An Experimental Investigation on Foam Injection in a Fractured Matrix : Effect of Viscous Cross flow (original) (raw)
Experimental Study of Foam Flow in Fractured Oil-Wet Limestone for Enhanced Oil Recovery
SPE Improved Oil Recovery Symposium, 2010
The use of foam to increase oil recovery by reducing the gas mobility during gas injection in heterogeneous reservoirs with permeability variations is a proven EOR technology. The use of foam for fracture permeability reduction in fractured reservoirs is less studied. In this work laboratory experiments using foam to reduce fracture transmissivity and improve the matrix sweep in highly fractured, low permeable, oil-wet limestone are reported. Oil recovery either by individual water-, surfactant-, or gas injection exhibited low recovery, less than 10%OIP, with oil recovered predominately from the fractures. Oil recovery was significantly improved by simultaneous injection of surfactant and gas to generate foam in the fracture network and thus divert flow to the oil saturated matrix. Two foam injection schemes were tested: 1) co-injection of surfactant and gas in the fracture for in-situ foam generation, and 2) pre-generated foam injection. In-situ foam generation in the smooth-walled...
Foam Application in Fractured Carbonate Reservoirs: A Simulation Study
Petroleum University of Technology, 2019
Fractured carbonate reservoirs account for 25% of world's total oil resources and for 90% of Iranian oil reserves. Since calcite and dolomite minerals are oil wet, gas oil gravity drainage (GOGD) is known as the most influencing production mechanism. The most important issue within gas injection into fractured media is the channeling problem which makes the efficiency of gas injection process extremely low. As a solution, foam is used to change the mobility ratio, to increase volumetric sweep efficiency, and to overcome the fingering problem. In this work, we inspected three main influencing mechanisms that affect oil extraction from matrix, namely foam/oil gravity drainage, viscous pressure drop due to foam flow in fractures, and foaming agent diffusion from fractures into the matrixes. Foam injection simulations were performed using CMG STARS 2015, on a single matrix unit model and on some vertical cross section models. A number of sensitivity analyses were performed on foam strength, injection rate, fracture and matrix properties, matrix heights, and the initial oil saturation within matrixes. The results show that the roles of the mass transfer of the foaming agent and viscous pressure drop are significant, especially when matrix average heights are small. Moreover, the mechanism for viscous pressure drop remains unchanged, which continues to aid oil extraction from matrixes while the other two mechanisms weaken with time.
Evaluating the application of foam injection as an enhanced oil recovery in unconsolidated sand
Journal of Petroleum and Gas Engineering, 2015
In the Niger Delta, low oil recovery rates less than 30% results mainly due to oil production problems such as water coning, wax deposition and high gas/oil ratios. Meanwhile, the remaining oil becomes a good candidate for EOR methods such as CO 2 injection, polymer and foam injection, in-situ combustion and steam injection. But as it stands, the practice of these known methods of enhanced oil recovery is scarce in the Nigeria's Oil and Gas industry. However, this project is aimed at evaluating the application of foam injection as an enhanced oil recovery method in sandstone reservoir and exploring possible improvement of oil production in the Niger Delta. The project was carried out using two cases. In Case 1, a synthetic model built with static modeling software, later imported to dynamic modeling software and simulated to mimic foam injection process while in Case 2 a real life model with an aquifer fully populated with the necessary reservoir and fluid properties and production history. From the results obtained in Case 1, production indices, field oil recovery, etc. were compared with gas flooding process. For foam flooding, a significant increase in oil recovery as compared to gas flooding and reduction in gas oil ratio and gas produced were observed while in Case 2, field oil recovery, oil production rate, cumulative oil production, gas oil ratio and water cut were compared and significant increase oil recovery using foam flooding, and reduced field water cut was also observed. The economic viability of the project in both cases was also investigated using some economic indicators. Improved displacement efficiency resulting into increased recoverable reserves, and subsequently increased total field oil production has been achieved by foam injection.
CT Scan Study of Immiscible Foam Flow in Porous Media for Enhancing Oil Recovery
Industrial & Engineering Chemistry Research, 2013
A systematic CT-scan-aided laboratory study of N 2 foam in Bentheimer sandstone cores is reported. The aim of the study was to investigate whether foam can improve oil recovery from clastic reservoirs subject to immiscible gas flooding. Foam was generated in situ in water-flooded sandstone cores by coinjecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely, C 14−16 α-olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) ester. The effects of surfactant concentration, injection direction, surfactant preflush, and core length on foam behavior were examined in detail. Stable foams were obtained in the presence of waterflood residual oil. It was found that foam strength (mobility reduction factor) increases with surfactant concentration. Foam development and, correspondingly, oil recovery without surfactant preflush were delayed compared to the case with preflush. Gravity-stable foam injection caused a rapid increase in foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods revealed that the incremental oil recovery by foam was as much as (23 ± 2)% of the oil initially in place after injection of 4.0 pore volumes (PV) of foam (equal to the injection of 0.36 PV of surfactant solution). Incremental oil recovery was only (5.0 ± 0.5)% for gas flooding under the same injection conditions. It appears that oil production by foam flooding occurs by the following main mechanisms: (1) residual oil saturation to foam flooding is lower than that to water flooding; (2) formation of an oil bank in the first few injected pore volumes, coinciding with a large increase of capillary number; and (3) a long tail production due to the transport of tiny oil droplets within the flowing foam at a fairly constant capillary number. The observations of this study support the concept that foam is potentially an efficient enhanced oil recovery (EOR) method.
