CONTROLLING WATER PRODUCTION IN FRACTURED RESERVOIRS WITH CAVITIES USING WATER INJECTION

2011 ◽  
Vol 2 (1) ◽  
pp. 23-34 ◽  
Author(s):  
Baosheng Liang ◽  
Xiaolong Peng ◽  
Zhimin Du ◽  
Xingwan Tu
Keyword(s):  
Fractured Reservoirs ◽  
Water Injection ◽  
Water Production

A Simplified and Efficient Method for Water Flooding Production Index Calculations in Low Permeable Fractured Reservoir

2019 ◽  
Vol 141 (11) ◽  
Author(s):  
Shun Liu ◽  
Liming Zhang ◽  
Kai Zhang ◽  
Jianren Zhou ◽  
Heng He ◽  
...  
Keyword(s):  
Fractured Reservoirs ◽  
Water Injection ◽  
Cross Flow ◽  
Production Performance ◽  
Water Flooding ◽  
Simplified Model ◽  
Single Fracture ◽  
Fractured Reservoir ◽  
Production Index ◽  
Future Production

Presently, predicting the production performance of fractured reservoirs is often challenging because of the following two factors: one factor such as complicatedly connected and random distribution nature of the fractures and the other factor includes the limitations of the understanding of reservoir geology, deficient fracture-related research, and defective simulators. To overcome the difficulties of simulating and predicting fractured reservoir under complex circumstances of cross flow, a simplified model, which assumes cross flow only exists in the oil phase segment, is constructed. In the model, the pressure distribution of a single fracture can be described by solving an analytical mathematical model. In addition, due to research and field experience which indicate that cross flow also exists in the mixed-phase segment after water injection, the simplified model is modified to consider cross flow in the whole phase. The model constructed here is applicable for fractured reservoirs especially for a low-permeability fracture reservoir, and it moderately predicts future production index. By using iterative methods, the solution to the model can be feasibly obtained and related production performance index formulas can be derived explicitly. A case study was performed to test the model, and the results prove that it is good.

scholarly journals Artificial Interference of Stress Field in a Near-Fracture show="" $6#?=""Zone by Water Injection in a Preexisting Crack

2019 ◽  
Vol 2019 ◽  
pp. 1-15 ◽  
Author(s):  
Yongxiang Zheng ◽  
Jianjun Liu ◽  
Bohu Zhang
Keyword(s):  
Oil And Gas ◽  
Fractured Reservoirs ◽  
Water Injection ◽  
Fluid Pressure ◽  
In Situ Stress ◽  
Stress Intervention ◽  
Oil And Gas Resources ◽  
Favorable State ◽  
Artificial Stress

The in situ stress has an important influence on fracture propagation and fault stability in deep formation. However, the development of oil and gas resources can only be determined according to the existing state of in situ stress in most cases. It is passive acceptance of existing in situ stress. Unfortunately, in some cases, the in situ stress conditions are not conducive to resource development. If the in situ stress can be interfered in some ways, the stress can be adjusted to a more favorable state. In order to explore the method of artificial interference, this paper established the calculation method of the in situ stress around the cracks based on fracture mechanics at first and obtained the redistribution law of the in situ stress. Based on the obtained redistribution law, attempts were made to interfere with the surrounding in situ stress by water injection in the preexisting crack. On this basis, the artificial stress intervention was applied. The results show that artificial interference of stress can effectively be achieved by water injection in the fracture. And changing the fluid pressure in the crack is the most effective way. By stress artificial intervention, critical pressure for water channelling in fractured reservoirs, directional propagation of cracks in hydraulic fracturing, and stress adjustment on the structural plane were applied. This study provides guidance for artificial stress intervention in the exploitation of the underground resource.

