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.

Theoretical and Experimental Study on Optimal Injection Rates in Carbonate Acidizing

SPE Journal ◽  
2016 ◽  
Vol 22 (03) ◽  
pp. 892-901 ◽  
Author(s):  
Kai Dong ◽  
Ding Zhu ◽  
A. Daniel Hill
Keyword(s):  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Injection Rate ◽  
Experimental Results ◽  
Acid Injection ◽  
Optimal Injection ◽  
Mode Size ◽  
Interstitial Velocity ◽  
Injection Rates

Summary Optimal acid-injection rate is critical information for carbonate-matrix-acidizing design. This rate is currently obtained through fitting acidizing-coreflood experimental results. A model is needed to predict optimal acid-injection rates for various reservoir conditions. A wormhole forms when larger pores grow in the cross-sectional area at a rate that greatly exceeds the growth rate of smaller pores caused by surface reaction. This happens when the pore growth follows a particular mechanism, which is discussed in this paper. We have developed a model to predict wormhole-growth behavior. The model uses the mode size in a pore-size distribution—the pore size that appears most frequently in the distribution—to predict the growth of the pore. By controlling the acid velocity inside of it, we can make this particular pore grow much faster than other smaller pores, thus reaching the most-favorable condition for wormholing. This also results in a balance between overall acid/rock reaction and acid flow. With the introduction of a porous-medium model, the acid velocity in the mode-size pore is scaled up to the interstitial velocity at the wormhole tip. This interstitial velocity at the wormhole tip controls the wormhole propagation. The optimal acid-injection rates are then calculated by use of semiempirical flow correlations for different flow geometries. The optimal injection rate depends on the rock lithology, acid concentration, temperature, and rock-pore-size distribution. All these factors are accounted for in this model. The model can predict the optimal rates of acidizing-coreflood experiments correctly, compared with our acidizing-coreflood experimental results. In addition, on the basis of our model, it is also found that at optimal conditions, the wormhole-propagation velocity is linearly proportional to the acid-diffusion coefficient for a diffusion-limited reaction. This is proved both experimentally and theoretically in this study. Because there is no flow-geometry constraint while developing this model, it can be applied to field scales. Applications are presented in this paper.

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.

New Insights on the Effect of Oil Saturation on the Optimal Acid-Injection Rate in Carbonate Acidizing

SPE Journal ◽  
2017 ◽  
Vol 23 (03) ◽  
pp. 969-984 ◽  
Author(s):  
Rahul Kumar ◽  
Jia He ◽  
Mohammed Bataweel ◽  
Hisham Nasr-El-Din
Keyword(s):  
Inductively Coupled Plasma ◽  
Optical Emission ◽  
Injection Rate ◽  
Residual Oil ◽  
Oil Saturation ◽  
Acid Injection ◽  
Reservoir Conditions ◽  
Carbonate Acidizing ◽  
The Impact ◽  
Injection Rates

Summary The optimal injection rate for wormhole propagation and face dissolution at low injection rates during carbonate matrix acidizing is well-established. However, little research is documented on the subject of how the presence of oil affects this process. This study demonstrates the impact of oil saturation on wormhole characteristics while acidizing reservoir and outcrop cores under reservoir conditions (200°F). Coreflood experiments at flow rates ranging from 0.5 to 20 cm3/min were performed to determine the optimal acid-injection rate for wormhole propagation when acidizing homogeneous limestone reservoir cores, low-permeability Indiana limestone cores, and homogeneous dolomite cores with dimensions of a 3- and 6-in. length and a 1.5-in. diameter. The experimental work involved acidizing cores saturated with water, oil, and waterflood residual oil by use of 15-wt% regular hydrochloric acid (HCl). The viscosity of the crude oil used was 3.8 cp at 200°F. Computed-chromatography (CT) scans enabled the characterization of wormholes through the cores. The concentrations of the calcium and magnesium ions in core effluent samples were measured with inductively coupled plasma optical emission spectroscopy (ICP-OES), and the effluent samples were titrated to determine the concentration of the acid. At injection rates of 0.5 to 20 cm3/min, 15-wt% HCl was effective in creating wormholes with minimal branches for cores with residual oil saturation (ROS). Compared with brine- and oil-saturated cores, those at ROS took less acid volume to breakthrough. In addition, the efficiency of regular acid improved with increased acid-injection rates in the presence of residual oil. A decrease in the acid pore volume (PV) to breakthrough for oil-saturated cores was observed at high acid-injection rates, which could be attributed to viscous fingering of acid through oil. Unlike brine-saturated and oil-saturated cores, cores at ROS showed no face dissolution at low acid-injection rates. The conclusions of this work highlight the impact of oil saturation on matrix characteristics while acidizing carbonate rocks.

CALCULATION OF OPTIMAL INJECTION RATE FOR DISPERSED WATERFLOODING SYSTEM

2017 ◽  
pp. 63-67
Author(s):  
L. A. Vaganov ◽  
A. Yu. Sencov ◽  
A. A. Ankudinov ◽  
N. S. Polyakova
Keyword(s):  
Injection Rate ◽  
Oil Field ◽  
Injection Well ◽  
Water Migration ◽  
Mutual Location ◽  
Optimal Injection ◽  
Technical Measures ◽  
Injection Rates

The article presents a description of the settlement method of necessary injection rates calculation, which is depended on the injected water migration into the surrounding wells and their mutual location. On the basis of the settlement method the targeted program of geological and technical measures for regulating the work of the injection well stock was created and implemented by the example of the BV7 formation of the Uzhno-Vyintoiskoe oil field.

scholarly journals Ball sealer tracking and seating of temporary plugging fracturing technology in the perforated casing of a horizontal well

