Gas Flooding Experiments Research Articles

Tailoring Water-Gas Ratios to Saturation Distribution for Improved Oil Recovery in Low-Permeability Reservoirs.

Water-gas alternation technology (WAG) is considered to be one of the methods that can effectively improve the effect of the CO2 flooding in heterogeneous reservoirs. The proportion of WAG and the timing of WAG adjustment are key factors affecting the oil displacement effect. This article analyzes the influence of adjusting the WAG ratio on the oil recovery effect of heterogeneous rock cores at different gas flooding stages based on gas flooding experiments. Second, the influence of WAG ratio changes on the recovery rate of displacement experiments under different saturation distributions was studied through numerical simulation. Finally, the oilfield model currently in production was used to optimize the WAG ratio adjustment of the reservoir recovery as a constraint condition. Moreover, the correlation between the fluid distribution of the reservoir and the timing of WAG adjustment was verified. The displacement experiment shows that adjusting the WAG ratio has a significant impact on the displacement effect of crude oil under the same heterogeneous conditions. After adjusting the WAG ratio from 1:2 to 2:1 at 0.5 HCPV and 1 HCPV, the final RF showed significant changes. There is an optimal timing for adjusting the WAG ratio under the same heterogeneity. If the WAG ratio is increased earlier, it will lead to a decrease in the CO2 injection volume and reduce the effectiveness of CO2 flooding. If the WAG ratio is increased later, it will lead to the formation of gas channeling channels and affect the effect of adjusting the WAG ratio on flooding.

Quantitative Investigation on Natural Gas Flooding Characteristics in Tight Oil Cores after Fracturing Based on Nuclear Magnetic Resonance Technique

SummaryTight reservoirs are mainly developed by injecting various gases after fracturing. However, the formed fractures are complex, and different fracture conditions have an important impact on the gas injection effect. In addition, natural gas is considered to be suitable for the development of tight reservoirs in China because of the abundant gas source and no corrosion. For this paper, the natural gas injection experiments were studied by combining mercury intrusion porosimetry (MIP) measurements and nuclear magnetic resonance (NMR) measurements. The method can be used to study the distribution characteristics of core pore structure and the recovery characteristics of oil in different pore spaces.In this work, the tight cores of the Changqing Oil Field were selected for fracturing for the natural gas flooding experiments. At first, the distribution characteristics of the core pore structure were studied based on the MIP and NMR measurements. The conversion relationship between the core pore throat radius and the relaxation time (T2) was decided. The NMR T2 distribution was transformed into the distribution of oil in pore space with different throat radii. Then, the gasflooding experiments were conducted to study the oil recovery law of tight cores with different fracture conditions. Finally, the recovery characteristics of oil in different pore spaces were analyzed based on the NMR results of cores.The results show that the pore throat radius of the core is mainly distributed in the range of 0.001 to 10 μm. The oil is mainly stored in the pore space whose pore throat radius ranges from 0.01 to 1 μm. The natural gas also mainly drives the saturated oil in the pore space with a pore throat radius of 0.01 to 1 μm. The increase in fracture area improves the distribution of oil in the larger pore space. In the process of natural gasflooding, with the increase of gas injection, the oil began to be recovered, and then gas was observed at the end of the core. With the continuous injection of natural gas, the rate of recovering oil gradually slowed down, and finally gas breakthrough occurred. The displacement oil process of the nonfractured core was uniform and slow. However, the oil and gas rapidly flowed along the fracture when the natural gas displaced the oil in the fractured core. The oil in the matrix was poorly recovered. Gasflooding mainly recovered the saturated oil in the matrix of nonfractured cores and the saturated oil in the fracture of fractured cores. As the fracture length increased, the oil recovery became lower and the gas breakthrough occurred earlier. The higher fracture density increased the fracture area, which also increased the oil recovery and caused a more intense gas breakthrough.In this paper, the displacement law of tight oil cores by injecting natural gas and the recovery characteristics of oil in different space pores were illuminated. The results can provide theoretical guidance for the formulation of the natural gas injection development plan in tight reservoirs.