Field Performances, Effective Times, and Economic Assessments of Polymer Gel Treatments in Controlling Excessive Water Production From Mature Oil Fields

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Munqith Aldhaheri ◽  
Mingzhen Wei ◽  
Ali Alhuraishawy ◽  
Baojun Bai
Keyword(s):  
Fractured Reservoirs ◽  
Descriptive Analysis ◽  
Naturally Fractured Reservoirs ◽  
Oil Fields ◽  
Water Production ◽  
Polymer Gel ◽  
Rock Formations ◽  
Water Cut ◽  
Matrix Rock ◽  
Excessive Water

Abstract Polymer bulk gels have been widely applied to mitigate excessive water production from mature oil fields by correcting the reservoir permeability heterogeneity. This paper reviews water responses, effective times, and economic assessments of injection-well gel treatments based on 61 field projects. Eight parameters were evaluated per the reservoir type using the descriptive analysis, stacked histograms, and scatterplots. Results show that water production generally continues to increase after the treatment for undeveloped conformance problems. Contrarily, it typically decreases after the reactive gel treatments target developed conformance issues. For the developed problems, gel treatments do not always mitigate the water production where the water cut may stabilize or increase by 17% in 22% of instances. In addition, they often do reduce water production but not dramatically to really low levels where the water cut stays above 70% and reduces by only 10% in most cases. Gel treatments are economically appraised based only on the oil production response, and both water responses (injection and production) are not considered in the evaluation. They have a typical payout time of 9.2 months, cost of incremental oil barrel of 2 $/barrel, and effective time of 1.9 years. In addition, they have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally fractured reservoirs than in matrix-rock formations. The current review strongly warns reservoir engineers that gel treatments are not superior in alleviating the water production and candidates should be nominated based on this fact to achieve favorable economics and avoid treatment failures.

scholarly journals Investigation of acid pre-flushing and pH-sensitive microgel injection in fractured carbonate rocks for conformance control purposes

2020 ◽  
Vol 75 ◽  
pp. 52
Author(s):  
Alireza Teimouri ◽  
Saeid Sadeghnejad ◽  
Amir Hossein Saeedi Dehaghani
Keyword(s):  
Flow Rate ◽  
Control Method ◽  
Fractured Reservoirs ◽  
Water Injection ◽  
Ph Sensitive ◽  
Water Flooding ◽  
Fracture Aperture ◽  
Visual Cell ◽  
Conformance Control ◽  
Fractured Carbonate

Waterflooding in fractured reservoirs is a challenging task due to the presence of high conductive flow pathways such as fractures. Much of the injected water passes through fractures without sweeping the oil in the low permeable area, which results in an early breakthrough. Implementing deep conformance control techniques can be a remedy for this early water breakthrough. pH-sensitive microgel injection is a conformance control method in which the dependency of microgel viscosity to pH guarantees easy injection of these microgels into formations at low pH environments. Because of the geochemical reactions among rock minerals, microgels, and a pre-flushing acid, the microgel pH increases; therefore, these microgels swell and block high conductive fractures. In this study, a designed visual cell containing rock samples is implemented to observe rock–microgel interactions during a pH-sensitive microgel flooding into a fractured carbonate medium. First, the dependency of fracture aperture changes to the acid pre-flush flow rate is examined. Then, we investigate the effect of pH-sensitive microgel concentration on its resistance to block fractures during post-water flooding by studying the gel failure mechanisms (e.g., adhesive separation, cohesive failure). Finally, the effect of an initial aperture of fracture is examined on microgel washout when water injection is resumed. The results showed that both decreasing the acid flow rate and lowering the initial aperture could increase the rate of aperture changes. Moreover, the microgel solution with a concentration of 1 wt% showed the highest resistance (98.2 psi/ft) against post-water injection. Additionally, this microgel concentration had the highest permeability reduction factor. Meanwhile, the smaller initial aperture of fracture contributed to a higher microgel resistance.

