Gas Flooding Research Articles

A novel insight of laboratory investigation and simulation for high pressure air injection in light oil reservoir

Due to the precipitous dropping oil price, air injection becomes advantageous to other gas flooding techniques as a result of the low cost. Therefore, this work targeted a light oil reservoir and comprehensively investigated the potential of air injection in this reservoir using experimental and numerical simulation, from which some new insights into high pressure air injection were recognized. Oxidation kinetics of the crude oil were first established using Thermal Gravity Analysis (TG)/Differential Thermal Gravity (DTG), and further validated through a set of history matching. The results indicate that the intense oxidation reaction consumed a great volume of oxygen forming only CO2. Temperature peak occurred after reacting 23 h, revealing that the oxidation reaction is an exothermic process under reservoir conditions and spontaneous combustion might take place. Reservoir dip angle is a crucial parameter governing the oil production and updip injection is generally suggested. Earlier air injection leads to more noticeable incremental temperature effect and also higher ultimate recovery. Air injection seems notably appropriate for rhythm reservoirs. Given a mature reservoir, high-permeability zone would cause gas breakthrough and thus considerably detract the air injection performance. Temperature-resistant polymer gel or foam is suggested to plug thief zones promoting oxidation reactions and air sweep efficiency.

Utilisation of multiple gas injection to enhance oil recovery for fractured-cavity carbonate heavy oil reservoir

Gas injection has been proven to be a valuable enhanced oil recovery (EOR) process for light oil reservoirs and ordinary heavy oil reservoirs, but it was rarely proposed as an EOR process for fractured-cavity carbonate heavy oil reservoir. This study aims to investigate the feasibility of the gas injection based on flooding and cycle stimulation method with respect to enhancing oil recovery for fractured-cavity carbonate heavy oil reservoir. Thus, a representative physical model of core was designed, and some gas flooding and cyclic gas stimulation experiments were conducted. The experimental results show that gas injection can enhance the oil recovery in fractured-cavity carbonate reservoir and carbon dioxide is the optimal injected gas in this study. Also, gravity drainage plays an important role in fractured-cavity carbonate reservoir besides the various recovering mechanisms in conventional reservoir. In addition, Tahe heavy oil has a strong capacity of oxygen consumption due to the high content of polar compound. [Received: May, 1, 2015; Accepted: February 29, 2016]

Utilisation of multiple gas injection to enhance oil recovery for fractured-cavity carbonate heavy oil reservoir

Gas injection has been proven to be a valuable enhanced oil recovery (EOR) process for light oil reservoirs and ordinary heavy oil reservoirs, but it was rarely proposed as an EOR process for fractured-cavity carbonate heavy oil reservoir. This study aims to investigate the feasibility of the gas injection based on flooding and cycle stimulation method with respect to enhancing oil recovery for fractured-cavity carbonate heavy oil reservoir. Thus, a representative physical model of core was designed, and some gas flooding and cyclic gas stimulation experiments were conducted. The experimental results show that gas injection can enhance the oil recovery in fractured-cavity carbonate reservoir and carbon dioxide is the optimal injected gas in this study. Also, gravity drainage plays an important role in fractured-cavity carbonate reservoir besides the various recovering mechanisms in conventional reservoir. In addition, Tahe heavy oil has a strong capacity of oxygen consumption due to the high content of polar compound. [Received: May, 1, 2015; Accepted: February 29, 2016]

Experimental and simulation determination of minimum miscibility pressure for a Bakken tight oil and different injection gases

