Propagation and Retention of Viscoelastic Surfactants Following Matrix-Acidizing Treatments in Carbonate Cores

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 993-1001 ◽  
Author(s):  
M.. Yu ◽  
M.A.. A. Mahmoud ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Flow Rate ◽  
Injection Rate ◽  
Low Flow ◽  
Gas Wells ◽  
The Core ◽  
Injection Flow ◽  
Carbonate Cores ◽  
Glycol Monobutyl Ether ◽  
Viscoelastic Surfactants ◽  
Viscoelastic Surfactant

Summary Viscoelastic surfactants have been used extensively in the field. They have the ability to form long rod-like micelles with an increase in pH and calcium concentration, which results in increasing the viscosity and elasticity of partially spent acids. There is ongoing debate in the industry about whether the gel generated by these surfactants causes formation damage, especially in dry-gas wells. The objectives of the present study are to quantitatively determine surfactant retention in calcite cores and assess the benefits of using mutual solvents to break the surfactant gel formed inside the cores. Coreflood tests were performed using Pink Desert limestone cores (1.5 in. in diameter and 20 in. in length). The cores were injected with a surfactant-based acid that contained 15 wt% HCl, 7 vol% viscoelastic surfactant, and 0.3 vol% corrosion inhibitor. Coreflood tests were conducted at a constant injection flow rate ranging from 1.5 to 40 cm3/min. Surfactant and calcium concentrations were measured in the injected acid and core effluent. Mutual solvent (ethylene glycol monobutyl ether) was used in several tests to break surfactant gel. Propagation of viscoelastic surfactants in linear calcite cores was found to be a function of flow rate. Surfactant lagged calcium in the core effluent samples, especially at low flow rates. The volume of acid needed to break through the core and the amount of surfactant retained varied with acid injection rate, and exhibited a minimum at 10 cm3/min. A significant amount of surfactant was retained in the cores. Injection of 2 pore volumes (PV) of 10 vol% mutual solvent removed only 20% of the surfactant injected. Based on these results, there is a need to use internal breakers when surfactant-based acids are used in dry-gas wells or water injectors.

Unloading Frac Hits in Gas Wells: How Does the Nitrogen Injection Rate and Pressure Affect the Unloading Process?

2021 ◽  
Author(s):  
Miguel Angel Cedeno
Keyword(s):  
Multiphase Flow ◽  
Flow Rate ◽  
Injection Pressure ◽  
Injection Rate ◽  
Gas Wells ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Nitrogen Injection ◽  
Injection Flow ◽  
Transient Multiphase Flow

Abstract The unconventional resources development has grown tremendously as a result of the advancement in horizontal drilling technology coupled with hydraulic fracturing. However, as more wells are drilled and fractured close to each other, frac hits have become a major challenge in these wells. The aim of this work is to investigate the effect of nitrogen injection flow rate and pressure on unloading frac hits gas wells in transient multiphase flow. A numerical simulation model was created using a transient multiphase flow simulator to mimic the unloading process of frac hits by injecting nitrogen from the surface through the annulus section of the well. Many simulation cases were created and analyzed to comprehend the effect of the nitrogen injection rate and pressure on the unloading of frac hits. The model mimicked real field data from currently active well in the Eagle Ford Shale. The results showed that as the nitrogen injection pressure increases, the nitrogen volume and the time to unload the frac hits decrease. On the other hand, increasing the injection rate of nitrogen will increase the nitrogen volume required to unload the frac hits. In addition, the time to unload frac hits will be decreased as the nitrogen injection rate increases. These results indicate that the time required to unload frac hits will be minimized if higher flow rates of nitrogen were utilized. Nonetheless, the volume of nitrogen required to unload the frac hits will be maximized. An important observation to highlight is that the operators can save money by reducing the time for injecting nitrogen. This observation was verified when increasing the injection pressure in the frac hit well in the Eagle Ford Shale, the time of injection was reduced 20%. This study presents the effects of nitrogen injection flow rate and injection pressure for unloading frac hits in gas wells. Due to the lack of published studies about this topic, this work can serve as a practical guideline for unloading frac hits in gas wells.

