Extended Brugge benchmark case for history matching and water flooding optimization

2013 ◽  
Vol 50 ◽  
pp. 16-24 ◽  
Author(s):  
E. Peters ◽  
Y. Chen ◽  
O. Leeuwenburgh ◽  
D.S. Oliver
Keyword(s):  
History Matching ◽  
Water Flooding

Numerical Simulation Study on Advanced Water Injection for Fuyang Ultra-Low Permeability Fractured Reservoir

2013 ◽  
Vol 421 ◽  
pp. 286-289
Author(s):  
Hui Hui Kou ◽  
Xian Gui Liu ◽  
Han Min Xiao ◽  
Ling Hui Sun ◽  
Dong Dong Hou ◽  
...  
Keyword(s):  
History Matching ◽  
Large Scale ◽  
Water Injection ◽  
Sedimentary Facies ◽  
Oil Field ◽  
Water Flooding ◽  
Small Scale ◽  
Low Permeability ◽  
Fractured Reservoir ◽  
Production Ratio

According to the features of low porosity and low permeability fracture as well as small scale of channel development, frequent sedimentary facies changes of planar sandstone, poor connectivity, large variation of sequence thickness and great development difficulties for oil layer in Fuyang Oilfield. In this paper, on the basis of fully considered of fracture features, built a more accurate 3-D geological model. And on the basis of the history matching, determined the formation pressure maintenance level under different injection-production ratio and rational water-flooding timing by the simulation of the different programs in the process advanced water injection development. The results show that: the reasonable injection-production ratio of Fuyang oil layer is 1.4, and the rational water-flooding timing is three months after advanced water injection. This provides theoretical guidance for the large-scale development of Fuyang oil layer, and also provides the technical basis for the developing of the other low permeability fractured oil field by advanced water injection.

scholarly journals Effect of initial water flooding on the performance of polymer flooding for heavy oil production

2020 ◽  
Vol 75 ◽  
pp. 19 ◽  
Author(s):  
Clement Fabbri ◽  
Romain de-Loubens ◽  
Arne Skauge ◽  
Gerald Hamon ◽  
Marcel Bourgeois
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Production ◽  
Water Flooding ◽  
Relative Permeabilities ◽  
Oil Viscosity ◽  
Initial Water ◽  
Polymer Injection ◽  
Polymer Flood

In the domain of heavy to extra heavy oil production, viscous polymer may be injected after water injection (tertiary mode), or as an alternative (secondary mode) to improve the sweep efficiency and increase oil recovery. To prepare field implementation, nine polymer injection experiments in heavy oil have been performed at core scale, to assess key modelling parameters in both situations. Among this consistent set of experiments, two have been performed on reconstituted cylindrical sandpacks in field-like conditions, and seven on consolidated Bentheimer sandstone in laboratory conditions. All experiments target the same oil viscosity, between 2000 cP and 7000 cP, and the viscosity of Partially Hydrolyzed Polyacrylamide solutions (HPAM 3630) ranges from 60 cP to 80 cP. Water and polymer front propagation are studied using X-ray and tracer measurements. The new experimental results presented here for water flood and polymer flood experiments are compared with experiments described in previous papers. The effects of geometry, viscosity ratio, injection sequence on recoveries, and history match parameters are investigated. Relative permeabilities of the water flood experiment are in line with previous experiments in linear geometry. Initial water floods led to recoveries of 15–30% after one Pore Volume Injected (PVI), a variation influenced by boundary conditions, viscosity, and velocities. The secondary polymer flood in consolidated sandstone confirms less stable displacement than tertiary floods in same conditions. Comparison of secondary and tertiary polymer floods history matching parameters suggests two mechanisms. First, hysteresis effect during oil bank mobilization stabilizes the tertiary polymer front; secondly, the propagation of polymer at higher oil saturation leads to lower adsorption during secondary experiment, generating a lower Residual Resistance Factor (RRF), close to unity. Finally, this paper discusses the use of the relative permeabilities and polymer properties estimated using Darcy equation for field simulation, depending on water distribution at polymer injection start-up.