Abstract The effective development of unconventional tight oil formations, such as Bakken, could include CO 2 enhanced oil recovery (EOR) technologies with associated benefits of capturing and storing large quantities of CO 2 . It is important to conduct the gas injection at miscible condition so as to reach maximum recovery efficiency. Therefore, determination of the minimum miscibility pressure (MMP) of reservoir live oil–injection gas system is critical in a miscible gas flooding project design. In this work, five candidate injection gases, namely CO 2 , CO 2 -enriched flue gas, natural gas, nitrogen, and CO 2 -enriched natural gas, were selected and their MMPs with a Bakken live oil were determined experimentally and numerically. At first, phase behaviour tests were conducted for the reconstituted Bakken live oil and the gases. CO 2 outperformed other gases in terms of viscosity reduction and oil swelling. Rising bubble apparatus (RBA) determined live oil–CO 2 MMP as 11.9 MPa and all other gases higher than 30 MPa. The measured phase behaviour data were used to build and tune an equation-of-state (EOS) model, which calculated the MMPs for different live oil-gas systems. The EOS-based calculations indicated that CO 2 had the lowest MMP with live oil among the five gases in the study. At last, the commonly-accepted Alston et al. equation was used to calculate live oil–pure CO 2 MMP and effect of impurities in the gas phase on MMP change. The Bakken oil–CO 2 had a calculated MMP of 10.3 MPa from the Alston equation, and sensitivity analysis showed that slight addition of volatile impurities, particularly N 2 , can increase MMP significantly.

Effect of wettability on oil recovery and breakthrough time for immiscible gas flooding

ABSTRACTThe effect of wettability on oil recovery at higher water saturation is still not fully understood, especially in the case of mixed wettability. This study was conducted to examine the effects of wettability on oil recovery and breakthrough time through experiments for two wettability conditions (water-wet and mixed-wet) and three water saturations (20%, 40%, and 60%). Clashach sandstone core with a porosity of 12.8% and a permeability of 75 md was utilized as the porous media. Immiscible gas flooding was performed by injecting nitrogen gas into the core at room temperature and pressure. The results showed 54.3% and 48.8% of the initial oil in place (IOIP) as the ultimate oil recovery at 40% water saturation from mixed-wet core and water-wet core respectively. In contrast, the water-wet core displayed better results (32.6% of the IOIP) in terms of breakthrough time compared to the results of water-wet core (10.6% of the IOIP) at the same water saturation. In conclusion, oil recovery was found highly dependent on water saturation while breakthrough time was mainly affected by the wettability of the cores.

Study on distribution of reservoir endogenous microbe and oil displacement mechanism.

In order to research oil displacement mechanism by indigenous microbial communities under reservoir conditions, indigenous microbial flooding experiments using the endogenous mixed bacterium from Shengli Oilfield were carried out. Through microscopic simulation visual model, observation and analysis of distribution and flow of the remaining oil in the process of water flooding and microbial oil displacement were conducted under high temperature and high pressure conditions. Research has shown that compared with atmospheric conditions, the growth of the microorganism metabolism and attenuation is slowly under high pressure conditions, and the existence of the porous medium for microbial provides good adhesion, also makes its growth cycle extension. The microbial activities can effectively launch all kinds of residual oil, and can together with metabolites, enter the blind holes off which water flooding, polymer flooding and gas flooding can’t sweep, then swap out remaining oil, increase liquidity of the crude oil and remarkably improve oil displacement effect.

Evaluation of CO2 Low Salinity Water-Alternating-Gas for enhanced oil recovery

Low Salinity Waterflooding (LSW) is an emerging attractive enhanced oil recovery (EOR) method because of its oil recovery performance and relatively simple, environmentally friendly implementation, when compared with conventional high salinity waterflooding and EOR approaches. More importantly, another advantage of LSW is that it can be integrated with other EOR methods (in hybrid LSW processes), i.e. chemical or miscible gas flooding. The merits of combining LSW with CO2 injection is investigated in this paper, and a novel EOR method, Low Salinity Water Alternating CO2 (CO2 LSWAG), is proposed. CO2 LSWAG injection promotes the synergy of the mechanisms underlying these methods which further enhances oil recovery and overcomes the late production problems frequently encountered in conventional WAG. CO2 LSWAG has been evaluated in both one-dimensional and full-field scale with positive results compared with conventional high salinity WAG.To investigate the advantages of CO2 LSWAG, a comprehensive ion exchange model associated with geochemical processes has been implemented and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. 1D simulation of different CO2 LSWAG schemes are first conducted to understand the combined effects of solubility of CO2 in brine, dissolution of carbonate minerals, ion exchange, and wettability alteration. CO2 LSWAG performance is then evaluated on a field scale through an integrated workflow that includes geological modeling, multi-phase multi component reservoir flow modeling and process optimization. The simulation results indicate that CO2 LSWAG has the highest oil recovery compared to conventional high salinity waterflood, high salinity WAG, continuous CO2 flooding, and low salinity waterflood. A number of geological realizations are generated to assess the geological uncertainty effect, in particular clay distribution uncertainties, on CO2 LSWAG efficiency. CO2 LSWAG injection strategies are optimized by identifying key WAG parameters. Finally, CO2 LSWAG is evaluated in the full field scale for a North Sea reservoir and the simulation results shows that CO2 LSWAG yields about 4.5% incremental OOIP compared to the conventional high salinity WAG.The proposed workflow demonstrates the synergy between CO2 WAG and LSW. Built in a robust reservoir simulator, it serves as a powerful tool for screening, design, optimization, and uncertainty assessment of the process. CO2 LSWAG is a promising EOR technique as it not only combines the benefits of CO2 injection and low salinity water floods but also promotes the synergy between these processes through the interactions between geochemical reactions associated with CO2 injection, ion exchange process, and wettability alteration. This paper demonstrates the merits of this process through modeling, optimization and uncertainty assessment.