scholarly journals Expanded Microchannel Heat Exchanger: Finite Difference Modeling

Designs ◽  
2021 ◽  
Vol 5 (4) ◽  
pp. 58
Author(s):  
David Denkenberger ◽  
Joshua M. Pearce ◽  
Michael Brandemuehl ◽  
Mitchell Alverts ◽  
John Zhai
Keyword(s):  
Heat Transfer ◽  
Heat Exchanger ◽  
Finite Difference ◽  
Flow Rate ◽  
Experimental Results ◽  
Low Flow ◽  
Difference Model ◽  
The Core ◽  
Finite Difference Model ◽  
Flow Maldistribution

A finite difference model of a heat exchanger (HX) considered maldistribution, axial conduction, heat leak, and the edge effect, all of which are needed to model a high effectiveness HX. An HX prototype was developed, and channel height data were obtained using a computerized tomography (CT) scan from previous work along with experimental results. This study used the core geometry data to model results with the finite difference model, and compared the modeled and experimental results to help improve the expanded microchannel HX (EMHX) prototype design. The root mean square (RMS) error was 3.8%. Manifold geometries were not put into the model because the data were not available, so impacts of the manifold were investigated by varying the temperature conditions at the inlet and exit of the core. Previous studies have not considered the influence of heat transfer in the manifold on the HX effectiveness when maldistribution is present. With no flow maldistribution, manifold heat transfer increases overall effectiveness roughly as would be expected by the greater heat transfer area in the manifolds. Manifold heat transfer coupled with flow maldistribution for the prototype, however, causes a decrease in the effectiveness at high flow rate, and an increase in effectiveness at low flow rate.

scholarly journals Characterization of venturi injector using dimensional analysis

2019 ◽  
Vol 23 (7) ◽  
pp. 484-491 ◽  
Author(s):  
Luiz R. Sobenko ◽  
José A. Frizzone ◽  
Antonio P. de Camargo ◽  
Ezequiel Saretta ◽  
Hermes S. da Rocha
Keyword(s):  
Dimensional Analysis ◽  
Flow Rate ◽  
Injection Rate ◽  
Operating Conditions ◽  
Functional Tests ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Hydraulic Conditions ◽  
Fluid Properties ◽  
Pi Theorem

ABSTRACT Venturi injectors are commonly employed for fertigation purposes in agriculture, in which they draw fertilizer from a tank into the irrigation pipeline. The knowledge of the amount of liquid injected by this device is used to ensure an adequate fertigation operation and management. The objectives of this research were (1) to carry out functional tests of Venturi injectors following requirements stated by ISO 15873; and (2) to model the injection rate using dimensional analysis by the Buckingham Pi theorem. Four models of Venturi injectors were submitted to functional tests using clean water as motive and injected fluid. A general model for predicting injection flow rate was proposed and validated. In this model, the injection flow rate depends on the fluid properties, operating hydraulic conditions and geometrical characteristics of the Venturi injector. Another model for estimating motive flow rate as a function of inlet pressure and differential pressure was adjusted and validated for each size of Venturi injector. Finally, an example of an application was presented. The Venturi injector size was selected to fulfill the requirements of the application and the operating conditions were estimated using the proposed models.

scholarly journals Influence of mineralization and injection flow rate on flow patterns in three-dimensional porous media

2019 ◽  
Vol 21 (27) ◽  
pp. 14605-14611 ◽  
Author(s):  
R. Moosavi ◽  
A. Kumar ◽  
A. De Wit ◽  
M. Schröter
Keyword(s):  
Porous Media ◽  
Flow Field ◽  
Flow Rate ◽  
Three Dimensional ◽  
Flow Patterns ◽  
Low Flow ◽  
Flow Rates ◽  
Injection Flow Rate ◽  
Injection Flow

At low flow rates, the precipitate forming at the miscible interface between two reactive solutions guides the evolution of the flow field.

