Carbon Dioxide-Oil Minimum Miscibility Pressure Methods Overview

Abstract

One of the essential parameters in carbon dioxide (CO2) miscible flooding is the minimum miscibility pressure (MMP). Minimum miscibility pressure (MMP) is defined as the lowest pressure at which recovery of oil is (90–92%) at injection (1.2 PV) of carbon dioxide (CO2). The injected gas and oil become a multi-contact miscible at a fixed temperature. Before any field trial, minimum miscibility pressure (MMP) must be determined. This parameter must be determined before any field trial because any engineer needs a suitable plan to develop an injection and surface facilities environment. Estimation of reliable (MMP) maybe by traditional laboratory techniques, but it is very costly and time-consuming. Also, it can rely on various literature (MMP) empirical correlations, but this is not a good strategy because each minimum miscibility pressure (MMP) correlation relates to a unique formation condition.

1. Introduction

Miscible gas injection could enhance light oil reservoirs’ enhanced recovery (EOR) process. Recycling CO₂ into oil formation reservoirs allows good gas storage in subsurface formations; consequently, the oil recovery will improve [1]. Miscible flooding project design mostly depends on his success in the minimum miscibility pressure correct determination [2]. The minimum flooding pressure reached the miscibility point, which is the maximum oil recovery achieved (90–92%) at the lowest pressure during injection (1.2 PV) of carbon dioxide (CO₂) [3]. Incremental oil recovery is negligible at a higher (CO₂) flooding project pressure than the MMP. In addition, recovery will sharply decrease at a pressure lower than MMP [4].

1.1 Importance of the minimum miscibility pressure (MMP)

• Minimum miscibility pressure (MMP) is an essential parameter in any design project of gas injection. At the minimum miscibility pressure (MMP), all oil was recovered within a porous medium of (CO₂).

• When oil and gas are miscible, displacement efficiency will be 100% [5].

1.2 Factors affecting minimum miscibility pressure (MMP)

oil composition, reservoir temperature, and (CO₂) purity effect on minimum miscibility pressure (MMP), where [6]:

• The minimum miscibility pressure (MMP) does not change as methane is present in the reservoir.

• As the oil gravity of oil becomes heavier as minimum miscibility pressure (MMP) increases. So, fields with heavy API are not suitable for carbon dioxide (CO₂)-EOR injection.

• As reservoir temperature is high, minimum miscibility pressure (MMP) is higher.

• Minimum miscibility pressure (MMP) is inversely related to the reservoir oil’s C₅ to C₃₀ summation.

• Minimum miscibility pressure (MMP) does not require methane to propane presence.

2. Methods of estimating (MMP)

There are several experimental, equation of state, and empirical equations for estimating (MMP).

2.1 Experimental methods for estimating minimum miscibility pressure (MMP)

Minimum miscibility pressure (MMP) estimates through several testing methods: slim-tube experiments, rising bubble experiments, multiple-contact experiments, and vanishing interfacial tension experiments [7].

2.1.1 Slim-tube experiment

These experiments are widely accepted experimental methods for estimating minimum miscibility pressure (MMP) because they can repeat the interaction of gas and oil in a one-dimensional porous medium [8]. As a result, that slim-tube experiment can replicate oil and gas interaction in a one-dimensional porous medium. It remains the most reliable method of estimating minimum miscibility pressure (MMP)[9]. The slim-tube basic test is the small-diameter tube packed with an unconsolidated porous medium [3]. It is an idealized medium for carbon dioxide (CO₂) and oil to develop dynamic miscibility [10]. The slim-tube experiment comes close to a one-dimensional displacement due to this large length-to-diameter ratio, thus the isolating of phase behavior affects the efficiency of removal [11]. A slim-tube is a long thin stainless steel-tube that is fifteen-meter, packed with sand or glass beads (commonly, sand packing is 160 to 200 mesh) [12]. The slim schematic-tube appears in Figures 1 and 2.

Figure 1.

Schematic diagram of the slim-tube test setup.

Figure 2.

Actual slim-tube test system.