2021 ◽  
pp. 014459872110204
Author(s):  
Wan Cheng ◽  
Chunhua Lu ◽  
Guanxiong Feng ◽  
Bo Xiao
Keyword(s):  
Critical Parameter ◽  
Fluid Velocity ◽  
Stable State ◽  
Horizontal Wells ◽  
Terminal Velocity ◽  
Injection Rate ◽  
Fracturing Fluid ◽  
Perforation Hole ◽  
Horizontal Wellbore ◽  
Tight Reservoirs

Multistaged temporary plugging fracturing in horizontal wells is an emerging technology to promote uniform fracture propagation in tight reservoirs by injecting ball sealers to plug higher-flux perforations. The seating mechanism and transportation of ball sealers remain poorly understood. In this paper, the sensitivities of the ball sealer density, casing injection rate and perforation angle to the seating behaviors are studied. In a vertical wellbore section, a ball sealer accelerates very fast at the beginning of the dropping and reaches a stable state within a few seconds. The terminal velocity of a non-buoyant ball is greater than the fluid velocity, while the terminal velocity of a buoyant ball is less than the fluid velocity. In the horizontal wellbore section, the terminal velocity of a non-buoyant or buoyant ball is less than the fracturing fluid flowing velocity. The ball sealer density is a more critical parameter than the casing injection rate when a ball sealer diverts to a perforation hole. The casing injection rate is a more critical parameter than the ball sealer density when a ball sealer seats on a perforation hole. A buoyant ball sealer associated with a high injection rate of fracturing fluid is highly recommended to improve the seating efficiency.

scholarly journals Capillary processes increase salt precipitation during CO2 injection in saline formations

2018 ◽  
Vol 852 ◽  
pp. 398-421
Author(s):  
Helena L. Kelly ◽  
Simon A. Mathias
Keyword(s):  
High Salinity ◽  
Volume Fraction ◽  
Injection Rate ◽  
Injection Well ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Injection Wells ◽  
Tenfold Increase ◽  
Entry Pressure ◽  
Injection Rates

An important attraction of saline formations for CO2 storage is that their high salinity renders their associated brine unlikely to be identified as a potential water resource in the future. However, high salinity can lead to dissolved salt precipitating around injection wells, resulting in loss of injectivity and well deterioration. Earlier numerical simulations have revealed that salt precipitation becomes more problematic at lower injection rates. This article presents a new similarity solution, which is used to study the relationship between capillary pressure and salt precipitation around CO2 injection wells in saline formations. Mathematical analysis reveals that the process is strongly controlled by a dimensionless capillary number, which represents the ratio of the CO2 injection rate to the product of the CO2 mobility and air-entry pressure of the porous medium. Low injection rates lead to low capillary numbers, which in turn are found to lead to large volume fractions of precipitated salt around the injection well. For one example studied, reducing the CO2 injection rate by 94 % led to a tenfold increase in the volume fraction of precipitated salt around the injection well.

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 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 Rheological characteristics of polyethylene-nanotube composites by capillary rheometry

2020 ◽  
Author(s):  
S Al-Baghdadi ◽  
A Al-Amiery
Keyword(s):  
Shear Rate ◽  
Flow Rate ◽  
Applied Load ◽  
Critical Parameter ◽  
Raw Materials ◽  
Rheological Characteristics ◽  
Capillary Rheometry ◽  
Solid Load ◽  
Nanotube Composites ◽  
Newtonian Behavior

Abstract The viscosity and flow rate as rheological characteristics are fundamental in evaluating the nanofillers in processing the polyethylene-nanotube (PE-NT) composite in injecting molding. The purpose of this investigation is to study the rheological conduct of PE-NT composite plastic feedstock through capillary rheometry. For the purpose of obtaining a flawless component, the feedstock is used as a critical parameter, and care must be taken while introducing the raw materials with high solid load and hence perfect flowability. The shear rate viscosity of different feedstocks at an NT ratio extending at 0–3 wt.% has been determined at L/D equal to 10 die and a load extending at 40.0–80.0 KGF at temperatures 140.0, 150.0 and 160.0°C. The three specimens’ viscosity was measured in order to exhibit that the corresponding flow conduct factor varies from 0.40 to 0.70, demonstrating the non-Newtonian behavior of the specimens. The three specimens’ activation energies at the studied temperature degrees were evaluated and turned out to be 36.5–69.88 kJ/mol according to the applied load.

scholarly journals Optimal injection rate of water in the Guide Basin hot dry rock mining project

2018 ◽  
Vol 37 (2) ◽  
pp. 721-735 ◽  
Author(s):  
Xiaoxue Yan ◽  
Yanguang Liu ◽  
Guiling Wang ◽  
Yaoru Lu
Keyword(s):  
Injection Rate ◽  
Heat Extraction ◽  
Qinghai Province ◽  
Hot Dry Rock ◽  
Rock Mining ◽  
Optimal Injection ◽  
Production Stages ◽  
Reservoir Simulator ◽  
Guide Basin ◽  
Injection Rates

The energy reserves of hot dry rock resources are huge, thus a model to predict engineering production for efficient and stable development and utilization is sought. Based on the geological characteristics of dry rock resources in Guide Basin, Qinghai Province, China, the fully coupled wellbore–reservoir simulator—T2Well—is used to model a production system using water as a heat transfer medium and simulate the system’s operation to analyze the influence of different injection rates on heat extraction. In later production stages, output temperature and reservoir pressure decrease by 10–30°C and 0.5–30 MPa, depending on injection rate; this occurs earlier and to a greater extent at higher injection rates; thermal breakthrough also occurs earlier (7–10 years). The heat extraction rate is 1–20 MW and the cumulative heat extracted is 2.1–24.2 × 105 J. Lower injection rates result in relatively low heat extraction rates. For maximum economic benefit, an injection rate of 50–75 kg/s is ideal.

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