The mechanism of gas-water extraction in micro- and nanoscale pores in shale gas reservoirs: Based on gas-water interactions

Gas in micro- and nanoscale pores maintains the middle and later period production of shale gas wells; however, these pores are severely affected by fracturing fluid that prevents the outflow of pore gas and reduces the efficiency of gas flow. This study used an innovative method to analyze gas–water interaction in shale gas reservoirs during the fracturing and drainage process. Based on the theory of gas–water interaction and gas flooding experiments using nuclear magnetic resonance, the drainage mechanism of shale micro- and nanoscale pores was analyzed in detail. The results show that pore gas pressure and drainage resistance after the influence of imbibition can be predicted by the proposed model, which indicates that the fracturing fluid in seepage channels is only discharged so that gas can be extracted and the water retained in the larger pores is discharged first, followed by the water in the smaller pores.

Modeling of Coal Matrix Apparent Strains for Sorbing Gases Using a Transversely Isotropic Approach

Gas sorption-induced coal deformation is one of the primary geomechanics effect in coalbed methane (CBM) engineering. Coal is known to have transversely isotropic properties because of its cleat structure. We propose a new theoretical approach to modeling the strain behavior of bulk coal by including sorption-induced matrix shrinkage/swelling strain, cleat volume strain and matrix mechanical strain resulting from changes in pore pressure, and external stresses. The new model framework can define the apparent bulk coal volume with respect to the variation in gas pressure. To validate the model, unconstrained gas flooding experiments were conducted with helium, methane and carbon dioxide injections. The experimental data agreed well with the modeled strain evolution results under hydrostatic conditions and at the injection pressure conditions. The results show that the degree of anisotropy is ~ 1.6 for helium injection, comparing the strains perpendicular to and parallel to the bedding plane. The results demonstrate that the volumetric strains closely correlate to the sorption capability of coal. The maximum volumetric strain induced by carbon dioxide injection can reach ~ 2.05% as gas pressure increases up to ~ 5.43 MPa, which is ~ 2.77 times that of the methane-induced volumetric strain of ~ 0.74% at a gas pressure of ~ 5.45 MPa. The proposed model can be simplified to be equivalent to the commonly extended Langmuir-type strain model at relatively low gas pressure for bulk coal with low cleat porosity. The proposed model can also successfully cover the volumetric response of bulk coal for high pressures that range beyond 13 MPa. A sensitivity study shows that Young’s modulus, Poisson’s ratio, and the degree of anisotropy affect the volumetric responses differently at various pressure stages, but the effects are always distinct for high-pressure injections. The proposed model framework can be coupled into a coal dynamic permeability model for defining the permeability evolution—which is important for gas production predictions for CBM wells.

Wettability alteration of calcite and dolomite carbonates using silica nanoparticles coated with fluorine groups

Altering the wettability of a gas-liquid system from liquid-wetting to intermediate gas-wetting is a novel strategy for removing condensate from gas condensate reservoirs. In this paper, the role of a silica nanofluid modified by fluorine groups in the wettability alteration of seven carbonate samples was investigated. An acid test and Energy Dispersive X-ray Spectroscopy analysis were carried out to identify the levels of calcite and dolomite as dominant carbonate minerals and evaluate the coating ability of the proposed chemical used on carbonate surfaces. Contact angle measurements and spontaneous imbibition experiments were conducted before and after wettability alteration. In addition, gas flooding experiments were conducted on three permeable core samples to investigate the effect of the nanofluid on the fluid flow at the core scale. Contact angle measurements demonstrated that the wetting tendency of core samples altered from liquid-wetting into gas-wetting after surface treatment, and a higher contact angle was achieved for carbonate cores with less dolomite than calcite. EDX analysis showed more fluorine and silica adsorption on calcite, compared to dolomite cores. After surface modification, the brine imbibed into carbonate core samples 1 to 7 decreased by 0.104, 0.174, 0.0016, 0.773, 0.355, 0.056, and 0.279, respectively. Core flooding results demonstrated that the recovery factor of three permeable core samples increased from 56.52%, 49.69%, and 65.33%–69.34%, 56.75%, and 76.72%, respectively.

