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Accurate determination of the minimum miscibility pressure (MMP) of a crude oil−CO2 system at the actual reservoir temperature is required in order to determine whether CO2 flooding is immiscible or miscible under the actual reservoir pressure. The objective of this study is to determine the MMPs of a crude oil−CO2 system from its measured and predicted equilibrium interfacial tension (IFT) versus equilibrium pressure data at a constant temperature. In the experiment, first, the CO2 solubilities in the crude oil are measured under four different equilibrium pressures. Second, the equilibrium IFTs of the crude oil−CO2 system are measured at 12 different equilibrium pressures and a constant temperature of T = 27 °C by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. The detailed experimental results show that the CO2 solubility in the crude oil is increased almost linearly with the equilibrium pressure. It is also found that the measured crude oil−CO2 equilibrium IFT is reduced almost linearly with the equilibrium pressure as long as it is lower than a threshold pressure. The measured equilibrium IFT versus equilibrium pressure data are used to determine the MMP of the crude oil−CO2 system by applying the so-called vanishing interfacial tension (VIT) technique. In addition, the equilibrium IFT versus equilibrium pressure data of the crude oil−CO2 system are predicted by using the parachor model and linear gradient theory (LGT) model, respectively. The predicted equilibrium IFT data from each model are also used to determine the MMP of the same crude oil−CO2 system. Comparison of the MMPs determined from the two equilibrium IFT prediction models and that determined from the measured equilibrium IFTs shows that the LGT model is suitable for determining the MMP of the crude oil−CO2 system.

Carbon dioxide flooding has been proven to be one of the most effective and viable enhanced oil recovery (EOR) processes for light and medium oil reservoirs. In the past, an extremely large number of laboratory experiments and numerical simulations have been conducted to study the CO 2 EOR process. However, the specific effects of viscous and capillary forces on this tertiary oil recovery process are neither thoroughly studied nor well understood yet. In this paper, an experimental study is carried out to examine the detailed effects of viscous and capillary forces on the CO 2 EOR under the actual reservoir conditions. First, the equilibrium interfacial tensions between a light crude oil and CO 2 are measured at different equilibrium pressures. Second, a series of CO 2 coreflood tests are performed to measure the CO 2 EOR at different CO 2 injection pore volumes, pressures, and rates. Each CO 2 coreflood test is terminated after a total of 1.5 pore volume of CO 2 is injected. The detailed experimental results show that, in general, the measured equilibrium interfacial tension is reduced with the equilibrium pressure but the measured CO 2 EOR at 1.5 pore volume of CO 2 is increased with the CO 2 injection pressure and rate. Finally, the measured CO 2 EOR at 1.5 pore volume versus injection pressure data at different CO 2 injection rates are related to the measured equilibrium interfacial tension versus equilibrium pressure data in terms of the complete capillary number, which is defined as the ratio of the viscous force to the capillary force for each CO 2 coreflood test. This study shows that if the complete capillary number is in an intermediate range, the CO 2 EOR increases quickly with the complete capillary number. Otherwise, the CO 2 EOR is lower and remains almost constant for a smaller complete capillary number, or it is higher and remains unchanged for a larger complete capillary number.

Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using square root-time plot, a plot of rate-normalized pressure versus square root of time. Linear flow appears as a straight line on this plot and the slope of this line can be used to calculate the product of fracture half-length and square root of permeability. In this paper, linear flow from a fractured well in tight/shale gas reservoir under a constant flowing pressure constraint is studied. It is shown that the slope of square root-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure and formation compressibility. An analytical method is presented to correct the slope of the square root-time plot to eliminate the overestimation of fracture half-length. The method is validated using a number of numerically-simulated cases. As expected, the square root-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly-developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully-analytical, results in an improvement in linear flow analysis over previously-presented methods.

Long-term shale gas well performance characteristics are generally not well understood. The ultra-low permeability of shale ensures the continuing presence of pressure transient effects during well production. This makes production forecasting a difficult and non-unique exercise. Conventional methods have proven to be too pessimistic, in many cases, because they assume a depletion-dominated system. Recently, more suitable forecasting methods have been developed that account for long-term transient effects. These methods incorporate a transient model (usually linear flow) which transitions into a conventional boundary-dominated flow model after a prescribed time or upon achieving a certain region of investigation. The underlying concept assumes that once a transition to boundary-dominated flow is observed, depletion will dominate the production going forward. Although this methodology has been successfully applied for a variety of tight gas reservoirs, it may not be the right model for fractured shale gas (and some conventional tight gas) reservoirs. Fractured shale gas reservoirs get their productivity from the stimulated reservoir volume (SRV), which may be quite limited in areal extent but is surrounded by a low-permeability reservoir (matrix). Thus, the mechanism for long-term production includes a late-time transition from depletion of the SRV, back to infinite acting (linear or pseudo-radial) flow. This "return" to infinite acting flow may or may not provide contribution to recoverable reserves within a practical time-frame, but it should be considered nonetheless. In this paper we present a straight forward methodology for determining the major well performance characteristics of fractured horizontal shale gas wells, considering the impact of uncertainty and non-uniqueness. The focus will be on determining the dominant flow regimes and bulk properties from the data, and then defining a suitable, simple reservoir model for production forecasting, using practical experience and all available information. Field examples from the Barnett, Marcellus, and Haynesville shales are included.

No abstract

Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using a square-root-oftime plot, a plot of rate-normalized pressure vs. the square root of time. Linear flow appears as a straight line on this plot, and the slope of this line can be used to calculate the product of fracture half-length and the square root of permeability. In this paper, linear flow from a fractured well in a tight/shale gas reservoir under a constant-flowing-pressure constraint is studied. It is shown that the slope of the square-root-of-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure, and formation compressibility. An analytical method is presented to correct the slope of the squareroot-of-time plot to improve the overestimation of fracture halflength. The method is validated using a number of numerically simulated cases. As expected, the square-root-of-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully analytical, results in an improvement in linear-flow analysis over previously presented methods. Finally, the application of this method to multifractured horizontal wells is discussed and the method is applied to three field examples.

Shales and some tight gas reservoirs have complex, multi-model pore size distributions, including pore sizes in the nanopore range, causing gas to be transported via multiple flow mechanisms through the pore structure. In 1986, Ertekin et al. developed a method to account for dual mechanism (pressure-and concentration-driven) flow for tight formations that incorporated an apparent Klinkenberg gas-slippage factor that is not a constant, which is commonly assumed for tight gas reservoirs. In this work, we extend the dynamic-slippage concept to shale gas reservoirs, for which it is postulated that multi-mechanism flow can occur. Inspired by recent studies that have demonstrated the complex pore structure of shale gas reservoirs, which may include nanoporosity in kerogen, we first develop a numerical model that accounts for multimechanism flow in the inorganic and organic matter framework using the dynamic-slippage concept. In this formulation, unsteady-state desorption of gas from the kerogen is accounted for. We then generate a series of production forecasts using the numerical model to demonstrate the consequences of not rigorously accounting for multi-mechanistic flow in tight formations. Finally, we modify modern rate-transient methods by altering pseudovariables to include dynamic-slippage and desorption effects and demonstrate the utility of this approach with simulated and field cases. The primary contribution of this work is therefore the demonstration of the use of modern rate transient methods for reservoirs exhibiting multimechanistic (non-Darcy) flow. The approach is considered to be useful for analysis of production data from shale gas and tight gas formations as it captures the physics of flow in such formations realistically.