scholarly journals Approximate solutions for Forchheimer flow during water injection and water production in an unconfined aquifer

2016 ◽  
Vol 538 ◽  
pp. 13-21 ◽  
Author(s):  
Simon A. Mathias ◽  
Konstantinos N. Moutsopoulos
Keyword(s):  
Water Injection ◽  
Approximate Solutions ◽  
Unconfined Aquifer ◽  
Water Production ◽  
Forchheimer Flow

scholarly journals Approximate Solutions for Forchheimer Flow to a Well

2008 ◽  
Vol 134 (9) ◽  
pp. 1318-1325 ◽  
Author(s):  
Simon A. Mathias ◽  
Adrian P. Butler ◽  
Hongbin Zhan
Keyword(s):  
Approximate Solutions ◽  
Forchheimer Flow

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.

Swelling and Deswelling Kinetics of Superabsorbent Polymer

2016 ◽  
Author(s):  
Cody Chancellor ◽  
Mahmoud Elsharafi
Keyword(s):  
Water Injection ◽  
Oil Industry ◽  
Deionized Water ◽  
Effect Of Temperature ◽  
Low Permeability ◽  
Superabsorbent Polymer ◽  
Water Production ◽  
High Permeability ◽  
Kinetics Of ◽  
Oil Formation

In the oil industry, techniques that decrease unwanted water production have drawn large amounts of interest from many companies. During water injection operations, water is injected into the reservoir in order to extract oil remaining in the formation. Due to the heterogeneity in the reservoir formation, oil production will decline and water production will increase as the injected water sweeps the high permeability zones. In order to flush out the oil remaining in the low permeability zones, many treatments have been used. One such treatment involves the injection of a superabsorbent polymer (SAP) into the high permeability zones. The swelled polymer will decrease heterogeneity in the reservoir’s permeability, thus forcing injected water into the oil rich, unswept zones/areas of the formation. Proper application of an SAP can have a dramatic impact on both the production and lifespan of mature oil wells. Understanding the swelling and deswelling kinetics of the SAP is crucial to its application. The following work focused on the use of AT-O3S polymer, a Sodium salt of crosslinked polyacrylic acid purchased from Emerging Technologies®. The polymer had a particle size of 35 to 60 meshes, or 250 to 500 microns. The swelling and deswelling ratio of such a polymer is heavily influenced by salinity, temperature, and pH. In order to study the polymer’s kinetics, 1% (for swelling) or 0.1% (for deswelling) by solution weight of polymer was allowed to swell and deswell over time in various brines. These brines were made up of deionized water, 1% to 20% (by wt.) Sodium Chloride, and/or 1% to 10% (by wt.) Calcium Chloride. The effect of temperature on the final swelling ratio was afterwards tested. Understanding the reaction of SAPs to conditions similar to those found in an oil formation can help the oil industry to utilize this tool with greater efficiency.

Measurement of Thermoelectric Potential Coupling Coefficient for Sandstone Rock Sample

2016 ◽  
Vol 819 ◽  
pp. 83-87
Author(s):  
Mohd Zaidi bin Jaafar ◽  
Abdul Razak Ismail ◽  
Mohamad Kamil bin Saharuddin ◽  
Siti Mardhiah binti Mohd Anuar ◽  
Siti Rahmah bte Suradi ◽  
...  
Keyword(s):  
Temperature Difference ◽  
Coupling Coefficient ◽  
Rock Sample ◽  
Water Injection ◽  
Control Valve ◽  
Water Production ◽  
Coupling Coefficients ◽  
Voltage Versus ◽  
Sandstone Rock ◽  
Excessive Water

Excessive water production is one of the main problems that occur during hydrocarbon production. During water injection, the less viscous water which has higher mobility than the reservoir fluid, tends to by-pass the oil. This phenomenon is normally called water fingering. Density difference between denser water and oil makes the water segregate to the bottom of layer, creating water tongue. Uncontrolled excessive water production will reduce oil production potential and increase the cost for water management and treatment. This phenomenon is economical unfavorable. Intelligent well integrated with monitoring systems and inflow control valve (ICV) has been applied in producing hydrocarbon. The excessive flow of water into well can be controlled using ICV. There are various methods and approaches been proposed to control water production. One of them is by measuring the spontaneous potential (SP) using permanent sensor outside the insulated casing. However, thermoelectric (TE) potential could also contribute to the measurement of the SP. The main objective of this experiment is to measure TE potential across sandstone rock sample at four different salinities which are 0.001M, 0.01M, 0.1M, and 1.0M of brine (NaCl). The core samples dimension is 7.62 cm in length and 3.81 cm in diameter. Temperature difference up to 80°C was applied to rock sample inducing different TE potentials at different salinities. Gradual heating technique was applied in creating temperature difference by using a temperature controller. Three different experiments were conducted for each salinity and real-time voltage (V) and temperature (T) were recorded using data acquisition system. Then the TE coupling coefficient can be determined by calculating the slope after plotting Voltage versus Temperature Difference. The result is as the salinity increases, TE coupling coefficient decrease and drop to zero around 0.1M. The result shows small but still measurable thermoelectric coupling coefficients.

scholarly journals SYNCHRONIZATION OF STORAGE TANK VOLUME, DISPOSAL WELL VOLUME AND ELECTRIC SUBMERSIBLE PUMP (ESP) PUMP CAPACITY IN DISPOSAL WELL FIELD A

2021 ◽  
Vol 4 (02) ◽  
Author(s):  
Ali Musnal ◽  
Fitrianti
Keyword(s):  
Water Level ◽  
Flow Rate ◽  
Storage Tank ◽  
Oil And Gas ◽  
Water Flow Rate ◽  
Water Injection ◽  
Injection Well ◽  
Water Production ◽  
Submersible Pump ◽  
Injection Pump

In producing oil, one of the common problems faced by oil and gas companies is the production of a lot of water. Increased water production causes the storage tank to be unable to accommodate the produced water. To overcome the excess water production, some of the water is injected back into the well. In Field A, an innovation has been made for a water injection pump with the driving force coming from the Electrical Submersible Pump (ESP) pump. The working principle of this ESP pump is to drain water from the disposal well to the injection well. Therefore, in order for the injection to run optimally, synchronization is carried out starting from the water entering the holding tank, the flow rate in the Disposal well and the pump capacity (ESP) for injecting from the holding well to the injection well. The amount of water flow rate injected through the ESP pump is 9,500 BWPD. For this reason, the capacity of the ESP pump as an injection pump is calculated. First, determine the water level in the tank to control the amount of flow that enters the reservoir well. Based on the results of the research that has been done, the water level in the holding tank to get a flow rate of 9,500 BWPD is 4.11 ft. And the results of the calculation of water will be injected using an ESP pump with a number of stages 22 with the TRW Reda Pump Devision pump type. The water will be channeled to the injection well with a type of galvanized iron pipe with a diameter of the main pipe (mainline) of 6 inches. From the disposal well, it flows with a 4 inch pipe as far as 45.93 ft and a 2 inch pipe as far as 2214.57 ft for well 07. As for wells 60, the flowline size is 4 inches as far as 708.66 ft and 2 inches as far as 987.53 ft.

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