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 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.

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.

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.

Migration and Storage Mechanisms of CO2 with Different Injection Rates

2012 ◽  
Vol 588-589 ◽  
pp. 15-20 ◽  
Author(s):  
Gao Fan Yue ◽  
Hai Long Tian ◽  
Tian Fu Xu ◽  
Fu Gang Wang
Keyword(s):  
Greenhouse Effect ◽  
Migration Velocity ◽  
Injection Rate ◽  
Injection Well ◽  
Geological Sequestration ◽  
Sequestration Of Co2 ◽  
And Storage ◽  
Injection Rates

Geological sequestration of CO2 in deep saline formations has been considered as an effective way to mitigate the greenhouse effect. With different rates of injection to a storage formation, the migration and storage mechanisms of CO2 are different. In this paper, we simulated the migration of CO2 based on a generic geological reservoir under simplified conditions. The results show that higher injection rate will lead to higher migration velocity and farther distance from the injection well, while it has no influence on dissolution amount when the total amounts of injected CO2 are equal.

scholarly journals Investigating the effects of fault reactivation and CO2 migration during combined CO2-EOR and sequestration within a mature oil reservoir

2020 ◽  
Vol 10 (8) ◽  
pp. 3827-3848
Author(s):  
Shawn Pulchan ◽  
David Alexander ◽  
Donnie Boodlal
Keyword(s):  
Injection Pressure ◽  
Injection Rate ◽  
Oil Field ◽  
Fault Reactivation ◽  
Combined Processes ◽  
Fracture Permeability ◽  
Propagation Length ◽  
Combined Process ◽  
Optimal Injection

Abstract The investigation into the combined processes of CO2-EOR and geologic carbon sequestration was seen to be a viable solution to reducing CO2 emissions from the atmosphere, while boosting production from mature oil fields. However, the practicality of the combined process hinges on the determination of an optimum injection pressure to maximize the application of both methods. In addition, the success of these two operations is also contingent upon the dynamic sealing capacity of bounding faults, to allow hydrocarbon accumulation and trapping of injected CO2. Consequentially, the goal of this research is to optimize the implementation of combined CO2-EOR with simultaneous CO2 sequestration and investigate the enhancing/diminishing aspects of fault reactivation and CO2 migration. The study was approached from two scenarios; the first was the determination of an optimum injection pressure for the combined process, with the main focus on maximizing recovery from a mature oil field. The results saw a maximum cumulative recovery of 73.7090 Mbbls being facilitated at an optimal injection rate of 722 Scf/day. The second scenario entailed the investigation of the occurrence or lack thereof, of injection-induced fault reactivation at this predetermined injection rate of 722 Scf/day. Simulations reflecting the characteristics of fault reactivation were conducted, and are indicative of relations between fault opening stress, reactivation time, hydraulic fracture permeability, fracture propagation length, and leakage. Conclusively, the viability of the combination of CO2-EOR and sequestration were seen to depend on the technicalities of fault reactivation. In some cases, reactivation resulted in increases of accessible storage capacity, whereas, in other instances, it led to the leakage of the injected CO2.

scholarly journals Investigations of Structural and Residual Trapping Phenomena during CO2 Sequestration in Deccan Volcanic Province of the Saurashtra Region, Gujarat

2021 ◽  
Vol 2021 ◽  
pp. 1-16
Author(s):  
Pradeep Reddy Punnam ◽  
Balaji Krishnamurthy ◽  
Vikranth Kumar Surasani
Keyword(s):  
Co2 Sequestration ◽  
Injection Rate ◽  
Deccan Traps ◽  
Deccan Volcanic Province ◽  
Residual Trapping ◽  
Optimal Injection ◽  
Simulation Results ◽  
Insight Into ◽  
Selection Of ◽  
Injection Rates

This work aims to study the structural and residual trapping mechanisms on the Deccan traps topography to elucidate the possible implementation of CO2 geological sequestration. This study provides an insight into a selection of stairsteps landscape from Deccan traps in the Saurashtra region, Gujarat, India. Various parameters affect the efficiency of the structural and residual trapping mechanisms. Thus, the parametric study is conducted on the modeled synthetic geological domain by considering the suitable injection points for varying injection rates and petrophysical properties. The outcomes of this study will provide insights into the dependencies of structural and residual trapping on the Deccan traps surface topography and injection rates. It can also establish a protocol for selecting the optimal injection points with the desired injection rate for the safe and efficient implementation of CO2 sequestration. The simulation results of this study have shown the dependencies of structural and residual trapping on the geological domain parameters.

