Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood

SPE Journal ◽  
2014 ◽  
Vol 19 (05) ◽  
pp. 931-942 ◽  
Author(s):  
Shayan Tavassoli ◽  
Jun Lu ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Numerical Simulations ◽  
Critical Velocity ◽  
Oil Recovery ◽  
Horizontal Wells ◽  
Mobility Control ◽  
Oil Reservoirs ◽  
Three Dimensions ◽  
Analytical Models ◽  
Oil Viscosity ◽  
Fine Grid

Summary Classical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world's largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

Individual Fracture Efficiency Monitoring in Horizontal Wells by Using a New 3d Fine-Grid Temperature Modelling

2021 ◽  
Author(s):  
Vitaly Virt ◽  
Vladimir Kosolapov ◽  
Vener Nagimov ◽  
Andrey Salamatin ◽  
Yulia Fesina ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Transient Analysis ◽  
Horizontal Wells ◽  
Sweep Efficiency ◽  
Fine Grid ◽  
Hydrodynamic Parameters ◽  
Multistage Hydraulic Fracturing ◽  
Multi Stage ◽  
Differential Efficiency

Abstract Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.

An Investigation Into Propagation Behavior of the Steam Chamber During Expanding-Solvent SAGP (ES-SAGP)

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 413-430
Author(s):  
Zhanxi Pang ◽  
Lei Wang ◽  
Zhengbin Wu ◽  
Xue Wang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Physical Simulation ◽  
Heat Losses ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Experimental Conditions ◽  
Steam Chamber ◽  
Heavy Oil Reservoirs

Summary Steam-assisted gravity drainage (SAGD) and steam and gas push (SAGP) are used commercially to recover bitumen from oil sands, but for thin heavy-oil reservoirs, the recovery is lower because of larger heat losses through caprock and poorer oil mobility under reservoir conditions. A new enhanced-oil-recovery (EOR) method, expanding-solvent SAGP (ES-SAGP), is introduced to develop thin heavy-oil reservoirs. In ES-SAGP, noncondensate gas and vaporizable solvent are injected with steam into the steam chamber during SAGD. We used a 3D physical simulation scale to research the effectiveness of ES-SAGP and to analyze the propagation mechanisms of the steam chamber during ES-SAGP. Under the same experimental conditions, we conducted a contrast analysis between SAGP and ES-SAGP to study the expanding characteristics of the steam chamber, the sweep efficiency of the steam chamber, and the ultimate oil recovery. The experimental results show that the steam chamber gradually becomes an ellipse shape during SAGP. However, during ES-SAGP, noncondensate gas and a vaporizable solvent gather at the reservoir top to decrease heat losses, and oil viscosity near the condensate layer of the steam chamber is largely decreased by hot steam and by solvent, making the boundary of the steam chamber vertical and gradually a similar, rectangular shape. As in SAGD, during ES-SAGP, the expansion mechanism of the steam chamber can be divided into three stages: the ascent stage, the horizontal-expansion stage, and the descent stage. In the ascent stage, the time needed is shorter during ES-SAGP than during SAGP. However, the other two stages take more time during nitrogen, solvent, and steam injection to enlarge the cross-sectional area of the bottom of the steam chamber. For the conditions in our experiments, when the instantaneous oil/steam ratio is lower than 0.1, the corresponding oil recovery is 51.11%, which is 7.04% higher than in SAGP. Therefore, during ES-SAGP, not only is the volume of the steam chamber sharply enlarged, but the sweep efficiency and the ultimate oil recovery are also remarkably improved.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

Prediction of Recovery in Unstable Miscible Flooding

1972 ◽  
Vol 12 (02) ◽  
pp. 143-155 ◽  
Author(s):  
E.L. Claridge
Keyword(s):  
Economic Evaluation ◽  
Crude Oil ◽  
Oil Recovery ◽  
Pore Space ◽  
Vertical Direction ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Recovery Processes ◽  
First Choice

Abstract A new correlation bas been developed for estimating oil recovery in unstable miscible five-spot pattern floods. It combines existing methods of predicting areal coverage and linear displacement efficiency and was used to calculate oil recovery for a series of assumed slug sizes in a live-spot CO2 slug-waterflood pilot test. The economic optimum slug size varies with CO2 cost; at anticipated CO2 costs the pilot would generate an attractive profit if performance is as predicted Introduction Selection of good field prospects for application of oil recovery processes other than waterflooding is often difficult. The principal reason is that other proposed displacing agents are far more costly proposed displacing agents are far more costly than water and usually sweep a lesser fraction of the volume of an oil reservoir (while displacing oil more efficiently from this fraction). Such agents must be used in limited amounts as compared with water; and this amount must achieve an appreciable additional oil recovery above waterflooding recovery. For these reasons, there is in general much less economic margin for engineering error in processes other than waterflooding. The general characteristics of the various types of supplemental recovery processes are well known, and adequate choices can be made of processes to be considered in more detail with respect to a given field. Comparative estimates must then be made of process performance and costs in order to narrow the choice. A much more detailed, definitive process-and-economic evaluation is eventually process-and-economic evaluation is eventually required of the chosen process before an executive decision can be made to commit large amounts of money to such projects. It is in the area between first choice and final engineering evaluation that this work applies. A areal cusping and vertical coning into producing wells. These effects can be seated by existing "desk-drawer" correlation which can confirm or deny the engineer's surmise that he has an appropriate match of recovery process and oil reservoir characteristics is of considerable value in determining when to undertake the costly and often manpower-consuming task of a definitive process-and-economic evaluation. process-and-economic evaluation. An examination of the nature of the developed crude oil resources in the U.S. indicates that the majority of the crude oil being produced is above 35 degrees API gravity and exists in reservoirs deeper than 4,000 ft. The combination of hydrostatic pressure on these oil reservoirs, the natural gas usually present in the crude oil in proportion to this pressure, the reservoir temperatures typically found, and the distribution of molecular sizes and types in the crude oil corresponding to the API gravity results in the fact that, in the majority of cases, the in-place crude oil viscosity was originally no more than twice that of water. A large proportion of these oil reservoirs have undergone pressure decline, gas evolution and consequent increase in crude oil viscosity. However, an appreciable proportion are still at such a pressure and proportion are still at such a pressure and temperature that miscibility can be readily attained with miscible drive agents such as propane or carbon dioxide, and the viscosity of the crude oil is such that the mobility of these miscible drive agents is no more than 50 time s that of the crude oil. Under these circumstances, a possible candidate situation for the miscible-drive type of process may exist. process may exist. Supposing that such a situation is under consideration, the next question is: what specific miscible drive process, and how should it be designed to operate? In some cases, the answer is clear: when the reservoir has a high degree of vertical communication (high permeability and continuity of the permeable, oil-bearing pore space in the vertical direction), then a gravity-stabilized miscible flood is the preferred mode of operation; and the particular drive agent or agents can be chosen on the basis of miscibility requirements, availability and cost. SPEJ P. 143

