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.

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.

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 Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiang Li ◽  
Yuan Cheng ◽  
Wulong Tao ◽  
Shalake Sarulicaoketi ◽  
Xuhui Ji ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

Using Transient Inflow Performance Relationships to Model the Dynamic Interaction Between Reservoir and Wellbore During Pressure Testing

2007 ◽  
Author(s):  
Aldo Costantini ◽  
Gioia Falcone ◽  
Geoffrey F. Hewitt ◽  
Claudio Alimonti
Keyword(s):  
Multiphase Flow ◽  
Flow Rate ◽  
Dynamic Interaction ◽  
Published Data ◽  
Preliminary Evaluation ◽  
Well Test ◽  
Set Up ◽  
Inflow Performance ◽  
Transient Multiphase Flow ◽  
Bottomhole Pressure

The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPR’s), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behaviour in the well. Steady-state IPR’s are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. Transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at surface and the bottomhole pressure is measured. Pressure build-up (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g. phase change, flow reversal and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artefacts. This paper introduces a method to derive the transient IPR’s at bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial co-ordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps and bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental set-up was carried out. The set-up would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region and the well, represented by a pressured vessel, a cylindrical porous medium and a vertical pipe, respectively.

The Sensitivity Analysis of Wellbore Heat Transfer during the CO2 Injection Process

2014 ◽  
Vol 889-890 ◽  
pp. 1638-1643
Author(s):  
Yi Zhang ◽  
Tong Tong Li ◽  
Yong Chen Song ◽  
Duo Li ◽  
Yang Chun Zhan ◽  
...  
Keyword(s):  
Heat Transfer ◽  
Carbon Dioxide ◽  
Sensitivity Analysis ◽  
Flow Rate ◽  
Injection Pressure ◽  
Simulation Method ◽  
Injection Process ◽  
Injection Flow ◽  
Injection Temperature ◽  
Thomson Coefficient

The sensitivity analysis of wellbore heat transfer during the CO2injection process is of vital importance to Carbon dioxide utilization and sequestration (CCUS). A numerical simulation method is developed to simulate the process of wellbore heat transfer during injecting carbon dioxide by amending the classical heat transfer modelRamey models. It analyses how the selected parameters affect the distribution of the wellbore temperature and pressure, which include CO2injection temperature, pressure and density, the injection flow rate and Joule Thomson coefficient. The results show that, CO2injection temperature has greater impact on the initial level of the temperature distribution; higher injection pressure raises the temperature mainly because of the effect of Joule Thomson coefficient; also, when the injection process lasts a longer time, the distribution is much more stable. When the injection flow rate is higher, the strata temperature has less influence on the flow temperature. The injection pressure and density has very appreciable effect on the pressure distribution. However, the other parameters have less influence on it. The modified simulation method was applied in Jiangsu Caoshe oil field and the simulation results coincided with the measuring data well.

Using Transient Inflow Performance Relationships to Model the Dynamic Interaction Between Reservoir and Wellbore During Pressure Testing

2008 ◽  
Vol 130 (4) ◽  
Author(s):  
Aldo Costantini ◽  
Gioia Falcone ◽  
Geoffrey F. Hewitt ◽  
Claudio Alimonti
Keyword(s):  
Multiphase Flow ◽  
Flow Rate ◽  
Flow Behavior ◽  
Dynamic Interaction ◽  
Published Data ◽  
Preliminary Evaluation ◽  
Well Test ◽  
Inflow Performance ◽  
Transient Multiphase Flow ◽  
Bottomhole Pressure

The fundamental understanding of the dynamic interactions between multiphase flow in the reservoir and that in the wellbore remains surprisingly weak. The classical way of dealing with these interactions is via inflow performance relationships (IPRs), where the inflow from the reservoir is related to the pressure at the bottom of the well, which is a function of the multiphase flow behavior in the well. A steady-state IPRs are normally adopted, but their use may be erroneous when transient multiphase flow conditions occur. The transient multiphase flow in the wellbore causes problems in well test interpretation when the well is shut-in at the surface and the bottomhole pressure is measured. The pressure buildup (PBU) data recorded during a test can be dominated by transient wellbore effects (e.g., phase change, flow reversal, and re-entry of the denser phase into the producing zone), making it difficult to distinguish between true reservoir features and transient wellbore artifacts. This paper introduces a method to derive the transient IPRs at bottomhole conditions in order to link the wellbore to the reservoir during PBU. A commercial numerical simulator was used to build a simplified reservoir model (single well, radial coordinates, homogeneous rock properties) using published data from a gas condensate field in the North Sea. In order to exclude wellbore effects from the investigation of the transient inflow from the reservoir, the simulation of the wellbore was omitted from the model. Rather than the traditional flow rate at surface conditions, bottomhole pressure was imposed to constrain the simulation. This procedure allowed the flow rate at the sand face to be different from zero during the early times of the PBU, even if the surface flow rate is equal to zero. As a result, a transient IPR at bottomhole conditions was obtained for the given field case and for a specific set of time intervals, time steps, and bottomhole pressure. In order to validate the above simulation approach, a preliminary evaluation of the required experimental setup was carried out. The setup would allow the investigation of the dynamic interaction between the reservoir, the near-wellbore region, and the well, represented by a pressured vessel, a cylindrical porous medium, and a vertical pipe, respectively.