Nitrogen gas channeling characteristics in fracture-vuggy carbonate reservoirs

Tahe Oilfield, located in Tarim Basin, Northwest China, is a typical carbonate fracture-vuggy reservoir. Nitrogen gas flooding is a vital technology for improving oil recovery by enlarging sweep volume in fracture-vuggy reservoirs. However, gas channeling restricts further application of nitrogen gas flooding. This paper studied the characteristics of gas channeling in fracture-vuggy carbonate reservoirs using physical simulation. Visual physical models and macroscopic physical models were designed and fabricated based on similarity criterion. Nitrogen gas flooding experiments were conducted in both types of models. Experimental results demonstrated that once the dominant channel of gas is formed, the remaining oil cannot be effectively swept. The greater the areal heterogeneity of fracture-vuggy carbonate reservoir is, the easier the formation of gas channeling is. Gas channeling was accompanied by a large amount of oil and water production. The initial gas channeling was followed by several additional occurrences of gas channeling. In addition, PIR risk assessment method was proposed to predict gas channeling by assigning values to each coefficient of P, I and R. This method verified by oilfield data can be used to prevent and evaluate the risk of gas channeling in fracture-vuggy carbonate reservoirs.

Evaluation of oil production potential in fractured porous media

Based on rock samples of tight oil reservoirs in the buried hills of North China, conventional gas flooding and high-speed centrifugal experiments at different pressures were carried out. Combined with nuclear magnetic resonance experiments, an evaluation method of oil production potential in fractured porous media was established to quantitatively study the gas flooding potential of target reservoirs. Results indicated that the “gas fingering phenomenon” is serious in conventional gas flooding experiments of fractured cores even under low pressures because of fractures. With an increase in flooding pressure, the changes of T2 (T2 relaxation time) spectrum and displacement percentage are relatively small, which means that the displacement efficiency has not been improved significantly (the flooding pressure for these three cores increased from 0.014 MPa to 2.6 MPa, with an average increase in displacement percentage of 6.3%). High-speed centrifugation can realize “homogeneous displacement” of the cores and overcome the influence of gas channeling. With an increase in the displacement pressure, the T2 spectrum and percentage of displaced oil varied obviously, and the displacement efficiency improved greatly (the flooding pressure for these three cores increases from 0.014 MPa to 2.6 MPa, with an average percentage of displaced oil being increased to 16.16%). Using the method of this study, 13 cores of the target reservoir were evaluated for gas flooding potential. The percentage of available pores in the target reservoir ranges from 17.64% to 58.54%, with an average of 33.84%. Movable fluid controlled by microthroats in the reservoirs larger than 0.1 mD is about 20%, while that in the reservoirs smaller than 0.1 mD is about 5%. This study indicates that the development of fractures and microfractures controls the physical properties and fluid productivity of reservoirs.

Experimental study of fluid behaviors from water and nitrogen floods on a 3-D visual fractured-vuggy model

Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs.

CO2-sensitive foams for mobility control and channeling blocking in enhanced WAG process

Mobility control is a key issue in gas and CO2 flooding process, and water-alternating-gas (CO2) injection (WAG) has been used in various field applications. The WAG process can be CO2 foam assisted in order to further improve the sweeping efficiency of the injectants. In this study, a novel foaming method for reducing CO2 mobility and blocking gas channeling is proposed, which is based on a CO2-sensitive chemical (compound with amine group) to generate foams or thicken the injected water in situ. The CO2-sensitive chemical is referred to that, in a reaction triggered by CO2, it can be converted to an effective surfactant or foam agent. The chemical can be dissolved in water and injected as a slug. In this study, the foaming behavior and the CO2-sensitivity of the chemical were tested using a visualization apparatus and a viscometer in the presence of CO2 and N2. The capability of the foams generated using the CO2-sisentive chemical for mobility control was evaluated via gas flooding experiments of sand-packs. Stable CO2 foams have been obtained at high temperature and pressure conditions (up to 140°C and 16MPa), and high viscosity was observed in the chemical solution when CO2 was present in comparison with that of N2, indicating the chemical's sensitivity with dissolved CO2 in water. In the sand-pack flooding experiments, a high resistance factor was achieved in a simulated WAG process using the CO2-sensitive chemical, which is attributed to the CO2 foams and viscous micelles generated in situ during CO2 injection.