Experimental Analysis of CO2 Injection on Permeability of Vuggy Carbonate Aquifers

2012 ◽  
Vol 135 (1) ◽  
Author(s):  
Ibrahim M. Mohamed ◽  
Jia He ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Flow Rate ◽  
Initial Permeability ◽  
Co2 Injection ◽  
Reaction Products ◽  
The Core ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Injection Scheme ◽  
Core Permeability ◽  
Permeability Alteration

Reactions of CO2 with formation rock may lead to an enhancement in the permeability due to rock dissolution, or damage (reduction in the core permeability) because of the precipitation of reaction products. The reaction is affected by aquifer conditions (pressure, temperature, initial porosity, and permeability), and the injection scheme (injection flow rate, CO2:brine volumetric ratio, and the injection time). The effects of temperature, injection flow rate, and injection scheme on the permeability alteration due to CO2 injection into heterogeneous dolomite rock is addressed experimentally in this paper. Twenty coreflood tests were conducted using Silurian dolomite cores. Thirty pore volumes of CO2 and brine were injected in water alternating gas (WAG) scheme under supercritical conditions at temperatures ranging from 21 to 121 °C, and injection rates of 2.0–5.0 cm3/min. Concentrations of Ca++, Mg++, and Na+ were measured in the core effluent samples. Permeability alteration was evaluated by measuring the permeability of the cores before and after the experiment. Two sources of damage in permeability were noted in this study: (1) due to precipitation of calcium carbonate, and (2) due to migration of clay minerals present in the core. Temperature and injection scheme don't have a clear impact on the core permeability. A good correlation between the initial and final core permeability was noted, and the ratio of final permeability to the initial permeability is lower for low permeability cores.

Acid Diversion by Use of Viscoelastic Surfactants: The Effects of Flow Rate and Initial Permeability Contrast

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1203-1216 ◽  
Author(s):  
A.H.. H. Al-Ghamdi ◽  
M.A.. A. Mahmoud ◽  
G.. Wang ◽  
A.D.. D. Hill ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Flow Rate ◽  
Critical Parameter ◽  
Initial Permeability ◽  
Injection Rate ◽  
Large Set ◽  
Treatment Needs ◽  
Permeability Ratio ◽  
Acid Injection ◽  
Viscoelastic Surfactant ◽  
Injection Rates

Summary The purpose of matrix stimulation in carbonate reservoirs is to bypass damaged areas and increase the effective wellbore area. This can be achieved by creating highly conductive flow channels known as wormholes. A further injection of the acid will follow a wormhole path where the permeability has increased significantly, leaving substantial intervals untreated. This problem can be more significant as the contrast in permeability increases within the target zones. Diverting materials, such as viscoelastic-surfactant (VES) -based acids, play an important role in mitigating this problem. The acid-injection rate was found to be a critical parameter to maximize the efficiency of the use of VES-based acids as a diverting chemical in addition to creating wormholes. It was found that the maximum apparent viscosity, which developed during VES-based-acids injection, occurred over a narrow window of acid-injection rates. Higher injection rates were not effective in enhancing the acidizing process, and the use of diverting material became similar in effect to that of regular acids. The use of VES-based acid was also found to be constrained by the scale of the initial permeability ratio. For initial permeability ratios greater than approximately 10, the diversion was insufficient. The results were obtained by conducting a large set of acidizing experiments by use of 20-in.-long cores. Both single- and parallel-coreflood experiments were performed in this study. Carbonate cores were used with initial permeabilities of 4–150 md, and the flow rate was varied from 1.5 to 50 cm3/min. The initial ratio of permeability between the two cores ranged from 2 to 15. To characterize the wormholes, computerized tomography (CT) was used to generate a 3D view of the wormholes in each core. By use of the results obtained from single cores, the acid-injection rate was found to be a critical parameter in maximizing the efficiency of the use of VES as a diverting agent during matrix-acidizing treatments. Higher injection rates were not effective in enhancing the acidizing process, and the use of diverting material produced results similar to those of regular hydrochloric acid (HCl). Parallel-coreflood experiments indicated that the use was found to be constrained by the scale of the initial permeability ratio. For initial permeability ratios greater than approximately 10, diversion was insufficient in 20-in. coreflood tests. For permeability ratios greater than 10, the acid-placement treatment needs to be designed more carefully.