New method of controlling excessive water production in wells using induced formation damage

2015 ◽  
Vol 55 (2) ◽  
pp. 485
Author(s):  
Abbas Zeinijahromi ◽  
Pavel Bedrikovetski
Keyword(s):  
Fresh Water ◽  
Large Scale ◽  
Produced Water ◽  
Water Injection ◽  
Cost Effective ◽  
Formation Damage ◽  
Water Production ◽  
Permeable Barrier ◽  
Water Influx ◽  
Excessive Water

Excessive water production is a major factor in reduced well productivity. This can result from water channelling from the water table to the well through natural fractures or faults, water breakthrough in high permeability zones, or water coning. The use of foams or gels for controlling water production through high-permeable layers has been tested successfully in several field cases. A large treatment volume, however, is required to block the water influx that generally involves high operational and material costs. This extended abstract proposes a new cost-effective method of creating a low-permeable barrier against the produced water with induced formation damage. The method includes applying induced formation damage to block the water influx without hindering the oil production. This can be achieved by injection of a small slug of fresh water into the water-producing layer. This results in release of in situ fines from the matrix, which can decrease permeability and create a local low-permeable barrier to the producing water. In large-scale approximation, water injection with induced fines migration is analogous to polymer flooding. This analogy is used to model the fresh water with induced formation damage. Sensitivity studies showed that the injection of 0.01 PVI of fresh water resulted in the blockage of the water-producing layer and an incremental recovery by 8% in field case A, with respect to the standard production scenario. The authors found that the incremental gas recovery with induced formation damage was sensitive to reservoir heterogeneity, permeability reduction and slug volume.

Rigorous Performance Evaluation of Stochastic Optimization for Water Injection Strategies

2021 ◽  
Author(s):  
Nader BuKhamseen ◽  
Ali Saffar ◽  
Marko Maucec
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
Water Injection ◽  
Oil Production ◽  
Optimization Techniques ◽  
Evolutionary Strategies ◽  
Stochastic Methods ◽  
Water Production ◽  
Reservoir Simulation Model ◽  
Injection Strategies

Abstract This paper presents an approach to optimize field water injection strategies using stochastic methods under uncertainty. For many fields, voidage replacement was the dictating factor of setting injection strategies. Determining the optimum injection-production ratio (IPR) requires extensive experience taking into consideration all the operational facility constraints. We present the outcome of a study, in which several optimization techniques were used to find the optimum field IPR values and then elaborate on the techniques? strengths and weaknesses. The synthetic reservoir simulation model, with millions of grid blocks and significant numbers of producers and injectors, was divided into seven IPR regions based on a streamline study. Each region was assigned an IPR value with an associated uncertainty interval. An ensemble of fifty probabilistic scenarios was generated by experimental design, using Latin Hypercube sampling of IPR values within tolerance limits. Scenarios were used as the main sampling domain to evaluate a family of optimization engines: population-based methods of artificial intelligence (AI), such as Genetic algorithms and Evolutionary strategies, Bayesian inference using sequential or Markov chain Monte Carlo, and proxy-based optimization. The optimizers were evaluated based on the recommended IPR values that meet the objective of minimizing the water cut by maximizing oil production and minimizing water production. The speed of convergence of the optimization process was also a subject of evaluation. To ensure unbiased sampling of IPR values and to prevent oversampling of boundary extremes, a uniform triangular distribution was designed. The results of the study show a clear improvement of the objective function, compared to the initial sampled cases. As a direct search method, the Evolutionary strategies with covariance matrix adaptation (ES-CMA) yielded the optimum IPR value per region. While examining the effect of applying these IPR values in the reservoir simulation model, a significant reduction of water production from the initial cases without an impact on the oil production was observed. Compared to ESCMA, other optimization methods have dem

Production Performance Analysis of Western Siberia Mature Waterflood with Prime Diagnostic Metrics

2021 ◽  
Author(s):  
Arthur Aslanyan ◽  
Andrey Margarit ◽  
Arkadiy Popov ◽  
Ivan Zhdanov ◽  
Evgeniy Pakhomov ◽  
...  
Keyword(s):  
Cross Sections ◽  
Western Siberia ◽  
Performance Metrics ◽  
Water Injection ◽  
Production Performance ◽  
Practical Case ◽  
Flow Profile ◽  
Water Production ◽  
Production Analysis ◽  
Conventional Production