scholarly journals Evaluation of Polymer Flooding in a Highly Stratified Heterogeneous Reservoir. A Field Case Study

2020 ◽  
Vol 16 ◽  
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Lower Layer ◽  
Polymer Flooding ◽  
Economic Life ◽  
Water Flooding ◽  
Base Case ◽  
Sweep Efficiency ◽  
Sector Model ◽  
Reservoir Simulator

Oil and gas companies are looking for proven hydrocarbon reserves from their mature drained reservoirs to extend the production and economic life of these fields. The chemical enhanced oil recovery (CEOR) is an attractive water-based EOR method for these mature fields. The polymer flooding (PF) is a widely applied process in reservoirs with low sweep efficiency after the water flooding (WF). The target Colombian field has one of the first polymer pilots in the region with positive results of oil recovery in “A” sands. Thus, the operator is interested in the expansion of PF for the same reservoir and even in deeper reservoir sands. This paper focuses in the evaluation of different scenarios of PF for the producer in layers A and B with a mechanistic simulation model, thus obtaining new recommendations for the recovery strategy in the field. A sector model was constructed from a full field model using a commercial reservoir simulator to the in-house chemical flooding reservoir simulator: UTCHEMRS. This sector model was also migrated to a second commercial simulator allowing a performance comparison for these three simulators. UTCHEMRS model results were compared with the commercial simulators through the history matching (HM) phase. The primary and waterflood history match was in agreement with the field data. Simulation results suggested that PF for the base case in “A” sands presented an incremental oil recovery of up to 12% additional to water flooding. Additionally, PF was extended to the lower layer “B” sand to investigate the potential of polymer injection. The PF injection in both reservoirs simultaneously loses sweep efficiency and decreases the oil recovery to about 3%. However, a hypothetical case of new infill producer wells with the objective of testing the individual reservoir performance has revealed that PF is having significant upside from B sands as well.

scholarly journals Streamline simulation study on recovery of oil by water flooding: A real case study on Haripur field

2016 ◽  
Vol 28 (1) ◽  
pp. 61-72
Author(s):  
Mohammad Amirul Islam ◽  
ASM Woobaidullah ◽  
Badrul Imam
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Oil Production ◽  
Water Flooding ◽  
Present Condition ◽  
Optimum Number ◽  
Injection Wells ◽  
Reservoir Performance ◽  
Production Wells ◽  
Head Pressure

Haripur field is the first oil producing field in Bangladesh. The field produced approximately 0.53 MMSTB of oil from the well No. SY-7. The oil production began in 1987 and terminated in 1994. All of the oil was produced by the reservoir own energy from the depth of 2030 meter. Recent investigation and study have revealed that approximately 31 MMSTB Oil is remaining in that formation as validated by the reservoir performance based study i.e. oil production rate and tube head pressure history matching. At present condition, the reservoir has no pressure energy to lift the oil to surface as it requires minimum 1500 psi pressure, so it needs pressure energy to lift the oil to surface. Among the recent developed technologies water injection is one of the best methods to sweep oil towards the production well from the injection well as well as to provide sufficient pressure for lifting. In this study we proposed design for optimum waterflooding pattern and defined optimum number of injection and production wells. In addition the production and injection rates are optimized along with selection of the best placement of production and injection wells and their life.Bangladesh J. Sci. Res. 28(1): 61-72, June-2015

State-of-the-Art Solution of Capacitance Resistance Model by Considering Dynamic Time Constants as a Realistic Assumption

2017 ◽  
Vol 140 (1) ◽  
Author(s):  
A. Lesan ◽  
S. Ehsan Eshraghi ◽  
A. Bahroudi ◽  
M. Reza Rasaei ◽  
H. Rahami
Keyword(s):  
Time Constant ◽  
History Matching ◽  
Injection Rate ◽  
Water Flooding ◽  
Production Flow ◽  
Time Constants ◽  
New Model ◽  
Resistance Model ◽  
Model Dependency ◽  
Dynamic Time