Interrelationship of Capillary Number, Interfacial Tension, Injection Flow Rate and Temperature by Surfactant Flooding for Oil-wet Carbonate Reservoirs

2021 ◽  
Author(s):  
Xianmin Zhou ◽  
Ridha Al-Abdrabalnabi ◽  
Sarmad Zafar Khan ◽  
Muhammad Shahzad Kamal
Keyword(s):  
Interfacial Tension ◽  
Flow Rate ◽  
Capillary Number ◽  
Injection Rate ◽  
Carbonate Reservoirs ◽  
Surfactant Flooding ◽  
Oil Saturation ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Remaining Oil

Abstract After water flooding in carbonate reservoirs, a significant fraction of the original oil as remaining oil is left in the swept zone. The remaining oil in the pore, trapped by viscous and capillary forces, is to target for improved and enhanced oil recovery. The mobilization of remaining oil can be predicted by a dimensionless parameter called capillary number. The interfacial tension and injection flow rate strongly affect the capillary number. Unfortunately, the interrelationship between capillary number, interfacial tension, injection flow rate, and the temperature has been poorly studied for carbonate reservoirs. This paper focuses on studying the remaining oil saturations at different orders of magnitude capillary numbers related to interfacial tension, injection flow rate, and temperature by seawater and surfactant flooding. Several core flooding experiments were performed by changing the injection rate and surfactant concentrations at evaluated conditions. Four displacement experiments of seawater/oil and surfactant solution/oil were performed using oil-wet carbonate cores to obtain the relationship between the residual oil saturation vs. the capillary number. The surfactant flooding experiments with different concentrations of 0.01 and 0.2 wt% were conducted when the remaining oil saturation was reached after water flooding. Three core flooding experiments were conducted at ambient conditions, and one was under evaluated conditions of a temperature of 100° and pore pressure of 3200 psi. Several injection rates were selected to experiment with a 0.2 wt% surfactant solution, which is to study the effect of injection rate on the capillary number and residual oil saturation. The experimental findings show that some remaining oil can be recovered from oil-wet carbonate cores if the capillary number increases by a critical Nc =2.1E-05 by surfactant flooding at reservoir conditions. After water flooding, the remaining oil saturation was decreased from 51% to 16% with 0.01wt% surfactant flooding. The reduction of interfacial tension from 6.77dyne/cm to 0.017dyne/cm led to an increased capillary number. It decreased the remaining oil saturation by about 5% OOIP when the capillary number increases three magnitudes. The effect of temperature and injection rate on the capillary number was observed based on experimental displacement results. Compared with results between the ambient and specified conditions, the effect of temperature on the capillary number is significant. Under the same capillary number, the remaining oil recovered by surfactant flooding at HPHT conditions was higher than that at ambient conditions. Also, the effect of the injection flow rate on the capillary number was observed by 0.2wt % surfactant flooding for all experiments. The capillary number increased with an increase in the injection rate for both ambient and evaluated conditions. This paper provides valuable results to evaluate the interrelationship between remaining oil and capillary numbers by surfactant flooding and design field application for oil-wet carbonate reservoirs.

scholarly journals Backflow effects on mass flow gain factor in a centrifugal pump

2021 ◽  
Vol 104 (2) ◽  
pp. 003685042199886
Author(s):  
Wenzhe Kang ◽  
Lingjiu Zhou ◽  
Dianhai Liu ◽  
Zhengwei Wang
Keyword(s):  
Centrifugal Pump ◽  
Mass Flow ◽  
Flow Rate ◽  
Low Frequency ◽  
Gain Factor ◽  
Low Flow ◽  
Cavity Volume ◽  
Cavitating Flows ◽  
Inlet Tube ◽  
Low Flow Rate