Foam sweep in fractures for enhanced oil recovery
Colloids and Surfaces A: Physicochemical and Engineering Aspects, 2006
A theory for foam flow in a uniform fracture was developed and verified by experiment. The apparent viscosity was found to be the sum of contributions arising from liquid between bubbles and the resistance to deformation of the interfaces of bubbles passing through the fracture. Apparent viscosity increases with gas fractional flow and is greater for thicker fractures (for a given bubble size), indicating that foam can divert flow from thicker to thinner fractures. This diversion effect was confirmed experimentally and modeled using the above theory for each individual fracture. The amount of surfactant solution required to sweep a heterogeneous fracture system decreases greatly with increasing gas fractional flow owing to the diversion effect and to the need for less liquid to occupy a given volume when foam is used.
A review of recent advances in foam-based fracturing fluid application in unconventional reservoirs
Journal of Industrial and Engineering Chemistry, 2018
Foam-based fracturing fluid application in unconventional reservoirs has recently attracted prodigious attention, due to their high apparent viscosity and ultra-low water contents, which enhanced their potential applications as proppants carrier fluids in water sensitive formations. A comprehensive review of existing literature on the applications and recent advancement of foam fracturing fluid is conducted in this study. Results of experimental studies, simulations predictions and field applications were extensively discussed. Challenges and knowledge gaps were identified and directions for future studies were suggested. The review literature suggested that stable foam fracturing fluids can increase the productivity of the fractured wells.
Screening and optimisation of water/foam/gas injection EOR scenarios in a fractured reservoir
Primary sweep efficiency in carbonate reservoirs is low due to the low contribution of the matrix in production. Also, due to unfavourable mobility ratio, secondary recovery is not also effective. Hence, design and application of an effective enhanced oil recovery method is essential to improve recovery. Different methods such as water injection, gas injection, chemical injection, thermal, and a combination of these methods such as water alternating gas (WAG), simultaneous WAG (SWAG), selective simultaneous WAG (SSWAG), foam injection, and foam-assisted WAG (FAWAG) are applied to improve the recovery efficiency in naturally fractured reservoirs. In this paper, selection of the best EOR method and well pattern for a naturally fractured reservoir is studied to reach the highest net present value (NPV) and field oil recovery efficiency (FOE). Results showed that the FAWAG process in a five-spot well pattern with 22.7% oil recovery efficiency is the best technical and economical method. Reference to this paper should be made as follows: Bagrezaie, M.A. and Pourafshary, P. (2016) 'Screening and optimisation of water/foam/gas injection EOR scenarios in a fractured reservoir', Int.
Energy Exploration & Exploitation
Foam flooding is considered as one of the beneficial chemical enhanced oil recovery techniques to increase the value of gas viscosity and thereby, the efficiency of the produced oil would be improved dramatically rather than other methodologies. The objective of this extensive study is to determine a suitable injectivity model for one of the heterogeneous sandstone reservoir in which hydrolyzed polyacrylamide concentration in the solution foam has the most recovery factor. To do this, the results of laboratory investigation and simulation analysis are taken into consideration in different injectivity scenarios to obtain the more efficient scenario. Consequently, higher concentration of hydrolyzed polyacrylamide in the foaming agent, the high volume of oil has been produced after 10 years of producing. Furthermore, by selecting three cores from the three wells in this field, it is clarified that, owing to the increasing the volume of foam in the injectivity fluid, the pressure drop increased dramatically and subsequently has leaded to produced more oil volume.
Spe Journal, 2019
Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil-wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection-strategy investigation of ultralow-interfacialtension (IFT) foam in a high-temperature (greater than 80 C), ultrahigh-formation-salinity [greater than 23% total dissolved solids (TDS)] fractured oil-wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontaldilution map was created to simulate frontal-displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk-foam tests were also conducted to study the salinity-gradient effect on the performance of ultralow-IFT foam. Ultralow-IFT foam-injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil-wet core systems with initial oil/brine two-phase saturation. The representative fractured system included a well-defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10 À2 to 10 À3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow-IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow-IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil-wet systems because of the selective diversion of ultralow-IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high-salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high-salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow-IFT foam process to ensure good foam propagation and high oil-recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow-IFT foam in high-temperature, ultrahighsalinity fractured oil-wet carbonate reservoirs and investigated the injection strategy to enhance the low-IFT foam performance. The ultralow-IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility-control agent in a fractured system for better sweep efficiency.