Influence of Transport Conditions on Optimal Injection Rate for Acid Jetting in Carbonate Reservoirs

2018 ◽  
Author(s):  
Dmitry Ridner ◽  
Taylor Frick ◽  
Ding Zhu ◽  
A. Daniel Hill ◽  
Renzo Angeles ◽  
...  
Keyword(s):  
Injection Rate ◽  
Carbonate Reservoirs ◽  
Optimal Injection

Influence of Transport Conditions on Optimal Injection Rate for Acid Jetting in Carbonate Reservoirs

2020 ◽  
Vol 35 (01) ◽  
pp. 137-146
Author(s):  
Dmitry Ridner ◽  
Taylor Frick ◽  
Ding Zhu ◽  
Alfred Daniel Hill ◽  
Renzo Angeles ◽  
...  
Keyword(s):  
Injection Rate ◽  
Carbonate Reservoirs ◽  
Optimal Injection

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.

The New Flow Control Devices Autonomously Controlling the Performance of Matrix Acid Stimulation Operations in Carbonate Reservoirs

2021 ◽  
Author(s):  
Mojtaba Moradi ◽  
Michael R Konopczynski
Keyword(s):  
Flow Control ◽  
Dynamic Change ◽  
Injection Rate ◽  
Control Flow ◽  
Carbonate Reservoir ◽  
Operating Conditions ◽  
Carbonate Reservoirs ◽  
High Permeability ◽  
The Impact ◽  
Stimulation Of

Abstract Matrix acidizing is a common but complex stimulation treatment that could significantly improve production/injection rate, particularly in carbonate reservoirs. However, the desired improvement in all zones of the well by such operation may not be achieved due to existing and/or developing reservoir heterogeneity. This paper describes how a new flow control device (FCD) previously used to control water injection in long horizontal wells can also be used to improve the conformance of acid stimulation in carbonate reservoirs. Acid stimulation of a carbonate reservoir is a positive feedback process. Acid preferentially takes the least resistant path, an area with higher permeability or low skin. Once acid reacts with the formation, the injectivity in that zone increases, resulting in further preferential injection in the stimulated zone. Over-treating a high permeability zone results in poor distribution of acid to low permeability zones. Mechanical, chemical or foam diversions have been used to improve stimulation conformance along the wellbore, however, they may fail in carbonate reservoirs with natural fractures where fracture injectivity dominates the stimulation process. A new FCD has been developed to autonomously control flow and provide mechanical diversion during matrix stimulation. Once a predefined upper limit flowrate is reached at a zone, the valve autonomously closes. This eliminates the impact of thief zone on acid injection conformance and maintains a prescribed acid distribution. Like other FCDs, this device is installed in several compartments in the wells. The device has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trip point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones This process can be repeated later in well life to re-stimulate zones. This performance enables the operators to minimise the impacts of high permeability zones on the acid conformance and to autonomously react to a dynamic change in reservoirs properties, specifically the growth of wormholes. The device can be installed as part of lower completions in both injection and production wells. It can be retrofitted in existing completions or be used in a retrievable completion. This technology allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention. This paper will briefly present an overview of the device performance, flow loop testing and some results from numerical modelling. The paper also discusses the completion design workflow in carbonates reservoirs.

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.

scholarly journals Improved CRM Model for Inter-Well Connectivity Estimation and Production Optimization: Case Study for Karst Reservoirs

Energies ◽  
2019 ◽  
Vol 12 (5) ◽  
pp. 816 ◽  
Author(s):  
Daigang Wang ◽  
Yong Li ◽  
Jing Zhang ◽  
Chenji Wei ◽  
Yuwei Jiao ◽  
...  
Keyword(s):  
Time Delay ◽  
Net Present Value ◽  
Water Injection ◽  
Injection Rate ◽  
Production Optimization ◽  
Carbonate Reservoirs ◽  
Karst Reservoir ◽  
Control Step ◽  
Multi Phase Flow

