Unconventional oil and gas resources such as shale gas, shale oil, CBM, tight gas and oil have attracted more and more attention worldwide in recent years. However, most of the formations of unconventional oil and gas are suffering from poor geological condition, thus the resources can not be developed without fracturing stimulation. Conventional hydraulic fracturing usually consumes a huge amount of water and also leads to the pollutions of surface water and even residential water. In addition, the formation damage caused by incomplete gel breaking, adsorption of polymers, clay expansion and water blocking are still not fully eliminated.
Thus, in this work, ultra-dry CO2 foam stabilized by graphene oxide (GO) were explored to get a fracturing fluid characterized by low water consumption, environmental friendliness, high efficiency and low formation damage. The foam quality of fracturing fluid in the study was higher than 90%, thus the water consumption of fracturing fluid was lower than 10% of total volume. The foam stability, rheology and dynamic filtration were studied by using a large-scale fracturing fluid test device.
The results showed that the stability and thermal adaptability of ultra-dry CO2 foam were enhanced by the addition of graphene oxide. The interfacial dilatational viscoelastic modulus of CO2/liquid was increased when the graphene oxide was used with saponin, implying that the bubble film interface became solid-like; The ultra-dry CO2 foam enhanced by the graphene oxide showed a shear thinning behavior. The effective viscosity of ultra-dry CO2 foam was increased by adding graphene oxide and its viscosity was higher than 50 mPa·s at a shear rate of 100s-1; Moreover, compared to pure surfactant foam, the filtration control performance of ultra-dry CO2 foam was also enhanced by graphene oxide. At a filtration pressure difference of 3.5MPa, the filtration coefficient of ultra-dry CO2 foam was decreased significantly by the addition of graphene oxide. Although the core damage caused by foam with graphene oxide was slightly higher than that of pure surfactant foam, the permeability damage was still below 10%, implying that the foam as a fracturing fluid is relatively clean to formation.
Ultra-dry CO2 foam fracturing fluid stabilized by graphene oxide provides a new high-performance fracturing system for unconventional oil and gas at water-deficient area. This study will be beneficial to fracturing applications characterized by low water consumption, environmental friendliness, high efficiency and low formation damage.
Foamy-oil flow has been successfully demonstrated in laboratory experiments and site applications. On the basis of solution-gas-drive experiments with Orinoco belt heavy oil, the effects of temperature on foamy-oil recovery and gas/oil relative permeability were investigated. Oil-recovery efficiency increases and then decreases with temperature and attains a maximum value of 20.23% at 100°C. The Johnson-Bossler-Nauman (JBN) method has been proposed to interpret relative permeability characteristics from solution-gas-drive experiments with Orinoco belt heavy oil, neglecting the effect of capillary pressure. The gas relative permeability is lower than the oil relative permeability by two to four orders of magnitude. No intersection was identified on the oil and gas relative permeability curves. Because of an increase in temperature, the oil relative permeability changes slightly, and the gas relative permeability increases. Thermal recovery at an intermediate temperature is suitable for foamy oil, whereas a significantly higher temperature can reduce foamy behavior, which appears to counteract the positive effect of viscosity reduction. The main reason for the flow characteristics of foamy oil in porous media is the low gas mobility caused by the oil components and the high viscosity. High resin and asphaltene concentrations and the high viscosity of Orinoco belt heavy oil increase the stability of bubble films and prevent gas breakthrough in the oil phase, which forms a continuous gas, compared with the solution-gas drive of light oil. The increase in the gas relative permeability with temperature is caused by higher interfacial tensions and the bubble-coalescence rate at high temperatures. The experimental results can provide theoretical support for foamy-oil production.
Li, Zhaomin (China University of Petroleum) | Liu, Zupeng (China University of Petroleum) | Li, Binfei (China University of Petroleum) | Li, Songyan (China University of Petroleum) | Sun, Qian (China University of Petroleum) | Wang, Shuhua (China University of Petroleum)
Foam is a proven method for decreasing gas mobility in both homogeneous and heterogeneous reservoirs. A new foam system, called multi-phase foam system composed of gas, liquid, and particles has been studied in China recently since it has better performance than general gas-liquid foam system in profile control.
The aqueous foams prepared by mixtures of pre-performed particles and surfactants were studied in detail. In this article a new method focusing on liquid drainage velocity was used to estimate the stability of multi-phase foam system compared with classical foam stability studies that record foam height variation versus time. A synergistic effect on foam stability occurs and becomes more obvious with increasing surfactant concentration. The synergistic effect mainly comes from the adsorption of particles on the bubble surface and the formation of a three-dimensional network in the coherent phase. In addition, particle size is a significant factor affecting foam formation and stability. Foam prepared by 3 different size particles indicates that foam formability and stability decrease with increasing of particle size. It is hypothesized that the decrease in the foam formation and stability is related to the particle gravity. Finally, experiments about reservoir conditions like high temperature and salinity were also conducted. It shows that increasing temperature will accelerate the velocity of foam decay and the increase of calcium chloride concentration help to stabilize foam while sodium chloride has an optimum concentration for foam stability.