Global Riemann solver and front tracking approximation of three-component gas floods

We study a $2\times 2$ system of non-strictly hyperbolic conservation laws arising in three-component gas flooding for enhanced oil recovery. The system is not strictly hyperbolic. In fact, along a curve in the domain one family is linearly degenerate, and along two other curves the system is parabolic degenerate. We construct global solutions for the Riemann problem, utilizing the splitting property of thermodynamics from the hydrodynamics. Front tracking simulations are presented, using the global Riemann solver.

Experimental study of nanoparticle-surfactant-stabilized CO2 foam: Stability and mobility control

CO2 injection has proved to be the most common and efficient enhanced oil recovery techniques which leads to more residual oil recovery. Unfavorable sweep efficiency which results in fingering propagation and causes early gas breakthrough is the most challenging issue of gas flooding process. The aim of this work is to study foam stability and analyze the mobility of CO2 foam stabilized by mixture of raw silica nanoparticles and ethyl hexadecyl dimethyl ammonium bromide (cationic surfactant). The result is obtained through both dynamic and static techniques using a new adsorption index.NPS-stabilized foams are generated using Ross-Miles method. A novel index for the adsorption of surfactant molecules on the nanoparticles is proposed using electrical conductivity measurement. Analyzing the foam decay behavior based on this adsorption index, it is found that the foam life can be divided into two general regions. First, low adsorption region that the foam stability is initially dominated by surfactant concentration and after a while it is controlled by nanoparticles. Second, high adsorption region, that the foam stability, is mostly affected by both nanoparticles and surfactant concentrations as well.The pressure behavior and morphology of the foam are investigated using dynamic characterization apparatus. By using a capillary viscometer in this apparatus, foam apparent viscosity is measured for different phase ratios, and nanoparticle and surfactant concentrations. It is observed that NPS solutions produce uniformly smaller foams with higher apparent viscosity compared to those with surfactant solutions. The results reveal that in different surfactant concentrations, the apparent viscosity of NPS-stabilized foam experiences a maximum value of 6.03cp which is about 9 times larger than that of CO2/water dispersion flood. This maximum is coincided with the maximum adsorption index and the maximum hydrophobicity.

Experimental and numerical evaluation of the potential of improving oil recovery from shale plugs by nitrogen gas flooding

Production from tight formation resources leads to the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising enhanced oil recovery (EOR) approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature have focused on unconventional plays. This paper presents experimental work for applying an immiscible N2 flooding process in oil-saturated shale plugs. To investigate the effect of injection pressure on recovery performance, multiple core-flood tests were performed at the injection pressures of 1000psi, 3000psi, and 5000psi, respectively. A lab-scale numerical simulation model was built to match the experimental data. Based on this model, we conducted sensitive studies and analyzed the recovery process.The potential of N2 flooding for improving oil recovery from shale core plugs has been demonstrated by the experimental observations and simulation results. Under a certain injection pressure, the results show that the oil was produced with a high and stable production rate at the initial period of the recovery process, before gas breakthrough. After that, the incremental RF decreased with the increase of a flooding period, and a much longer time had less effect on extracting more oil. We also examined the effect of injection pressure on gas breakthrough time, ultimate RF, and oil recovery history. This study illustrates that gas flooding could be considered as an improved oil recover (IOR) approach in shale oil reservoirs.