Evaluation of Processing Effects in Injection Molded Thermoplastics Using Excimer Laser

2004 ◽  
Author(s):  
E. Sancaktar ◽  
N. Negandhi ◽  
S. Adwani
Keyword(s):  
Weight Loss ◽  
Laser Ablation ◽  
Flow Rate ◽  
Annealing Time ◽  
Injection Pressure ◽  
Mold Temperature ◽  
Injection Flow Rate ◽  
Injection Flow ◽  
Injection Molded ◽  
Processing Effects

The ablation behavior of amorphous (polystyrene (PS), and polycarbonate (PC)) and crystalline (poly(ethylene terephthalate) (PET), and glass filled poly(butylenes terephthalate) (PBT)) polymers by 248 nm KrF excimer laser irradiation were investigated for different injection molding conditions namely, injection flow rate, injection pressure, and mold temperature, as a possible method to evaluate the processing effects in the specimens. For this purpose, dumb-bell shaped samples were injection molded at different sets of processing conditions, and weight loss measurements were carried out for the different injection molding conditions. Some of the crystalline (PET) samples were annealed at different annealing time and temperature. For PET, weight loss decreased with increasing mold temperature and remained insensitive to injection flow rate. Annealing time and temperature significantly reduced weight loss in PET. For PBT, the weight loss due to laser ablation reduced with increase in material packing due to pressure, and also showed some sensitivity to flow rate variation. The major effect was seen with glass filled PBT samples. The weight loss decreased drastically with increasing glass fiber content. Laser ablation allowed observation of process induced fiber orientation by SEM in PBT samples. For PS and PC, the weight loss increased with increases in the injection flow rate and mold temperature, and decreased with increasing injection pressure. Position near the gate showed higher ablation than the position at the end for all the conditions. A decrease in the material orientation, with injection speed and mold temperature, led to increase in the weight loss, while increase in the injection pressure, and consequently orientation, led to lower weight loss for PS and PC. Higher residual stress samples showed higher weight loss.

scholarly journals Evaluating Reservoir Risks and Their Influencing Factors during CO2 Injection into Multilayered Reservoirs

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-14 ◽  
Author(s):  
Lu Shi ◽  
Bing Bai ◽  
Haiqing Wu ◽  
Xiaochun Li
Keyword(s):  
Flow Rate ◽  
Risk Evaluation ◽  
Carbon Capture ◽  
Lower Layer ◽  
Carbon Capture And Storage ◽  
Injection Pressure ◽  
Co2 Injection ◽  
Rate Distribution ◽  
Injection Flow ◽  
And Storage

Wellbore and site safety must be ensured during CO2 injection into multiple reservoirs during carbon capture and storage projects. This study focuses on multireservoir injection and investigates the characteristics of the flow-rate distribution and reservoir-risk evaluation as well as their unique influences on multireservoir injection. The results show that more CO2 enters the upper layers than the lower layers. With the increase in injection pressure, the risks of the upper reservoirs increase more dramatically than those of the low reservoirs, which can cause the critical reservoir (CR) to shift. The CO2 injection temperature has a similar effect on the injection flow rate but no effect on the CR’s location. Despite having no effect on the flow-rate distribution, the formation-fracturing pressures in the reservoirs determine which layer becomes the CR. As the thickness or permeability of a layer increases, the inflows exhibit upward and downward trends in this layer and the lower layers, respectively, whereas the inflows of the upper layers remain unchanged; meanwhile, the risks of the lower layer and those of the others decrease and remain constant, respectively. Compared to other parameters, the reservoir porosities have a negligible effect on the reservoir risks and flow-rate distributions.

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.

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