Abstract The paper shares a practical case of production analysis of mature field in Western Siberia with a large stock of wells (> 1,000) and ongoing waterflood project. The main production complications of this field are the thief water production, thief water injection and non-uniform vertical sweep profile. The objective of the study was to analyse the 30-year history of development using conventional production and surveillance data, identify the suspects of thief water production and thief water injection and check the uniformity of the vertical flow profile. Performing such an analysis on well-by-well basis is a big challenge and requires a systematic approach and substantial automation. The majority of conventional diagnostic metrics fail to identify the origin of production complications. The choice was made in favour of production analysis workflow based on PRIME metrics, which automatically generates numerous conventional production performance metrics (including the reallocated production maps and cross-sections) and additionally generates advanced metrics based on automated 3D micro-modelling. This allowed to zoom on the wells with potential complications and understand their production/recovery potential. The PRIME analysis has also helped to identify the wells and areas which potentially may hold recoverable reserves and may benefit from additional well and cross-well surveillance.

A Mathematical Model for Natural Fracture Evolution in Water-Flooding Oil Reservoir

2013 ◽  
Vol 868 ◽  
pp. 535-541
Author(s):  
Hong Liu ◽  
Lin Wang ◽  
Yu Wu Zhou ◽  
Xi Nan Yu
Keyword(s):  
Oil Recovery ◽  
Rock Fracture ◽  
Fractured Reservoirs ◽  
Water Injection ◽  
Injection Pressure ◽  
Natural Fracture ◽  
Water Flooding ◽  
Oil Well ◽  
Fractured Reservoir ◽  
Naturally Fractured

The fractured low permeability reservoirs develop complex fracture network. As the of waterflooding recovery heightens, excessive high injection pressures and excessive water injection rate will result in open, initiation, propagation and coalescence of micro-fracture, connecting injection with production form the high permeability zone, which results in a one-way onrush of waterflooding, water cut in oil well water rise quickly, causing a severe oil well flooding and channeling, thereby reducing the ultimate oil recovery efficiency. The effect of the waterflooding seepage within natural fracture on fracture initiation is studied and analyzed here, applying the theory of rock fracture mechanics to analyze the interaction of fracture system for naturally fractured reservoirs in waterflooding developing process, studying the mechanical mechanism of opening, initiation, propagation and coalescence of natural fracture under injection pressure, which is important theoretical significance for studying the distribution law of fracture and defining appreciate water injection mode and injection pressure in the process of injection development of the naturally fractured reservoir and for delaying the directivity water break-through and water flooding rate of oil well in the process of injection development.

Combining Preformed Particle Gel and Curable Resin-Coated Particles To Control Water Production from High-Temperature and High-Salinity Fractured Producers

SPE Journal ◽  
2019 ◽  
Vol 25 (02) ◽  
pp. 938-950 ◽  
Author(s):  
Lin Sun ◽  
Daibo Li ◽  
Wanfen Pu ◽  
Liang Li ◽  
Baojun Bai ◽  
...  
Keyword(s):  
High Temperature ◽  
High Speed ◽  
High Salinity ◽  
Fractured Reservoirs ◽  
Water Production ◽  
Combined System ◽  
Injection Wells ◽  
Coated Particles ◽  
Preformed Particle Gel ◽  
Control Water

Summary Preformed-particle-gel (PPG) treatments have been successfully used in injection wells to reduce excessive water production from high-temperature, high-salinity fractured reservoirs. However, PPG itself cannot be used in fractured producers because it tends to wash out after the wells resume production. Therefore, we proposed to combine curable resin-coated particles (CRPs) with PPG to control water production from fractured producers. In this paper, millimeter-sized tubes and fractured carbonate cores were designed to comprehensively investigate water-plugging behaviors of the combined system under the conditions of various fracture parameters and PPG/CRP sizes. Particular attention was given to control the PPG washout after production was resumed. The results showed the cured CRPs could generate immobile packs in fractures and dramatically mitigate the PPG washout. The small size of the CRPs and the small ratio of CRP size to tube diameter contributed low permeability and homogeneity to CRP packs. Meanwhile, the less-permeable and more-homogeneous CRP pack, as well as the larger-sized PPGs, contributed to a higher PPG breakthrough pressure gradient. Moreover, some of the PPG particles blocked in the CRP packs could be released through high-speed brine injection from producers, which indicated the recoverability of the water plugging. This study provides a promising approach to reduce the high-water-cut problem in fractured producers.

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