Foam has proved to be effective and economical in underbalanced operations and is gaining wider applications in many areas. Foam fluid has low density and high blocking ability. It can effectively reduce leaking of fluid into formation in low-pressure wells, protecting the oil formation and improving sand-cleanout efficiency. According to energy-conservation equations, mass-conservation equations, and momentum-conservation equations, a mathematical model for sand cleanout with foam fluid was established that considers the heat transfer between foam in the annulus and foam in the tubing. The model was solved by numerical method. Distributions of foam temperature, foam density, foam quality, pressure, and foam velocity in the wellbore were obtained. Calculation results show that temperature distribution is affected greatly by thermal gradient. As the well depth increases, foam pressure and foam density increase and foam quality and velocity decrease. Foam velocity at the well bottomhole is the minimum. Friction pressure loss of foam is less than that of water at the same volume flow rate. Site applications show that sand cleanout with foam fluid can prevent fluid leakage effectively. It can avoid damage of sealing agents and reduce pollution. The average relative error and standard deviation between model and field data on injection pressure are -0.43 and 2.55%, respectively, which proves the validation of the mathematical model.
Foam diversion can effectively solve the problem that acid distribution among layers of different permeability is uneven during matrix acidizing. Based on gas trapping theory and mass conservation equation, mathematical models for foam slug diversion acidizing and foamed acid diversion acidizing were established. Design method for foam slug diversion acidizing was given. The mathematical models were solved by computer program. The results show that total formation skin factor, and pressure of wellhead and bottomhole increase with foam injection, and decrease with acid injection. Volume flow rate of high-permeability layer decreases, and that of low-permeability layer increases during foam injection, which can divert subsequent acid to low-permeability layer from high-permeability layer. Under the same formation situation, the effect of foamed acid diversion acidizing is better than foam slug diversion acidizing. In foamed acid diversion acidizing process, operation time is longer, and pressure of wellhead and bottomhole is higher. Field application shows that foam slug diversion acidizing can effectively block high permeability layer, and improve intake profile obviously. It is fit to acidizing for heterogenous formation.
Key words: foam slug, foamed acid, diversion, acidizing, heterogenous, mathematical model
Wang, Yuan (U. of Calgary) | Kantzas, Apostolos (U. of Calgary) | Li, Binfei (University of Petroleum) | Li, Zhaomin (China University of Petroleum) | Wang, Qing (Dongxin Oil Company, Shengli Oil Branch, SINOPEC) | Zhao, Mingchen (Dongxin Oil Company, Shengli Oil Branch, SINOPEC)
Migration of formation fines has been shown to cause production decline in many wells, especially for sand production wells in heavy oil reservoir. Filter cakes in wire wrapped liner, which were formed by the attachment of viscous crude oil blended with formation fines, may block the flow paths of viscous oil. The solution to this problem is appropriate treatment to mitigate this type of formation damage.
In this paper the performance at laboratory-scale of a new type of agent for formation damage mitigation is presented and some guidelines for its application including the injected pore volume and injection concentration are provided.
The mechanism for damage mitigation with this type of agent in heavy oil reservoir was introduced in detail, it mainly include that this type of agent can reduce interfacial tension between crude oil and water and change the wettability of rock surface, which may lead to the breakaway of resins and asphaltenes attached to the rock surface.
By simulation experiments and core flood tests the effectiveness of this type of agent to mitigate the damage in heavy oil reservoir was identified. Simulation experiment results show that, damage mitigation in cores with the permeability higher than 1µm2, is more effective than those with the permeability lower than 1µm2, and core flood experiment results also indicate that this type of agent with the concentration of higher than 5% can remarkably increase recovery factor for cores with the permeability higher than 1µm2. Finally some results on the behaviour of its application in heavy oil reservoir are presented.
At present, treatment of oil and gas wells with chemicals and biological enzymes are widely practiced to stimulate the production rate of the wells (Harold, 2003, McRae, 2004, M.A. Siddiqui, 2003, M.B. Al-Otaibi, 2004), principally through the removal of production related damages or by increasing the permeability or conductivity of the rock matrix with natural or induced fracture. Also some chemical agents produced by enzymes in oil or gas well can increase water injection, and control water cut (e.g., water shut-off and profile adjustment) as well as sands. Biological enzyme, a new type and efficient plug-removal agent, shows good application results in such countries as Venezuela and Indonesia, etc. Also very good results have been obtained in wells in China (Qin, 2002).
The enzyme used in this research possesses following superiorities (Qin, 2002, RadEx Technology):