Due to the coexistence of multiple types of reservoir bodies and widely distributed aquifer support in karst carbonate reservoirs, it remains a great challenge to understand the reservoir flow dynamics based on traditional capacitance–resistance (CRM) models and Darcy’s percolation theory. To solve this issue, an improved injector–producer-pair-based CRM model coupling the effect of active aquifer support was first developed and combined with the newly-developed Stochastic Simplex Approximate Gradient (StoSAG) optimization algorithm for accurate inter-well connectivity estimation in a waterflood operation. The improved CRM–StoSAG workflow was further applied for real-time production optimization to find the optimal water injection rate at each control step by maximizing the net present value of production. The case study conducted for a typical karst reservoir indicated that the proposed workflow can provide good insight into complex multi-phase flow behaviors in karst carbonate reservoirs. Low connectivity coefficient and time delay constant most likely refer to active aquifer support through a high-permeable flow channel. Moreover, the injector–producer pair may be interconnected by complex fissure zones when both the connectivity coefficient and time delay constant are relatively large.

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.

scholarly journals Numerical Study of Reactive Flow in Fractured Carbonate Rock

2021 ◽  
Vol 9 ◽  
Author(s):  
Xu Zhou ◽  
Qingfu Zhang ◽  
Hongchuan Xing ◽  
Jianrong Lv ◽  
Haibin Su ◽  
...  
Keyword(s):  
Carbonate Rock ◽  
Injection Rate ◽  
Fracture Model ◽  
Scale Model ◽  
Reactive Flow ◽  
Fracture Aperture ◽  
Discrete Fracture Model ◽  
Discrete Fracture ◽  
Fractured Carbonate ◽  
Optimal Injection

Acidizing technology is an effective reformation method of oil and gas reservoirs. It can also remove the reservoir pollution near wellbore zones and enhance the fluid transmissibility. The optimal injection rate of acid is one of the key factors to reduce cost and improve the effect of acidizing. Therefore, the key issue is to find the optimal injection rate during acid corrosion in fractured carbonate rock. In this work, a novel reactive flow mathematical model based on two-scale model and discrete fracture model is established for fractured carbonate reservoirs. The matrix and fracture are described by a two-scale model and a discrete fracture model, respectively. Firstly, the two-scale model for matrix is combined with the discrete fracture model. Then, an efficient numerical scheme based on the finite element method is implemented to solve the corresponding dimensionless equations. Finally, several important aspects, such as the influence of the injection rate of acid on the dissolution patterns, the influence of fracture aperture and fracture orientations on the dissolution structure, the breakthrough volume of injected acid, and the dynamic change of fracture aperture during acidizing, are analyzed. The numerical simulation results show that there is an optimal injection rate in fractured carbonate rock. However, the fractures do not have an impact on the optimal acid injection rate, they only have an impact on the dissolution structure.

scholarly journals Development of Coupled Biokinetic and Thermal Model to Optimize Cold-Water Microbial Enhanced Oil Recovery (MEOR) in Homogenous Reservoir

2019 ◽  
Vol 11 (6) ◽  
pp. 1652 ◽  
Author(s):  
Eunji Hong ◽  
Moon Jeong ◽  
Tae Kim ◽  
Ji Lee ◽  
Jin Cho ◽  
...  
Keyword(s):  
Bacillus Subtilis ◽  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Thermal Model ◽  
Cold Water ◽  
Injection Rate ◽  
Experimental Results ◽  
Microbial Enhanced Oil Recovery ◽  
Optimal Injection

By incorporating a temperature-dependent biokinetic and thermal model, the novel method, cold-water microbial enhanced oil recovery (MEOR), was developed under nonisothermal conditions. The suggested model characterized the growth for Bacillus subtilis (microbe) and Surfactin (biosurfactant) that were calibrated and confirmed against the experimental results. Several biokinetic parameters were obtained within approximately a 2% error using the cardinal temperature model and experimental results. According to the obtained parameters, the examination was conducted with several injection scenarios for a high-temperature reservoir of 71 °C. The results proposed the influences of injection factors including nutrient concentration, rate, and temperature. Higher nutrient concentrations resulted in decreased interfacial tension by producing Surfactin. On the other hand, injection rate and temperature changed growth condition for Bacillus subtilis. An optimal value of injection rate suggested that it affected not only heat transfer but also nutrient residence time. Injection temperature led to optimum reservoir condition for Surfactin production, thereby reducing interfacial tension. Through the optimization process, the determined optimal injection design improved oil recovery up to 53% which is 8% higher than waterflooding. The proposed optimal injection design was an injection sucrose concentration of 100 g/L, a rate of 7 m3/d, and a temperature of 19 °C.

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