The slim-tube is saturated with at least two PV light oils at the reservoir temperature. Then the system pressurized gradually to the operating pressure in the backpressure regulator’s presence [3]. It is pressure generally kept constant by a backpressure regulator. Upstream pressure changed with the backpressure regulator as it set [13]. To avoid pressure from one side of the diaphragm in the backpressure regulator from becoming significantly higher than the pressure on the other side and damaging the diaphragm [14]. It was required to pressurize the tube system gradually. Just the required pressure is reached, and the system will be equilibrated under this pressure. The carbon dioxide (CO₂) pressure pump was adjusted a little above the pressure of the backpressure regulator. The carbon dioxide (CO₂) flow rate is 4 to 8cm3/ hr. at a constant rate [15]. The experiment terminated when at least 1.2 PV of carbon dioxide (CO₂) was injected. Effluent flashed to atmospheric conditions, where the flow meter collects separator gas and the separated oil collects in a graduate cylinder. The pump’s initial and final volumes of carbon dioxide (CO₂) were recorded to ensure the pump was not empty. The system was depressurized by venting loading gas gradually. After that, use two PV of methylene chloride in the slim-tube to remove residual oil and be ready for the next experiment [16]. The bubble point pressure of the formation oil must measure before the slim-tube experiment. On these results, the slim-tube test can repeat numerous times at different pressures greater than bubble-point pressure. The injected gas pour volume and oil recovery are recorded in each experiment. After indirect 1.2 gas pore volume, the minimum miscibility pressure (MMP) was observed from recovery data.

As shown in Figure 3 [17].

Figure 3.

Minimum miscibility pressure for (CO₂).

2.1.2 Rising bubble experiment

Christiansen and Haines [18] are the first to introduce the rising bubble experiment as a fast option to the slim-tube test, where it can be measured within one hour. This method consists of eight inches high-pressure crystal clear-tube long packed with oil and set at a definite pressure and temperature. Gas introduces through the way of a needle at the tube bottom, forming a bubble and rising through the column [19]. This method can visually observe the miscibility between a gas bubble and an oil. The disadvantage of this method is significant limitations as not expensive and fast compared to the slim-tube method. This method is unreliable in predicting minimum miscibility pressure (MMP) in condensing drive and condensing/vaporizing gas drive (Mansour and Ragab, 2021) (Figure 4) [18].

Figure 4.

Rising bubble experiment.

2.1.3 Multiple-contact experiment

Multiple-contact experiments can detect minimum miscibility pressure (MMP) definite conditions. A multiple-contact test aims to study the gas and oil injection phase behavior [20]. The multiple-contact test is always on contacts between oil and gas. Oil and gas are mixed in a pressure-volume-temperature (PVT) cell [21]. A single PVT cell uses to make repeated contacts between oil and gas forward or backward. In a forward contract, the equilibrium gas retains after each contact.

In contrast, the equilibrium oil replaces with fresh oil—consequently, the equilibrium gas from the previous stage contacts fresh oil at each stage [22]. Equilibrium oil is retained in a backward connection, and the gas is replaced with new injection gas. The contacts are repeated till no change in the phase composition. These tests are repeated at different pressures until the repeated contacts result in a single phase (as shown visually from the cell window) [23]. The disadvantages of this method are that it can provide useful minimum miscibility pressure (MMP) and phase behavior data for gas floods that are purely condensing or vaporizing. Still, most gas flooding is condensing/evaporating drives, meaning that they have both condensing and drive features, but this makes the results of such experiments less accurate [24].

2.1.4 Vanishing interfacial tension experiment

Rao (1997) planned the vanishing interfacial tension (VIT) test as a technique for defining minimum miscibility pressure (MMP). This method involves a high temperature and pressure cell occupied with the CO₂ injection. A drop of crude oil (about 10% of the cell volume) is introduced through a capillary-tube [25]. It measures the interfacial tension (IFT) between oil and CO₂ injected gas at numerous pressures and a specific temperature. The analyzing data were determined by the shape of the hanging oil drop and the oil and gas densities. The pressure increases by pumping more gas into the cell, and the interfacial tension (IFT) measurement is repeated several times [26]. The minimum miscibility pressure (MMP) is approached by extrapolating the interfacial tension (IFT) plot versus pressures. The disadvantage of this test is that after extending their analysis to a multi-component mixture, and concluding that vanishing interfacial tension (VIT) experiments may not be a dependable method of determining minimum miscibility pressure (MMP) [27]. Among these, all experimental methods, the only known experiment of minimum miscibility pressure (MMP) between oil and injection gas is the slim-tube testing.

The experimental methods for estimating minimum miscibility pressure (MMP) have much money and time-overwhelming disadvantages. But these tests can provide us with useful phase behavior data that can be used to estimate and confirm the reliability of a computational minimum miscibility pressure (MMP) [26].

2.2 Computational method of estimating minimum miscibility pressure (MMP)

Empirical correlations for approximating minimum miscibility pressure (MMP) provide fast and cheap alternatives to experimental methods. It is beneficial for quick screening reservoirs for potential carbon dioxide (CO₂) flooding. Various empirical correlations for estimating minimum miscibility pressure (MMP) have been calculated from regression data analysis of slimtube data [28]. Generally, empirical correlations for the predicting of minimum miscibility pressure (MMP) reservoir temperature, the (C2-C6) content of reservoir fluid, and API (oil gravity) as input parameters [29]. This study includes popular minimum miscibility pressure (MMP) empirical correlations reported in the petroleum literature are included in this study. It can be used as a practical guide for the application of different reservoir oils, such as Cronquist [30], Lee [31], Yelling and Metcalfe [32], Alston et al. [33], Emera and Sarma [34], Liao et al. [35], and Mansour et al. [36].

2.2.1 Cronquist empirical correlation

Cronquist [30] empirical correlation is based on the reservoir temperature, pentane plus (C₅⁺) molecular weight, and volatile oil fraction as (CH4 and N2) for minimum miscibility pressure (MMP) estimation as shown in Eq. (1) [30].

$$\mathrm{MMP}=0.11027+{\left(1.{\text{8T}}_{\mathrm{R}}+32\right)}^{\mathrm{y}}$$E1

where Y = 0.744206 + 0.0011038 × MWTC₅++0.0015279 × Vol.

The experimental data range tested used in this study is as the following:

• The oil gravity (API) ranged from 23.7 to 44 8.

• The temperature ranged from 21.67 to 120.8°C.

• The experimental (MMP) ranged from 7.4 to34.5 MPa.

2.2.2 Lee empirical correlation

Lee [31] predicted a model to estimate minimum miscibility pressure (MMP) using reservoir temperature as input data only by considering carbon dioxide (CO₂) vapor pressure, as shown in Eq.(2). If any reservoir oil’s bubble point pressure (BP) is more than minimum miscibility pressure (MMP), the bubble point pressure (BP) takes as minimum miscibility pressure [31]. The bubble point can be detected from the constant mass study test [37].

$$\mathrm{MMP}=7.3924\times {10}^{\mathrm{b}}$$E2

where b = 2.772−(1519/(492 + 1.8T_R)).

2.2.3 Yelling and metcalfe empirical correlation

Yelling and Metcafe (1980) proposed an empirical correlation for estimating minimum miscibility pressure (MMP) at different reservoir temperatures by using the equation Eq. (3). This correlation is not dependent on oil composition and is based only on reservoir conditions. The empirical correlation of minimum miscibility pressure (MMP) is varied from 15 to 19 Mpa approximately [32].

$$\mathrm{MMP}=\begin{array}{l}12.6472+0.015531\times \left(1.{\text{8T}}_{\mathrm{R}}+32\right)+1.24192\times {10}^{-4}\\ \times {\left(1.{\text{8T}}_{\mathrm{R}}+32\right)}^2–716.9427/\left(1.{\text{8T}}_{\mathrm{R}}+32\right)\end{array}$$E3

The limitation of reservoir temperature data used 35.8 °C < TR < 88.9°C. Suppose the minimum miscibility pressure (MMP) is less than the bubble point pressure (BP) for any sample. The bubble point pressure is taken as the minimum miscibility pressure (MMP) determined by the constant mass study test [38].