To have an acceptable accuracy for water flooding projects, proper history matching is an important tool. Capacitance resistance model (CRM) simulates water flooding performance based on two tuning parameters of time constant and connectivity. Main advantages of CRM are its simplicity and fastness; furthermore, it needs only some field-available inputs like injection and production flow rates. CRM is reliable if producers receive the injection rate signal; in other words, duration of history matching must be enough so that the rate signal of injection is sensed in producers. It is a shortcoming of CRM that the results might not be accurate as a result of short history. In the common CRM, time constant is considered to be a static parameter (constant number) during the history of simulation. However, time constant is a time-dependent function that depends on the reservoir nature. In this paper, a new model has been developed as it decreases model dependency on the history matching length by shifting time axis. This new definition adds a rate shift constant to the model mathematics. Moreover, a new model is considering dynamic time constants. This new model is called dynamic capacitance resistance model (DCRM). Two reservoir models have been simulated to analyze the performance of DCRM, and, as a result, it is found that the static time constant is an erroneous assumption. Finally, the accuracy of the results has been improved since the degree-of-freedom of the CRM increased in the new version.

Orthogonal Experimental Design on the Program of CO2 Displacement

2012 ◽  
Vol 518-523 ◽  
pp. 3030-3037
Author(s):  
Ji Cheng Zhang ◽  
Ai Li Gao ◽  
Kao Ping Song
Keyword(s):  
Experimental Design ◽  
History Matching ◽  
Gas Injection ◽  
Parameters Optimization ◽  
Evaluation Criterion ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Injection Parameters ◽  
Water Alternating Gas ◽  
Combination Scheme

Combining module PVTi with E300 in ECLIPSE, we found the 3D and three phases simulating module of special low permeability reservoirs in YSL Oilfield. On the basis of history matching, considering gas injection volume, slug size, gas/water ratio, the speeding of gas injection, injection rate of sequent water flooding in water alternating gas, taking the volume of increasing oil and oil-draining rate as evaluation criterion we proceed orthogonal test design according to the principle orthogonal experimental design. By means of intuitive analysis and variance analysis to the test results, getting the primary and secondary orders that injection parameters effect evaluation criterion and optimizing best combination scheme of water alternating gas injection parameters for offering theoretical direction and technical support to water alternating gas injection parameters optimization in spot CO2 displacement.

scholarly journals Production Splitting Method for Commingled Production Reservoir Based on Automatic History Matching of Single Well

Lithosphere ◽  
2022 ◽  
Vol 2022 (Special 1) ◽  
Author(s):  
Yingfei Sui ◽  
Chuanzhi Cui ◽  
Zhen Wang ◽  
Yong Yang ◽  
Peifeng Jia
Keyword(s):  
Numerical Simulation ◽  
History Matching ◽  
Splitting Method ◽  
Production Performance ◽  
Water Flooding ◽  
Production Model ◽  
Mitigation Measures ◽  
Automatic History Matching ◽  
Well Production ◽  
Single Well

Abstract The interlayer interference is very serious in the process of water flooding development, especially when the reservoir adopts commingling production. The implementation of various interlayer interference mitigation measures requires that the production performance parameters and remaining oil distribution of each layer of the reservoir should be clearly defined, and the accurate production splitting of oil wells is the key. In this paper, the five-spot pattern is simplified to a single well production model of commingled production centered on oil well. The accurate production splitting results are obtained through automatic history matching of single well production performance. The comparison between the calculation results of this method and that of reservoir numerical simulation shows that the method is simple, accurate, and practical. In the field application, for the multilayer commingled production reservoir without accurate numerical simulation, this method can quickly and accurately realize the production splitting of the reservoir according to the development performance data.

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