatus (RBA), Slim Tubes, and linear core flood have been conducted on oils ranging from 16-42° gravities having viscosities of 0.5-280 cp. All tests were conducted at reservoir temperatures and pressures. CO, being a strong reducing agent, was further tested on reservoir rock containing swelling clays with hydrated ferric hydroxides. Due to the apparent reduction of the ferric hydroxide, and the liberation of its water of hydration, an increase in matrix permeability and clay stabilization, was observed.
For most oils tested, the CO2/CO mixture increased rate of oil recovery by 2-3X, using only 50-60% as much gas/bo as compared to pure CO2. Recovery factors of 80%, at immiscible pressures 30-40% below CO2 MMP, were achieved. Addition of 15% N2 (v/v) to the CO2/CO mixture did not impair oil recovery. Interfacial testing (IFT) of oils, using pure CO, demonstrated a lowering of the IFT. RBA testing of asphaltine-rich heavy oils has shown that a mixture of CO2/CO dissolves into the oil at a far faster rate than either CO2 or CO individually and faster than the sum of both individual gases. A similar test using non-asphaltine type oils did not display this unique characteristic. Slim tube testing suggests that CO facilitates the mobilization of asphaltine-rich heavy oils and lowers viscosity. A linear corefloods of a reservoir containing 5% smectite + illite/smectite + and chlorite demonstrated a 275% increase in matrix permeability. Packed column tests, containing quartz sand and bentonite, demonstrated up to 300-900% increase in permeability in the presence of CO.
Thus a method to recover oil faster, from stranded reservoirs, at pressures below MMP, using significantly less gas, appears possible. In addition the use of CO, either alone or in combination with CO2 and/or N2, has been shown to increase matrix permeability. Such a gas mixture may be beneficial to achieving low pressure EOR from shallow, "stranded" reservoirs, non-conventional shale oil reservoirs, and viscous, heavy oil reservoirs at low temperatures. Incorporation of CO, or CO2/CO, in a frac fluid, or alternately as a post frac cleanup for shale oil and gas applications appears to warrant investigation.
Low-salinity waterflooding has been portrayed as an effective enhanced-oil recovery technology. Despite compelling laboratory and field evidence of its potential, the underlying mechanisms still remain controversial. In this study, the enhanced-oil recovery mechanisms are investigated considering a distinct interfacial effect, i.e. water-crude oil interfacial viscoelasticity, through analysis of capillary hysteresis. An experimental setup with an oil-wet and a water-wet media on each end face of the core sample was utilized to capture capillary and rock electrical properties hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method were implemented to accelerate measurements. Two experiments were conducted on Minnelusa formation rock samples and TC crude oil, at low temperature (30 °C) and without any significant aging as to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. It is found that the dynamic-static method with a ceramic disk, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short 1" long core samples, allows one to capture the correct envelopes of the capillary pressure curves and save ~ 30% of the total time; a thin membrane is anticipated to save ~90% with respect to traditional quasi-static porous plate method. The capillary hysteresis experiments at low temperature prove that low-salinity brine is able to suppress capillary hysteresis. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. In addition, we show that wettability plays an essential role on electrical resistivity and the more oil-wet, the more hysteresis occurs, namely that resistivity values in imbibition are higher than those in drainage. The findings in this paper demonstrate that low-salinity waterflooding can still increase oil recovery even in the absence of wettability alteration.
Pilots are widely used for the purpose of gathering valuable information about performance and practical challenges of implementing a particular CEOR process in a given field (
Addition of chemical species to the material balance equations alongside finer resolution requirements for CEOR simulations compared to waterfloods (WF), often make it impractical to run full field CEOR simulations to the required accuracy. Massively parallel computing, dynamic local grid refinement and sector modeling have been used with varying success, of which sector modeling is the most common. Sector models, by their very definition, are also naturally suited for modeling of pilots.
The art of sector modeling needs mastering a few important steps such as: appropriate selection of the sector model extent, details on carving it out of the Full Field Model (FFM), populating it with proper petrophysical and fluid properties, initializing it to correct initial conditions and optimizing its boundary conditions. On top of that, choice of optimum grid size for proper trade-off of simulation run times and accuracy needs to be considered.
This paper presents a case study for appropriate simulation of a CEOR pilot within Chevron. The candidate has a waterflood history matched FFM. This model is used to generate a sector model for the CEOR pilot area. This paper outlines how the extent of the sector model and all the regions in communication with the Area of Interest (AOI) is decided. It also discusses proper initialization and optimization of the boundary conditions of the sector model along with its appropriate refinement and grid optimization. Proper CEOR simulations on the final optimized sector model and sensitivity analysis are also presented. The challenges, lessons learned and best practices are shared and important considerations for adequate simulation of CEOR processes are outlined.
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.
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.