Influence of Wettability on Residual Gas Trapping and Enhanced Oil Recovery in Three-Phase Flow: A Pore-Scale Analysis by Use of Microcomputed Tomography

Summary We imaged an intermediate-wet sandstone in three dimensions at high resolution (1–3.4 µm3) with X-ray microcomputed tomography (micro-CT) at various saturation states. Initially the core was at connate-water saturation and contained a large amount of oil (94%), which was produced by a waterflood [recovery factor Rf = 52% of original oil in place (OOIP)] or a direct gas flood (Rf = 66% of OOIP). Subsequent waterflooding and/or gasflooding (water-alternating-gas process) resulted in significant incremental-oil recovery (Rf = 71% of OOIP), whereas a substantial amount of gas could be stored (approximately 50%)—significantly more than in an analog water-wet plug. The oil- and gas-cluster-size distributions were measured and followed a power-law correlation N ∝ V−τ , where N is the frequency with which clusters of volume V are counted, and with decays exponents τ between 0.7 and 1.7. Furthermore, the cluster volume V plotted against cluster surface area A also correlated with a power-law correlation A ∝ Vp, and p was always ≈ 0.75. The measured τ- and p-values are significantly smaller than predicted by percolation theory, which predicts p ≈ 1 and τ = 2.189; this raises increasing doubts regarding the applicability of simple percolation models. In addition, we measured curvatures and capillary pressures of the oil and gas bubbles in situ, and analyzed the detailed pore-scale fluid configurations. The complex variations in fluid curvatures, capillary pressures, and the fluid/fluid or fluid/fluid/fluid pore-scale configurations (exact spatial locations also in relation to each other and the rock surface) are the origin of the well-known complexity of three-phase flow through rock.

Variation of Crude Oil Physical Properties and Oil Recovery of Natural Gas Flood Under Different Pressures

ABSTRACTFor the gas flood process, crude oil physical properties including oil volume and viscosity would be greatly changed resulting from gas solution and extraction. First, solubility of natural gas in oil and brine was measured and compared. Meanwhile, the resulting oil expansion and viscosity reduction were experimentally tested. Second, oil viscosity increase due to extraction was studied by extraction experiments. Finally, oil recovery of natural gas and propane-enriched natural gas flood was studied under different pressures. Results show that solubility of natural gas in oil is dozens of times of that in brine. Variation of crude oil physical properties during natural gas injection mainly includes the remarkable volume expansion and viscosity reduction caused by gas dissolution into oil, and the oil volume shrinkage and viscosity increase caused by extraction are not so significant. The oil recovery of natural gas flood grows linearly with increased injection pressure and gas solubility in oil, but is still less than 90% even at 55 MPa, which indicates immiscible flood at 55 MPa. Addition of propane to natural gas is proved to be helpful for enhancing oil recovery and achieving miscibility.

Prediction of Minimum Miscibility Pressure Using the UNIFAC Group Contribution Activity Coefficient Model and the LCVM Mixing Rule

Minimum miscibility pressure (MMP) is a key design parameter of any gas flooding project that can be measured in the laboratory or estimated by computational methods based on the equation of state (EOS). Application of the EOS for mixtures is attainable by employing simple mixing rules, such as the van der Waals (VDW) fluid mixing rule, which has been applied widely in petroleum industry so far. The objective of this study is to estimate MMP using multiple mixing cells (MMC), developed by Ahmadi and Johns (K. Ahmadi and R. T. Johns, SPE J. 2011, 16, 733–742), with the EOS/GE mixing rule. The linear combination of the Vidal and Michelsen (LCVM) is used as a mixing rule for the modified Peng–Robinson EOS by applying the UNIFAC activity coefficient equation. Moreover, in the MMP calculations, a group contribution method is used to characterize undefined petroleum fractions. The MMP results are compared with those estimated using the VDW (classic) mixing rule and experimental data of the slim tube apparatus. ...