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

Methane Pressure-Cycling Process With Horizontal Wells for Thin Heavy-Oil Reservoirs

2006 ◽  
Vol 9 (02) ◽  
pp. 154-164 ◽  
Author(s):  
Mingzhe Dong ◽  
S.-S. Sam Huang ◽  
Keith Hutchence
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Oil Reservoirs ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Pressure Cycling ◽  
Oil Resources ◽  
Heavy Oil Reservoirs ◽  
Secondary Methods

Summary The methane pressure-cycling (MPC) process is an enhanced-oil-recovery (EOR) scheme intended for application in some heavy-oil reservoirs after termination of either primary or waterflood production. The essence of the process is the restoration of the solution-gas-drive mechanism. The restoration is accomplished by reinjecting an appropriate amount of solution gas (mainly methane) and then repressuring the gas back into solution by injecting water until approximate original reservoir pressure is reached. This, aside from the replacement of produced oil by water, recreates the primary-production conditions. This novel recovery technique is being developed to target the considerable portion of heavy-oil resources located in thin reservoirs. Primary and secondary methods have managed to recover at best 10% of the initial oil in place (IOIP). Heat losses to overburden and underburden or bottomwater zones make thermal methods unsuitable for thin reservoirs. Sandpack-flood tests in 30.5-cm (length) × 5.0-cm (diameter) sandpacks were carried out for oils with a range of dead-oil viscosities from 1700 to 5400 mPa.s. The results showed that the pressure-cycling process could create a favorable condition for recharged gas to contact the remaining oil in reservoirs. This restores the situation whereby substantial amounts of gas are in solution for further "primary" production. The effects on the efficiency of the MPC process of cycle termination strategy, oil viscosity, and mobile-water saturation were investigated. Simulations were conducted to investigate the MPC process in three heavy-oil reservoirs in Saskatchewan, Canada. The effects on the process of infill wells, oil viscosity, gas-injection rate, and the presence of wormholes in reservoirs were studied. Introduction Heavy oil in thick-pay reservoirs (i.e., >10 m) is commonly produced with thermal-recovery methods. These methods (steam injection and its variants) are generally not suitable for thin reservoirs because of heat losses to overburden and underburden or bottomwater zones (Fairfield and White 1982; Dyer et al. 1994). The world's large untapped oil resource remaining after recovery by conventional technology offers potential for exploitation by a suitably developed tertiary-recovery technique. For example, Saskatchewan accounts for 62% of Canada's total heavy-oil resources (Bowers and Drummond 1997), including 1.7 billion m3 of proved reserves and 3.7 billion m3 of probable reserves (Saskatchewan Energy and Mines 1998). Of the province's proven initial heavy oil in place, 97% is contained in reservoirs where the pay zone is less than 10 m, and 55% in reservoirs with a pay zone less than 5 m thick (Huang et al. 1987; Srivastava et al. 1993). Primary and secondary methods combined recover, on average, only about 7% of the proven IOIP (Saskatchewan Energy and Mines 1998). The incentive is strong for the development of appropriate EOR techniques that will maximize the recovery potential of and profitability from these thin heavy-oil reservoirs. Extensive literature is available on CO2, flue gas, and produced-gas injection for heavy-oil recovery, including slug displacement, water alternating gas (WAG), and cyclic (huff ‘n’ puff) processes (Huang et al. 1987; Srivastava et al. 1993, 1994, 1999; Srivastava and Huang 1997; Ma and Youngren 1994; Issever et al. 1993; Olenick et al. 1992). A comparative study of the oil-recovery behavior for a 14.1°API heavy oil with different injection gases (CO2, flue gas, and produced gas) showed that CO2 was the best-suited gas for EOR of heavy oils (Srivastava et al. 1999). Cyclic CO2 injection for heavy-oil recovery was tested in the field, and field case histories indicated that oil production was enhanced (Olenick et al. 1992). However, natural CO2 sources are not available to most oil reservoirs. The cost of CO2 capture from flue gas and other sources may range from U.S. $25 to $70/ton (Padamsey and Railton 1993). Produced gas is available in large quantities at a much lower cost. With this consideration, produced gas can be an economically effective agent for heavy-oil recovery by the cyclic-injection process.

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