Wu, Xingcai (Research Inst. of Petroleum E&D, RIPED, CNPC) | Yang, Zhongjian (Qinghai Oilfield Company, QOC, CNPC) | Xu, Hanbing (RIPED) | Zhang, Lihui (QOC) | Xiong, Chunming (RIPED) | Yang, Huazhen (Huabei Oilfield Company, HOC, CNPC) | Shao, Liming (RIPED) | Kang, Bo (Chengdu North Petroleum E&D Technology Co. Ltd.) | Fu, Yaxiu (HOC) | Tian, Xiaoyan (Startwell Energy Co. Ltd) | Cao, Huiqing (HOC)
Though polymer flooding is widely considered as a good EOR method for heterogeneous fields, it's always a difficulty to be applied in high temperature and high salinity reservoirs, limited by polymer property. GS-E31 reservoir in West China has ultra-high temperature, 258.8°F (126°C), and ultra-high salinity, 18×104mg/L. It is highly heterogeneous, developed with flowing channels. Starting in July 2012, a new polymer (SMG) flooding was pilot tested, with success technically and economically.
Before SMG injection, tracer test was conducted in the pilot, figuring out the distribution position and direction of prevailing flowing channels. The microscopic pore structure and size were studied. The temperature and salinity resistance of the new particle-type polymer under reservoir condition was tested. The oil displacing effect was simulated on parallel dual core model. For the pilot test, two slugs with different particle sizes were designed. To guarantee the flooding effect, a preposed PPG (preformed particle gel) slug with larger size was designed to inhibit prevailing flow channels.
The lab studies showed the new polymer particles kept stable appearance within 100 days under the reservoir temperature and salinity, denoting high capacity of temperature and salinity resistance. And by physical simulation it could obtain EOR of 12.3%. The pilot test was started in July 2012 and ended in December 2013, and the total liquid injection amount was 12.2×104m3, which was 0.1 PV. During operation, the polymer particle size and concentration were adjusted based on the observing data. As a result, the monthly oil rate of the pilot was increased from 1313 t to 2049.6 t, with increase of 736.6 t; and the water cut was decreased from 91.7% to 84.1%. The cumulative oil incremental was 1.03×104t, and the cumulative water production decrease was 4.79×104m3. The input-output ratio was 1:2.09. Though the economical result was not ideal, it was still acceptable under such severe reservoir conditions. Besides, the surveillance showed the preposed channeling inhibition slug did not perform well, which affected the NPF effect, and especially led to the quick water cut rising in the follow-up water injection phase.
Summarizing the lat studies and pilot tests, the new particle-type polymer has obtained a large breakthrough for temperature and salinity resistance comparing to traditional polymer, and the EOR mechanism is different. The matching relationship between particle size and formation pore size is very important for polymer flooding effect. To further study on lab evaluation method and plan optimization is needed. The technology has important referencing meaning for efficiently developing high temperature and high salinity fields.
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).
Foamed fluids with the gas phase of carbon dioxide (CO2) have been applied as fracturing fluids to develop unconventional resources. This type of fracturing fluids meets the waterless requirements by unconventional reservoirs, which are prone to damage by clay swelling and blocking pore throat in water environment. Conventional CO2 foams with surfactants have low durability under high temperature and high salinity, which limit their application. Nanoparticles provide a new technique to stabilize CO2 foams under harsh reservoir conditions. It's essential to determine in-situ rheology of CO2 foams stabilized by nanoparticles in order to predict proppant transport in reservoir fractures and improve oil production.
The shear viscosity and foam texture of non-Newtonian fluids under reservoir conditions are critical to transport proppant and generate effective micro-channels. This study determined the in-situ shear viscosity of supercritical CO2 foams stabilized by nano-SiO2 in the Flow Loop apparatus with shear rates of 5950~17850 s-1 at the pressure of 1140±20 psig and the temperature of 40 °C. Supercritical CO2 with the density of 0.2~0.4 g/ml and the viscosity of 0.02~0.04 cp under typical reservoir conditions were applied to generate foams. The foams were tested with high foam quality up to 80% to minimize the usage of water. The effects of shear rates, salinity, surfactant, and nanoparticle sizes and on the rheology of gas foams with different foam qualities were experimentally investigated. The foam texture and stability were observed through an in-line sapphire tube. Further, proppant transport by CO2 foams and the placement in fractures were analyzed by considering the rheology of non-Newtonian fluids and the mechanisms of gravity driven settling and hindered settling/slurry flow.
The conditions of nanoparticle foaming systems were optimized through orthogonal experimental design. The dense and stable foams were generated and observed under high pressure and elevated temperature conditions. It was observed that CO2 foams with high quality of 80% demonstrated the highest viscosity and stability under optimal conditions. The foams with nanoparticles demonstrated both shear- thinning and shear-thickening behaviors depending on foam quality and components. The salinity and nanoparticle size affect foam rheology in two ways depending on components, foam quality, and shear rates.
While the viscosities of CO2 foam stabilized by nanoparticles have been widely studied recently, no work has been done to observe the stability and texture of supercritical CO2 foam after shearing under high pressure and high temperature, not to mention proppant transport by CO2 foam. This study provided a pioneering insight to the proppant transport by viscous supercritical CO2 foam stabilized by nanoparticles.
Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements.
Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil.
DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation.
In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (