Distribution of the Initial Fluid Composition in an Oil-Gas-Condensate Reservoir with Incomplete Gravity Segregation

It is known that initial composition of the hydrocarbon fluid in a petroleum reservoir changes significantly with depth due to the influence of gravity and geothermal gradient. Classical models of these phenomena are based on the assumption of equilibrium (quasiequilibrium) distribution of component concentrations in the gravity field with the presence of stationary thermodiffusional flux. However, there are typical situations in gas condensate reservoirs when the quasi-equilibrium conditions are not met. For example, this is true if immobile residual oil exists in the reservoir or for deep tight formations where gravity segregation is not completed. For such cases, modified models are required. They are proposed in this paper to take into account the non-equilibrium conditions of the initial fluid composition distribution in gas condensate (or oil-gas-condensate) reservoirs.

Geochemical Modeling of Petrophysical Alteration Effect on CO2 Injectivity in Carbonate Rocks

Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO2 injectivity alteration based on geochemical reactions in carbonate rocks. In this paper, we present a new method for CO2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO2/water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity. Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO2-WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO2-EOR and carbon sequestration projects.

Effects of Gravity on Foam Behavior in Roughened Model Fractures

Summary In this study, to investigate how gravity affects foam in open vertical fractures, we report foam experiments in three 1-m-long, 15-cm-wide glass-model fractures. Each fracture has a smooth wall and a roughened wall. Between the two walls is a slit-like channel representing a single geological fracture. Three model fractures (Models A, B, and C) share the same roughness and have different hydraulic apertures of 78, 98, and 128 µm, respectively. We conduct foam experiments by horizontal injection in the three model fractures placed horizontally and sideways (i.e., with the model fractures turned on their long side), and in Model A placed vertically with injection upward or downward. Direct imaging of the foam inside the model fracture is facilitated using a high-speed camera. We find that foam reaches local equilibrium (LE; where the rate of bubble generation equals that of bubble destruction) in horizontal-flow experiments in all three model fractures and in vertical-flow experiments in Model A. In fractures with a larger hydraulic aperture, foam is coarser because of less in-situ foam generation. In the vertical-flow experiments in Model A, we find that the properties of the foam are different in upward and downward flow. Compared with downward flooding, upward flooding creates a finer-texture foam, as sections near the inlet of this experiment are in a wetter state, which benefits in-situ foam generation. Moreover, less gas is trapped during upward flooding, as gravitational potential helps overcome the capillarity and moves bubbles upward. In the sideways-flow experiments, gravity segregation takes place. As a result, drier foam propagates along the top of the fractures and wetter foam along the bottom. The segregation is more significant in fractures with a larger hydraulic aperture. At foam quality 0.8, gas saturation is 27.7% greater at the top than the bottom for Model C, and 19.3% and 10.8% for Models B and A, respectively. Despite the gravity segregation in all three model fractures, water and gas are not completely segregated. All three model fractures thus represent a capillary transition zone, with greater segregation with increasing aperture. Our results suggest that the propagation of foam in vertical natural fractures meters tall and tens of meters long, with an aperture of hundreds of microns or greater, is problematic. Gravity segregation in foam would weaken its capacity in the field to maintain uniform flow and divert gas in a tall fracture over large distances.

Investigation of Reduced Interfacial Tension by Surfactant Flooding in Mixed-Wet Reservoirs

Surfactant flooding has long been considered a reliable solution for enhanced oil recovery, either by reducing oil-water interfacial tension (IFT) or through wettability alteration. This paper reveals the effect that reduced IFT has on capillary trapping in heterogeneous reservoirs. This effect is investigated through various numerical experiments on different simulation models where rock capillary pressure is assumed to scale with IFT. Capillary contrast on the scale of a few centimeters to a few tens of meters is reduced in the presence of surfactants. This reduction in IFT, under very specific circumstances, creates favorable conditions for increased or accelerated hydrocarbon production from mixed-wet reservoirs. The focus of this study is to ascertain the effectiveness of surfactant flooding in mixed-wet reservoirs. Simulation studies of different mechanisms which are believed to occur in mixed-wet reservoirs are presented. Simulation results indicate the promising effect of surfactant flooding on oil recovery, depending on the type of reservoir. Detailed fine-scale simulation studies are carried out with representative relative permeability and imbibition capillary pressure curves from mixed-wet cores. By designing and selecting a series of surfactants to lower the IFT to the range of 10-3dynes/cm, a recovery of 10 to 20% of the original oil-in-place is technically and economically feasible. The efficiency of surfactant flooding is investigated through sensitivity scenarios on formation rock/fluid parameters, including permeability, interfacial tension, rate flow, etc. Geological heterogeneity (layering and heterogeneous inclusions), imbibition capillary pressure curves, viscous/capillary balance (Nc), and gravitational forces were all found to have an impact on recovery by surfactant flooding. Numerical model dimensions, permeability, IFT, density contrast between oil and water, and injection flow rates were found to be the critical parameters influencing simulation results. Gravity segregation, typically ignored in earlier studies, was found to have a significant effect on reservoir performance. Two different numerical models, with and without impermeable shale streaks, were used to capture the gravity segregation effect. The results revealed that the reduction in interfacial tension helps gravity to segregate oil and water, ultimately resulting in improved oil recovery. Moreover, results from the numerical simulation studies revealed that either an inexpensive or a good quality surfactant at low concentration can be used to obtain the same enhanced oil recovery. The effect of change in oil relative permeability curvature, due to reduced interfacial tension, also revealed a reduction in the remaining oil saturation with an increase in the capillary number.

Simulation of Immiscible Water-Alternating-Gas Injection in a Stratified Reservoir: Performance Characterization Using a New Dimensionless Number

Summary Water alternating gas (WAG) is a well-established enhanced-oil-recovery process where gas and water are injected in alternating fashion. Good volumetric sweep is achieved as water and gas target both the oil residing in low and high portions of the reservoir, respectively. Other important features in three-phase hysteretic flow include phase trapping, which is believed to be more strongly associated with the gas phase. With these aspects in mind, a vast simulation study has been performed investigating immiscible WAG injection focusing on mechanisms such as mobility, gravity, injected volume fractions, reservoir heterogeneity, gas entrapment, and relative permeability hysteresis. The aim of our work is to investigate the interplay between these mechanisms for a model system with sufficient complexity to be of relevance and then scale recovery performance using a new dimensionless number that incorporates the relevant model input parameters. A horizontally layered reservoir is considered where oil is displaced by water and gas alternately injected toward a producer. The model is a modified black-oil type, where hysteresis in the gas phase is modeled using the Land (1968) model for trapping and the Carlson (1981) model for relative permeability hysteresis. It is seen that gravity segregation in uniform models and increased heterogeneity in no-gravity models both lead to lower oil recovery. However, in heterogeneous models, gravity can divert flow from high-permeability layers into low-permeability layers and improve recovery. Hysteresis lowers gas mobility and hence improves gas/oil mobility ratio and reduces gravity segregation. The first effect is always positive, but the second is mainly positive in more uniform reservoirs where gravity segregation has a negative effect on recovery. In heterogeneous reservoirs, reducing gravity segregation can lead to the oil in low-permeability layers remaining unswept. The newly derived characteristic dimensionless number is effectively a WAG mobility ratio, termed M*, expressing how well the injected-fluid mixture is able to displace oil, whether it is because of fluid mobilities, heterogeneity, or other effects. At a value of M* near unity, optimal recovery is achieved, whereas logarithmic increase of M* reduces recovery.