Previous researches has shown that inlet backflow may occur in a centrifugal pump when running at low-flow-rate conditions and have nonnegligible effects on cavitation behaviors (e.g. mass flow gain factor) and cavitation stability (e.g. cavitation surge). To analyze the influences of backflow in impeller inlet, comparative studies of cavitating flows are carried out for two typical centrifugal pumps. A series of computational fluid dynamics (CFD) simulations were carried out for the cavitating flows in two pumps, based on the RANS (Reynolds-Averaged Naiver-Stokes) solver with the turbulence model of k- ω shear stress transport and homogeneous multiphase model. The cavity volume in Pump A (with less reversed flow in impeller inlet) decreases with the decreasing of flow rate, while the cavity volume in Pump B (with obvious inlet backflow) reach the minimum values at δ = 0.1285 and then increase as the flow rate decreases. For Pump A, the mass flow gain factors are negative and the absolute values increase with the decrease of cavitation number for all calculation conditions. For Pump B, the mass flow gain factors are negative for most conditions but positive for some conditions with low flow rate coefficients and low cavitation numbers, reaching the minimum value at condition of σ = 0.151 for most cases. The development of backflow in impeller inlet is found to be the essential reason for the great differences. For Pump B, the strong shearing between backflow and main flow lead to the cavitation in inlet tube. The cavity volume in the impeller decreases while that in the inlet tube increases with the decreasing of flow rate, which make the total cavity volume reaches the minimum value at δ = 0.1285 and then the mass flow gain factor become positive. Through the transient calculations for cavitating flows in two pumps, low-frequency fluctuations of pressure and flow rate are found in Pump B at some off-designed conditions (e.g. δ = 0.107, σ = 0.195). The relations among inlet pressure, inlet flow rate, cavity volume, and backflow are analyzed in detail to understand the periodic evolution of low-frequency fluctuations. Backflow is found to be the main reason which cause the positive value of mass flow gain factor at low-flow-rate conditions. Through the transient simulations of cavitating flow, backflow is considered as an important aspect closely related to the hydraulic stability of cavitating pumping system.

scholarly journals Research progress of viscoelastic surfactants for enhanced oil recovery

2021 ◽  
pp. 014459872098020
Author(s):  
Ruizhi Hu ◽  
Shanfa Tang ◽  
Musa Mpelwa ◽  
Zhaowen Jiang ◽  
Shuyun Feng
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
High Efficiency ◽  
Research Progress ◽  
Surfactant Flooding ◽  
Sweep Efficiency ◽  
The World ◽  
Washing Efficiency ◽  
Viscoelastic Surfactants ◽  
Viscoelastic Surfactant

Although new energy has been widely used in our lives, oil is still one of the main energy sources in the world. After the application of traditional oil recovery methods, there are still a large number of oil layers that have not been exploited, and there is still a need to further increase oil recovery to meet the urgent need for oil in the world economic development. Chemically enhanced oil recovery (CEOR) is considered to be a kind of effective enhanced oil recovery technology, which has achieved good results in the field, but these technologies cannot simultaneously effectively improve oil sweep efficiency, oil washing efficiency, good injectability, and reservoir environment adaptability. Viscoelastic surfactants (VES) have unique micelle structure and aggregation behavior, high efficiency in reducing the interfacial tension of oil and water, and the most important and unique viscoelasticity, etc., which has attracted the attention of academics and field experts and introduced into the technical research of enhanced oil recovery. In this paper, the mechanism and research status of viscoelastic surfactant flooding are discussed in detail and focused, and the results of viscoelastic surfactant flooding experiments under different conditions are summarized. Finally, the problems to be solved by viscoelastic surfactant flooding are introduced, and the countermeasures to solve the problems are put forward. This overview presents extensive information about viscoelastic surfactant flooding used for EOR, and is intended to help researchers and professionals in this field understand the current situation.

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