Relationship between oil recovery and CO2 storage efficiency under the influence of gravity segregation in a CO2 EOR system

Integrating the technologies of EOR and CO2 sequestration could economically bring large quantities of CO2 storage capacity and increase recoverable oil, which could be called “green oil”. Gravity segregation, particularly in CO2 gas flooding, is an important factor for the successful application of CO2 flooding. A major goal of this study was to analyze how miscibility conditions and CO2 injection rate affect both oil recovery and CO2 storage efficiency under an environment of gravity segregation. This paper presents experimental observations of both EOR and CO2 sequestration for CO2 flooding in immiscible and near-miscible conditions at various CO2 injection rates using two-dimensional vertical Berea sandstone slabs (20 × 20 cm). The experiments were run under immiscible and near-miscible conditions with various CO2 injection rates. CO2 was injected continuously up to a maximum three-pore-volume injection into sandstone saturated with n-decane. From the results, both oil recovery and CO2 storage efficiency in the near-miscible conditions were much better than the immiscible conditions in the case of a vertical system containing a gravity segregation environment. Ultimately, in the relationship between oil recovery and CO2 storage efficiency, from this study, we propose that they behaved similarly, with a trend corresponding to the CO2 injection rate in immiscible conditions, whereas they showed the opposite relationship in near-miscible conditions.

Reservoir Screening for EOR Potential for the Western North Slope, Alaska

The Western North Slope of Alaska is an oil-rich zone located in the Colville river unit close to the Eastern boundary of National Petroleum Reserve Alaska. With an objective to find better enhanced oil recovery solutions and improve recoveries, four reservoirs from the Western North Slope were screened for different enhanced oil recovery methods to find the most suitable option. Based on the initial screening, gas injection was found to be the preferred method. This was followed by the determination of optimum injection gas compositions for Western North Slope reservoirs and their rank, thereby developing a new ranking methodology for gas flooding projects. The work was accomplished via a combination of two custom developed Excel spreadsheets for the determination of minimum miscibility pressure and enrichment respectively and several numerical experiments carried out using a compositional reservoir simulator, the results of which were applied for parametric ranking of the four Western North Slope reservoirs.

Investigation of the Gas Injection Effect on Asphaltene Onset Precipitation Using the Cubic-Plus-Association Equation of State

Miscible and immiscible gas flooding is one of the enhanced oil recovery (EOR) techniques that has been widely used to increase the oil production. One of the critical problems with gas flooding is that it generally aggravates the asphaltene precipitation, which further creates a flow assurance problem. Therefore, it is imperative to investigate beforehand the effect of gas injection into the reservoir from the modeling results. The cubic-plus-association (CPA) equation of state (EoS) has previously been applied to model the asphaltene onset precipitation condition. In this work, we adopt the modeling approach from the previous work and provide the conceptual base for it. Five different reservoir fluids are studied to validate whether the model is able to calculate the effect of different types (e.g., N2, CO2, and methane) and amounts (e.g., 10, 20, and 30 mol %) of gas injections in agreement with experimental data from the literature. We also investigate the model behavior to show the importance of the association term in the EoS for the selected modeling approach. Sensitivity of the model results when we calculate either two or three model parameters from the experimental data is also studied. Model dependency upon the saturates, aromatics, resins, and asphaltenes (SARA) analysis or molecular weight (MW) of asphaltene is also analyzed. In addition, a unique characteristic of the model for the given stock tank oil (STO) is identified, which does not change with different types and amounts of gas injections and also remains the same at upper and lower onset pressure boundaries. On the basis of this unique characteristic, a simple procedure to predict asphaltene phase envelope (APE) for the reservoir oil with relatively simple and few experimental data, performed on STO with n-pentane/n-heptane as a precipitant, is proposed. This proposed procedure avoids the need of high-pressure measurements of upper onset pressure (UOP).

Compositional flow modeling using a multi-point flux mixed finite element method

We present a general compositional formulation using multi-point flux mixed finite element (MFMFE) method on general hexahedral grids. The mixed finite element framework allows for local mass conservation, accurate flux approximation, and a more general treatment of boundary conditions. The multi-point flux inherent in MFMFE scheme allows the usage of a full permeability tensor. The proposed formulation is an extension of single and two-phase flow formulations presented by Wheeler and Yotov, SIAM J. Numer. Anal. 44(5), 2082–2106 (35) with similar convergence properties. Furthermore, the formulation allows for black oil, single-phase and multi-phase incompressible, slightly and fully compressible flow models utilizing the same design for different fluid systems. An accurate treatment of diffusive/dispersive fluxes owing to additional velocity degrees of freedom is also presented. The applications areas of interest include gas flooding, CO 2 sequestration, contaminant removal, and groundwater remediation.