2.2.4 Alstonetal et al. empirical correlation

Alston et al. [33] presented an empirical correlation for minimum miscibility pressure (MMP) caused by gas solution in reservoir fluids. The minimum miscibility pressure empirical correlation that is in Eq.(4) was predicted based on carbon dioxide (CO₂) composition stream, light oil fraction (CH4 + N2), reservoir temperature, pentane plus (C₅⁺) molecular weight, and Intermediate oil fraction (C₂ to C₄, H₂S, and CO₂). So, they proposed an impurity factor for predicting minimum miscibility pressure empirical correlation (MMP) by contaminated or en-riched carbon dioxide (CO₂) stream (Alston, Kokolis, and James, 1985).

$$p_{\mathit{CO}2}=1.25\ast {10}^{-7}{\left(1.8t-460\right)}^{1.06}{\left(M_{\mathit{WC}5+}\right)}^{1.78}{\left(\frac{x_{\mathit{vol}}}{x_{\mathit{int}}}\right)}^{0.136}$$E4

Also, suppose the minimum miscibility pressure (MMP) of volatile reservoir oil is fewer than the saturation pressure (BP). In that case, the saturation pressure act as the minimum miscibility pressure (MMP).

2.2.5 Emera and Sarma empirical correlation

Emera and Sarma (2005) presented genetic logarithm (GA)-depending on correlation to predicate minimum miscibility pressure (MMP) as shown in Eq.(5). The input data parameters that are based on this correlation are (C₁ and N₂) volatiles ratio, reservoir temperature, intermediates components (C₂–C₄, H₂S, and CO₂), pentane plus (C₅⁺) molecular weight, and (C₂–C₄, H₂S, and CO₂) [34].

$${\mathit{MMP}}_{\mathit{\text{pure}}}=0.003\ast T^{0.544}{\left({\mathit{MW}}_{C_{5+}}\right)}^{1.006}{\left(Y_{\mathit{VOL}}|Y_{\mathit{INT}}\right)}^{0.143}$$E5

2.2.6 Liao et al. empirical correlation

Liao et al. [35] offered minimum miscibility pressure (MMP) empirical correlation depending on (CH4 + N2) oil fraction, (C₂ to C₄, H₂S, and CO₂) intermediate oil fraction, pentane plus (C₅⁺) molecular weight, and reservoir temperature, as shown in Eq.(6).

$${\mathit{MMP}}_{\mathit{\text{pure}}}=0.003\ast T^{0.544}{\left({\mathit{MW}}_{C_{5+}}\right)}^{1.006}{\left(Y_{\mathit{VOL}}|Y_{\mathit{INT}}\right)}^{0.143}$$E6

This minimum miscibility pressure (MMP) empirical correlation was appropriate for low permeability reservoirs. The characteristics of oil reservoir low permeability must be (vol/yint>1), where the experimental and published data were used in this correlation [35].

2.2.7 Mansour et al. empirical correlation

Mansour et al. [36] proposed a new method for predicting (MMP) of a multi-component volatile oil reservoir. This model used twenty-live crude oil samples to correlate this unique formula with new constants. The data range for using this equation API from 40.5 to 26 and in range temperature from 160 to 246°F. The developed (MMP) equation gives good results to reduce the previous correlations errors, where (E_r) was found to be 0.627%, (E_a) 2.4%, (E_r) 0.627%, (R₂) 94.82% (S), and 2.7%. Consequently, this new model has better accuracy than previous literature correlations, as shown in Eq. (7) [36].

$$\mathrm{Ln}\left(\mathrm{MMP}\right)={\mathrm{\beta }}_0+{\mathrm{\beta }}_1\left(\mathrm{LnT}\right)+{\mathrm{\beta }}_2\left({{\text{LnMWT}}_{\text{C5}}}^{+}\right)+{\mathrm{\beta }}_3\left(\text{yVol}/\text{yint}\right)$$E7

where β₀, β₁, β₂, β₃ are the coefficient values and have the following values 11.222, −0.355, −0.2069, and 0.039, respectively.

Nomenclature

API

American Petroleum Institute, degree

BP

Bubble point(saturation pressure), psi

CO₂

Carbon Dioxide

CMD

Constant Mass Depletion

E_a

Average Absolute percent relative error

E_r

Average percent relative error %

PV

Pore Volume

MMP

Minimum Miscibility Pressure

MW_C5⁺

Molecular weight of pentane plus

R²

Correlation Coefficient

S

Standard deviation

T

Reservoir temperature

y

Mole percentage

y_i

Mole fraction of I component

Subscript

Int

Intermediate

Psi

Pound/square inch

Res

Reservoir

vol

Volatile