Miscible WAG Efficiency Assessment on a Large Mature Carbonate Field

2021 ◽  
Author(s):  
Marcel J. Bourgeois ◽  
Hocine Berrahmoun ◽  
Maryam Mohamed Al Attar ◽  
Djilali Boulenouar ◽  
Djelloul Hammadi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
High Efficiency ◽  
Gas Injection ◽  
Water Injection ◽  
Pressure Data ◽  
Utilization Factor ◽  
Miscible Gas Injection ◽  
Production History ◽  
Dimensionless Variables ◽  
Gas Recycling

Abstract This paper is based on the analysis of miscible WAG for an onshore Middle-East field, with strongly undersaturated light oil. Water Alternate Gas operations have been ongoing for around 5 years, which is relatively recent compared to more than 40 years of production history. Goal of this work was to assess the efficiency of this miscible hydrocarbon WAG and to optimize it on the different compartments, with respect to miscibility, voidage replacement, and recycling. As this is a large mature field, with WAG operations dispatched on around 50 injectors and 9 fault blocks (compartments), the method of analysis had to be robust with respect to the different injection strategies followed in the past. It was essentially based on injection and production data, but also used pressure data when available. We computed the following dimensionless variables: oil recovery factor, BSW, voidage replacement ratio (VRR), and also WAG ratio and gas recycling ratio (GRR). Their evolution versus time was analyzed and compared between fault blocks. Using dimensionless variables allowed to compare fault blocks with different initial volumes in place, and to illustrate trends versus time. It was also found beneficial to lump some compartments, when communication was substantiated by pressure data. On the production side, we used the conventional BSW and GOR variables to quantify the water and gas recycling ratio. On the injection side, we observed that in some compartments, the historical WAG ratio was too low in the oil zone, which could be quantified by excluding the peripheral water injection volumes. The analysis allowed also to estimate the gas utilization factor and efficiency, which confirmed the overall high efficiency of miscible gas injection in 3-phase mode. It was also found that the injected fluid efficiency correlated with geology: gas injection tends to be more efficient in zones with high permeabilities at the bottom (coarsening downwards), while water injection is better adapted to zones with high permeabilities at the top (coarsening upwards). Estimating these water and gas efficiencies also allowed to optimize the injection strategy on a field level, by comparing the water efficiency with other units of the field only under waterflood.

scholarly journals Investigation of Oil Recovery in Fractured Carbonate Rock by

2016 ◽  
Vol 6 (1) ◽  
pp. 14
Author(s):  
H. Karimaie ◽  
O. Torsæter
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Co2 Injection ◽  
Recovery Method ◽  
Asmari Limestone ◽  
Fractured Carbonate ◽  
Efficient Recovery ◽  
Live Oil ◽  
Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

scholarly journals Interfacial Phenomena Effect on Sand Production Due to Optimized Smart Water with/without the Presence of Nanoparticles

2020 ◽  
Vol 10 (6) ◽  
pp. 6652-6668
Keyword(s):  
Oil Recovery ◽  
High Efficiency ◽  
Low Cost ◽  
Water Injection ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Sand Production ◽  
Smart Water ◽  
Comparison Of The Results

Historically, smart water flooding is proved as one of the methods used to enhance oil recovery from hydrocarbon reservoirs. This method has been spread due to its low cost and ease of operation, with changing the composition and concentration of salts in the water, the smart water injection leads to more excellent compatibility with rock and fluids. However, due to a large number of sandstone reservoirs in the world and the increase of the recovery factor using this high-efficiency method, a problem occurs with the continued injection of smart water into these reservoirs a phenomenon happened in which called rock leaching. Indeed, sand production is the most common problem in these fields. Rock wettability alteration toward water wetting is considered as the main cause of sand production during the smart water injection mechanism. During this process, due to stresses on the rock surface as well as disturbance of equilibrium, the sand production in the porous media takes place. In this paper, the effect of wettability alteration of oil wetted sandstones (0.005,0.01,0.02 and 0.03 molar stearic acid in normal heptane) on sand production in the presence of smart water is fully investigated. The implementation of an effective chemical method, which is nanoparticles, have been executed to prevent sand production. By stabilizing silica nanoparticles (SiO2) at an optimum concentration of 2000 ppm in smart water (pH=8) according to the results of Zeta potential and DLS test, the effect of wettability alteration of oil wetted sandstones on sand production in the presence of smart water with nanoparticles is thoroughly reviewed. Ultimately, a comparison of the results showed that nanoparticles significantly reduced sand production.

scholarly journals Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiang Li ◽  
Yuan Cheng ◽  
Wulong Tao ◽  
Shalake Sarulicaoketi ◽  
Xuhui Ji ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

Minimum Miscibility Pressure of CO2/Hydrocarbon Systems Within Nanopores

2021 ◽  
Author(s):  
Gang Yang ◽  
Xiaoli Li
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Unconventional Reservoirs ◽  
Minimum Miscibility Pressure ◽  
Theoretical Approaches ◽  
Fluid Systems ◽  
Confined Fluid ◽  
Miscible Gas Injection ◽  
Fluid Characterization ◽  
The Impact

Abstract Minimum miscibility pressure (MMP), as a key parameter for the miscible gas injection enhanced oil recovery (EOR) in unconventional reservoirs, is affected by the dominance of nanoscale pores. The objective of this work is to investigate the impact of nanoscale confinement on MMP of CO2/hydrocarbon systems and to compare the accuracy of different theoretical approaches in calculating MMP of confined fluid systems. A modified PR EOS applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of multiple CO2/hydrocarbon systems at different pore sizes are obtained via the VIT simulations. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the same modified PR EOS is applied to compute the MMP for the same fluid systems. Comparison of these results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, nanoscale confinement results in the drastic suppression of MMP and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

scholarly journals Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3961
Author(s):  
Haiyang Yu ◽  
Songchao Qi ◽  
Zhewei Chen ◽  
Shiqing Cheng ◽  
Qichao Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Co2 Emission ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

scholarly journals Development of Proxy Models for Screening Water Flood and Gas Flood Candidates

2021 ◽  
pp. 51-57
Author(s):  
Moyosore, Olanipekun ◽  
Akpabio, Julius U. ◽  
Isehunwa, Sunday O.
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Screening Method ◽  
Water Flooding ◽  
Improved Oil Recovery ◽  
Screening Criteria ◽  
Recovery Techniques ◽  
Oil Formation Volume Factor ◽  
Proxy Models

Fluid-flood and other improved oil recovery techniques are becoming prominent in global petroleum production because a large proportion of production is from mature oil fields. Although water flooding and gas injection are well established techniques in the industry, several of the screening criteria in literature are discipline which could sometimes be subjective. This work used experimental design techniques to develop proxy models for predicting oil recovery under water-flood and gas-flood conditions. The objective of the study is to develop a quantitative screening method that would allow for candidates to be evaluated and ranked for water flood or gas injection. The model was applied to some field cases and compared with published models and the well-known Welge Analysis method. The coefficient constants for the oil formation volume factor for water flooding and gas injection was 0.0139 and 0.0434 respectively. Similarly, the coefficient constants for water injection and gas injection for the generated proxy model was -2.34* 10-8 and -6.1 *10-5 respectively. The results show that the proxy models developed are quite robust and can be used for first pass screening of water and gas flood candidates. 

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