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

Successful Development and Deployment of a Novel Chemical Package for Stimulation of Injection wells, Offshore UK

2021 ◽  
Author(s):  
Dennis Alexis ◽  
Gayani Pinnawala ◽  
Do Hoon Kim ◽  
Varadarajan Dwarakanath ◽  
Ruth Hahn ◽  
...  
Keyword(s):  
Product Quality ◽  
Injection Well ◽  
Concentrated Solutions ◽  
Successful Development ◽  
Injection Wells ◽  
Polymer Injection ◽  
Remediation Process ◽  
Field Location ◽  
Stimulation Of ◽  
Injection Rates

Abstract The work described in this paper details the development of a single stimulation package that was successfully used for treating an offshore horizontal polymer injection well to improve near wellbore injectivity in the Captain field, offshore UK. The practice was to pump these concentrated surfactant streams using multiple pumps from a stimulation vessel which is diluted with the polymer injection stream in the platform to be injected downhole. The operational challenges were maintaining steady injection rates of the different liquid streams which was exacerbated by the viscous nature of the concentrated surfactants that would require pre-dilution using cosolvent or heating the concentrated solutions before pumping to make them flowable. We have developed a single, concentrated liquid blend of surfactant, polymer and cosolvent that was used in near-wellbore remediation. This approach significantly simplifies the chemical remediation process in the field while also ensuring consistent product quality and efficiency. The developed single package is multiphase, multicomponent in nature that can be readily pumped. This blend was formulated based on the previous stimulation experience where concentrated surfactant packages were confirmed to work. Commercial blending of the single package was carried out based on lab scale to yard scale blending and dilution studies. About 420 MT of the blend was manufactured, stored, and transported by rail, road and offshore stimulation vessel to the field location and successfully injected.

Numerical simulation and optimization of CO2 enhanced gas recovery in homogeneous and vertical heterogeneous reservoir models

2021 ◽  
pp. 1-36
Author(s):  
Shuyang Liu ◽  
Ramesh Agarwal ◽  
Baojiang Sun
Keyword(s):  
Natural Gas ◽  
Injection Rate ◽  
Injection Time ◽  
Upward Migration ◽  
Enhanced Gas Recovery ◽  
Simulation And Optimization ◽  
Heterogeneous Reservoirs ◽  
Gas Recovery ◽  
Heterogeneous Reservoir ◽  
Optimal Injection

Abstract CO2 enhanced gas recovery (CO2-EGR) is a promising, environment-friendly technology with simultaneously sequestering CO2. The goals of this paper are to conduct simulations of CO2-EGR in both homogeneous and heterogeneous reservoirs to evaluate effects of gravity and reservoir heterogeneity, and to determine optimal CO2 injection time and injection rate for achieving better natural gas recovery by employing a genetic algorithm integrated with TOUGH2. The results show that gravity segregation retards upward migration of CO2 and promotes horizontal displacement efficiency, and the layers with low permeability in heterogeneous reservoir hinder the upward migration of CO2. The optimal injection time is determined as the depleted stage, and the corresponding injection rate is optimized. The optimal recovery factors are 62.83 % and 64.75 % in the homogeneous and heterogeneous reservoirs (804.76 m × 804.76 m × 45.72 m), enhancing production by 22.32 × 103 and 23.00 × 103 t of natural gas and storing 75.60 × 103 and 72.40 × 103 t CO2 with storage efficiencies of 70.55 % and 67.56 %, respectively. The cost/benefit analysis show that economic income of about 8.67 and 8.95 million USD can be obtained by CO2-EGR with optimized injection parameters respectively. This work could assist in determining optimal injection strategy and economic benefits for industrial scale gas reservoirs.

An Integrated IR4.0 Software Enables Autonomous Casing Crossflow Rate Calculation

2021 ◽  
Author(s):  
Nasser M. Al-Hajri ◽  
Akram R. Barghouti ◽  
Sulaiman T. Ureiga
Keyword(s):  
Industrial Revolution ◽  
Water Injection ◽  
Flow Characteristics ◽  
Injection Rate ◽  
Performance Model ◽  
Injection Well ◽  
Production Model ◽  
Well Performance ◽  
Secondary Formation ◽  
Well Model

Abstract This paper will present an alternative calculation technique to predict wellbore crossflow rate in a water injection well resulting from a casing leak. The method provides a self-governing process for wellbore related calculations inspired by the fourth industrial revolution technologies. In an earlier work, calculations techniques were presented which do not require the conventional use of downhole flowmeter (spinner) to obtain the flow rate. Rather, continuous surface injection data prior to crossflow development and shut-in well are used to estimate the rate. In this alternative methodology, surface injection data post crossflow development are factored in to calculate the rate with the same accuracy. To illustrate the process an example water injector well is used. To quantify the casing leak crossflow rate, the following calculation methodology was applied:Generate a well performance model using pre-crossflow injection data. Normal modeling techniques are applied in this step to obtain an accurate model for the injection well as a baseline case.Generate an imaginary injection well model: An injection well mimicking the flow characteristics and properties of the water injector is envisioned to simulate crossflow at flowing (injecting) conditions. In this step, we simulate an injector that has total depth up to the crossflow location only and not the total depth of the example water well.Generate the performance model for the secondary formation using post crossflow data: The total injection rate measured at surface has two portions: one portion goes into the shallower secondary formation and another goes into the deeper (primary) formation. The modeling inputs from the first two steps will be used here to obtain the rate for the downhole formation at crossflow conditions.Generate an imaginary production well model: The normal model for the water injector will be inversed to obtain a production model instead. The inputs from previous steps will be incorporated in the inverse modeling.Obtaining the crossflow rate at shut-in conditions: Performance curves generated from step 3 & 4 will be plotted together to obtain an intersection that corresponds to the crossflow rate at shut-in conditions. This numerical methodology was analytically derived and the prediction results were verified on syntactic field data with very high accuracy. The application of this model will benefit oil operators by avoiding wireline logging costs and associated safety risks with mechanical intervention.

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