Experimental and numerical study of the EOR potential in liquid-rich shales by cyclic gas injection

One of the limitations of gas or water injection in tight shale oil reservoirs is that the fluid injectivity is low due to the nature of very low permeability of shale. Another challenge of gas flooding is that the injected gas is subject to early breakthrough in densely fractured shale gas or oil reservoirs, resulting in poor performance. Cyclic gas injection (CGI) in a single horizontal well is not affected by early gas breakthrough. Compared to gas flooding, cyclic gas injection is an effective recovery process in tight shale oil reservoirs. This paper presented our experimental work on using nitrogen cyclic injection in shale rocks. We analyzed the experimental data using numerical simulation approaches. Coreflooding and simulation outputs showed that it is favorable to implement cyclic gas injection enhanced oil recovery process in shale oil reservoirs.Our experimental data and simulation results have demonstrated the potential of gas huff-n-puff injection to improve oil recovery in shale oil reservoirs. We also examined the effect of diffusion on improved oil recovery performance by cyclic injection process. The objective of this paper is to investigate significance of possible factors on gas huff-n-puff recovery process in shale oil reservoirs via experimental work and simulation approaches. Our simulation results benchmarked with experimental observations showed that molecular diffusion played a significant role in the mobilization of oil in lab scale.

CO2 enhanced oil recovery and storage using a gravity-enhanced process

CO2 flooding offers a means to recover significant amounts of oil while simultaneously sequestering CO2. Recent methods for CO2 geological storage have focused on CO2 injection into deep brine aquifers, or by water-alternating-gas (WAG) injection in a miscible gas flooding process using vertical wells. There is significant uncertainty in the amount of CO2 that can be stored using these methods owing to reservoir heterogeneity and variations in reservoir/fluid parameters. It would be useful therefore to have a more robust process that can also increase both CO2 storage and oil recovery in a symbiotic relationship, where increased storage leads to greater oil recovery.This paper considers an alternative process that maximizes both storage and oil recovery simultaneously using only horizontal wells in a gravity-enhanced miscible process. A reduced-order model (ROM) is developed to consider a wide range of reservoir heterogeneities and fluid properties. Monte-Carlo simulations using the ROM show that achieving very high storage and oil recovery is possible using the gravity-enhanced process and that the approach is very robust. For example, after 2.0 moveable pore volumes injected (MPVI), probabilistic forecasts show that CO2 storage efficiency across two standard deviations ranges from about 81% to 93%, indicating that nearly all of the available pore space (excluding immobile water) at the end of injection is occupied by CO2. Oil recoveries after 2.0 MPVI varied from 79% to 93% of the original mass of oil-in-place (OOIP). These storage and recovery efficiencies are significantly greater than any process reported to date. Response functions developed can also be used to estimate the maximum amount of stored CO2 and corresponding oil recoveries for a wide range of reservoir and fluid properties. Such estimates are critical for regional and national assessment of CO2 storage potential.

The Effects of Initial Gas Content of the Oil on Recovery by Natural Gas Flood

Effects of initial gas content in oil (IGC) on oil properties and interactions between oil and natural gas were firstly studied by measurements of oil viscosity, interfacial tension (IFT) between oil and gas, and continual dissolution capacity (CDC) of natural gas in oil, which were the main factors affecting oil recovery. Secondly, core flood tests using the oils with different IGC were conducted, so that effects of IGC on oil recovery could be known. Finally, reasons why IGC could influence oil recovery were mechanistically analyzed according to the breakthrough data of natural gas. The results show that, with increased IGC, oil viscosity decreased linearly and IFT was also reduced, but the CDC of natural gas in oil was weakened. Oil recovery of natural gas flood decreased obviously with increased IGC, which is mainly due to the getting-earlier breakthrough of natural gas resulting from the reduced CDC of natural gas in oil and the consequently weakened capacity of oil to dissolve the fingering gas. So for the light oils that are similar to the experimental samples, the lower the IGC was, the higher the oil recovery of natural gas flood was.