Study on Flow Mechanism of Gas Injection in Porous Carbonate Core

There are wide scale of porous carbonate reservoirs in around the world, that have low permeability with undeveloped fracture. With study target of Savark formation in Middle East, core gas flooding experiments are conducted and microscope seepage mechanism is researched further. The study results indicate, with formation condition, miscible associated gas flooding is not achieved easily because of high minimum miscible pressure; flooding efficiency of hydrocarbon gas injection is high, especially for miscible flooding, because gas flooding makes oil volume expanse and viscosity decrease, and then oil mobility will be improved. In the experiments, gas injection mainly displace mobile oil in macropore, so changing displacement manner should be considered to improve flooding efficiency further.

Relationship Between Wetting Properties and Macroscale Hydrodynamics During Forced Gravity Drainage and Secondary Waterflood

In order to relate the wetting properties at the pore scale to the macroscale prevailing forces, a series of experiments was performed in vertical porous media under forced gas invasion at various wettability conditions with partially spreading oil. To describe the dynamics of oil recovery in a three-phase flow condition, the downward gas flood experiments were continued by water injection from the bottom. Experimental results obtained in situations where the magnitudes of viscous, capillary, and gravity forces are comparable. We study the transition from flow configurations where the interface is stable with respect to viscous instability to flow configurations where viscous fingering occurs. The results also have been analyzed using a dimensionless number.

Comparison of viscous and gravity dominated gas–oil relative permeabilities

Unsteady and steady-state gasflood, centrifuge and gravity-drainage experiments are routinely carried out to determine relative permeabilities for cores taken from petroleum reservoirs. These laboratory studies are often interpreted by simple methods, e.g., JBN or Hagoort method, and give different oil relative permeability for the same core. The objective of this paper is to investigate the factors that affect these tests and determine the best use of the data in the field scale studies. In this study, it has been shown that neglecting capillary pressure can lead to significant errors in the relative permeability curves for both gasflood and centrifuge experiments. The residual oil saturation obtained from a centrifuge experiment is very low (∼1%) for a set of unconsolidated and friable cores from offshore, West Africa with spreading oil and shown to be insensitive to the permeability of the porous medium (in the range studied). A comparison between the relative permeabilities determined from centrifuge and gasflood experiments shows that the residual oil saturation is much higher and oil relative permeability is lower for gasflood tests. An empirical model has been proposed to estimate residual oil saturation as a function of a heterogeneity index and displacement rate for cores obtained perpendicular to the bedding plane. The normalized relative permeabilities obtained from the centrifuge and the gasflood experiment are essentially the same for these vertical cores. The normalized oil relative permeabilities for the two techniques are different for cores obtained parallel to the bedding plane, perhaps due to the effects of layering. The centrifuge relative permeability should be applicable to those parts of the reservoir where the flow is gravity dominated. The gasflood relative permeability can be applicable to viscous dominated regions of the reservoir as long as heterogeneities and flow rates are accounted for properly.

Gasflooding Experiments for the East Side of the Yates Field Unit

Summary In a series of immiscible gasflood experiments at current conditions for the east side of the Yates Field Unit (450 psi, 82°F [3.10 MPa, 301 K]), the oil recovery efficiency of CO2 was compared with that of gas-cap gas (GCG). Flooding rates in vertically mounted, preserved-state cores were near the critical velocities for gravity-stable displacement. Oil recoveries with CO2 were 6 to 11 % of original oil in place (OOIP) greater than those of GCG. Flooding results were interpreted with a modified Buckley-Leverett end-effect simulator. With this simulator, the gas/oil saturation profile that results from capillary end effects could be modeled. The modeling study showed that incremental oil recovery with CO2 resulted from oil swelling, oil-viscosity reduction, and gas/oil interfacial-tension (IFT) reduction.