scholarly journals Modeling of Liquid Injectivity in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1123-1138 ◽  
Author(s):  
J.. Gong ◽  
S.. Vincent-Bonnieu ◽  
R. Z. Kamarul Bahrim ◽  
C. A. Che Mamat ◽  
R. D. Tewari ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flow Model ◽  
Radial Flow ◽  
Gas Injection ◽  
Small Region ◽  
Propagation Model ◽  
Injection Well ◽  
Wellbore Pressure ◽  
Model Predictions ◽  
Experimental Findings

Summary Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity. In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator's results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor. The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.

Real-Time Down-Hole Monitoring of Gas Injection Profile Using Fibre-Optic Distribute Temperature and Acoustic Sensing in Tarim

2021 ◽  
Author(s):  
Defei Chen ◽  
Kun Huang ◽  
Xiangjuan Meng ◽  
Ju Liu ◽  
Bao Zhang ◽  
...  
Keyword(s):  
High Temperature ◽  
Real Time ◽  
Oil Recovery ◽  
Fiber Optic ◽  
Gas Injection ◽  
Injection Well ◽  
Fibre Optic ◽  
Distributed Temperature Sensing ◽  
Acoustic Sensing ◽  
Gas Channeling

Abstract Gas injection has become an important means of enhancing oil recovery (EOR) in clastic reservoirs, the Donghe Oilfield, Tarim, has been undergoing gas injection to enhanced oil recovery. During the gas injection, dynamic justification of gas injection was the most severe challenges, which needed to monitor the pressure profile, temperature profile and gas injection profile. Therefore, monitoring gas injection profile has becoming an important part of gas drive reservoirs. Donghe Oilfield was characterized by ultra-deep (>6000m), high temperature (>140°C) and high content of carbon dioxide, conventional manometer and thermometer cannot meet the downhole condition of ultra-deep and high temperature. To continuously monitor gas injection well, permanent fibre-optic surveillance technique featured with outstanding conformance, nice corrosion resistance and long-life span was developed, and a program was developed to use real-time fiber-optic Distributed Temperature Sensing (DTS) and Distributed Acoustic sensing (DAS) to identify the gas injection profile (gas channeling). Monitoring principle and system assembly of the fibre-optic was demonstrated in detail, the DTS utilized Joule - Thompson cooling principle as the gas injected into formation through screen pipe, while the DAS captured the amplitude and frequency of acoustics from the gas flow. DTS and DAS data obtained at the same time by using fiber wireline outside the gas injection string during gas injection. There was a field application in gas injection well of DH1-H3 and gas injection profiles derived from DTS and DAS had the extremely high consistency to radioactive tracer profiles run at about the same time and under similar injection rates and pressure. The success of the fibre-optic surveillance in DH1-H3 exhibited great potential of fiber-optic sensing in gas injection EOR projects, which could provide a new and effective tool in identifying gas channeling.

scholarly journals Modeling Near-Miscible Gas Foam Injection in Fractured Tight Rocks and Its Challenges

Energies ◽  
2021 ◽  
Vol 14 (7) ◽  
pp. 1998
Author(s):  
Haishan Luo ◽  
Kishore K. Mohanty
Keyword(s):  
Oil Recovery ◽  
Fractured Rock ◽  
Gas Injection ◽  
Gas Composition ◽  
Gas Oil ◽  
Rock Matrix ◽  
Reducing Gas ◽  
Tight Reservoirs ◽  
Modeling Strategy ◽  
Tight Rocks

Unlocking oil from tight reservoirs remains a challenging task, as the existence of fractures and oil-wet rock surfaces tends to make the recovery uneconomic. Injecting a gas in the form of a foam is considered a feasible technique in such reservoirs for providing conformance control and reducing gas-oil interfacial tension (IFT) that allows the injected fluids to enter the rock matrix. This paper presents a modeling strategy that aims to understand the behavior of near-miscible foam injection and to find the optimal strategy to oil recovery depending on the reservoir pressure and gas availability. Corefloods with foam injection following gas injection into a fractured rock were simulated and history matched using a compositional commercial simulator. The simulation results agreed with the experimental data with respect to both oil recovery and pressure gradient during both injection schedules. Additional simulations were carried out by increasing the foam strength and changing the injected gas composition. It was found that increasing foam strength or the proportion of ethane could boost oil production rate significantly. When injected gas gets miscible or near miscible, the foam model would face serious challenges, as gas and oil phases could not be distinguished by the simulator, while they have essentially different effects on the presence and strength of foam in terms of modeling. We provide in-depth thoughts and discussions on potential ways to improve current foam models to account for miscible and near-miscible conditions.

Applicability of Enhanced Oil Recovery techniques on mature fields - Interest of gas injection

2005 ◽  
Author(s):  
Frederic Maubeuge ◽  
Danielle Christine Morel ◽  
Jean-Pierre Charles Fossey ◽  
Said Hunedi ◽  
Jacques Albert Danquigny
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Recovery Techniques

The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery

2004 ◽  
Vol 126 (2) ◽  
pp. 119-124 ◽  
Author(s):  
O. S. Shokoya ◽  
S. A. (Raj) Mehta ◽  
R. G. Moore ◽  
B. B. Maini ◽  
M. Pooladi-Darvish ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Cost Effective ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Flue Gases ◽  
Low Permeability ◽  
Light Oil ◽  
Light Oil Reservoirs

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Numerical Optimization of WAG Injection in a Sandstone Field using a Coupled Surface and Subsurface Model

2021 ◽  
Author(s):  
Thaer I. Ismail ◽  
Emad W. Al-Shalabi ◽  
Mahmoud Bedewi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Coupled Model ◽  
Sensitivity Study ◽  
Mobility Control ◽  
Base Case ◽  
The North ◽  
Injection Process ◽  
Interaction Terms ◽  
Wag Injection

Abstract Gas injection is one of the most commonly used enhanced oil recovery (EOR) methods. However, there are multiple problems associated with gas injection including gravity override, viscous fingering, and channeling. These problems are due to an adverse mobility ratio and cause early breakthrough of the gas resulting, in poor recovery efficiency. A Water Alternating Gas (WAG) injection process is recommended to resolve these problems through better mobility control of gas, leading to better project economics. However, poor WAG design and lack of understanding of the different factors that control its performance might result in unfavorable oil recovery. Therefore, this study provides more insight into improving WAG oil recovery by optimizing different surface and subsurface WAG parameters using a coupled surface and subsurface simulator. Moreover, the work investigates the effects of hysteresis on WAG performance. This case study investigates a field named Volve, which is a decommissioned sandstone field in the North Sea. Experimental design of factors influencing WAG performance on this base case was studied. Sensitivity analysis was performed on different surface and subsurface WAG parameters including WAG ratio, time to start WAG, total gas slug size, cycle slug size, and tubing diameter. A full two-level factorial design was used for the sensitivity study. The significant parameters of interest were further optimized numerically to maximize oil recovery. The results showed that the total slug size is the most important parameter, followed by time to start WAG, and then cycle slug size. WAG ratio appeared in some of the interaction terms while tubing diameter effect was found to be negligible. The study also showed that phase hysteresis has little to no effect on oil recovery. Based on the optimization, it is recommended to perform waterflooding followed by tertiary WAG injection for maximizing oil recovery from the Volve field. Furthermore, miscible WAG injection resulted in an incremental oil recovery between 5 to 11% OOIP compared to conventional waterflooding. WAG optimization is case-dependent and hence, the findings of this study hold only for the studied case, but the workflow should be applicable to any reservoir. Unlike most previous work, this study investigates WAG optimization considering both surface and subsurface parameters using a coupled model.

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