CO₂, Water and N₂ Injection for Enhanced Oil Recovery with Spatial Arrangement of Fractures in Tight-Oil Reservoirs Using Huff-‘n-puff

Abstract

Tight oil has been effectively developed thanks to artificial fracture technology. The basic mechanism of effective production through fractures lies in the contact between the fractures (both natural and artificial) and the matrix. In this paper, the natural tight cores from J field in China are used to conduct experimental studies on the different fluid huff-‘n-puff process. A new core-scale fracture lab-simulation method is proposed. Woven metallic wires were attached to the outer surface of the core to create a space between the core holder and core as a high permeable zone, an equivalent fracture. Three different injecting fluids are used, including CO₂, N₂ and water. The equivalent core scale reservoir numerical models in depletion and huff-n-puff mode are then restored by numerical simulation with the Computer Modeling Group—Compositional & Unconventional Reservoir Simulator (CMG GEM). Simulation cases with eight different fracture patterns are used in the study to understand how fracture mechanistically impact Enhanced Oil Recovery (EOR) in huff n puff mode for the different injected fluids. The results showed: Firstly, regardless of the arrangement of fractures, CO₂ has mostly obvious advantages over water and N₂ in tight reservoir development in huff-‘n-puff mode. Through EOR mechanism analysis, CO₂ is the only fluid that is miscible with oil (even 90% mole fraction CO₂ is dissolved in the oil phase), which results in the lowest oil phase viscosity. The CO₂ diffusion mechanism is also pronounced in the huff-‘n-puff process. Water may impact on the oil recovery through gravity and the capillary force imbibition effect. N₂, cannot recover more crude oil only by elasticity and swelling effects. Secondly, the fracture arrangement in space has the most impact on CO₂ huff-‘n-puff, followed by water and finally N₂. The fractures primarily supply more efficient and convenient channels and contact relationships. The spatial arrangement of fractures mainly impacts the performance of CO₂ through viscosity reduction in the contact between CO₂ and crude oil. Similarly, the contact between water in fractures and crude oil in the matrix is also the key to imbibition. In the process of N₂ huff-‘n-puff, the elasticity energy is dominant and fracture arrangement in space hardly to improve oil recovery. In addition, when considering anisotropy, water huff-‘n-puff is more sensitive to it, while N₂ and CO₂ are not. Finally, comparing the relationship between fracture contact area and oil recovery, oil production is insensitive to contact area between fracture and matrix for water and N₂ cases.

1. Introduction

The key dominant feature difference between a tight reservoir and a traditional reservoir lies in the tight pore. The pore throat of the porous medium of the tight reservoir is very narrow, and its movable fluid saturation is very low. The fluid flow requires a higher-pressure gradient through the pore throat (when <50 nm), and the mobility of fluids is poor [1,2,3,4,5,6], so in the development of tight reservoirs, fracturing is a key technology with an indelible contribution to oil production. The main objective of fracturing is to reconstruct the reservoir seepage formation and to achieve the purpose of the effective expansion and development of the fracture through the mechanical mechanism and provide a more efficient and convenient flow channel for the crude oil [2,7]. However, according to the evaluation of the oil production of tight reservoirs both in China and America, the production rate of tight reservoirs decreases rapidly, without a long and stable production period [2,6,8,9,10,11]. Thus, it is difficult to obtain satisfactory oil recovery only relying on the depressurization process even with fracturing.

The tight porous reservoir structure is dense, the pore throat is narrow, and at the nanometer scale, and the fluid flow is also affected by the boundary layer effect. This results in higher-pressure gradients in the flooding process in the matrix that restricts traditional flooding application in tight reservoirs [12,13,14], while with the existence of fractures, the breakthrough of gas/water usually occurs during the tight reservoir flooding process, so the huff-‘n-puff method is considered a promising energy increasing method in tight reservoirs over the depressurization mode.

Many scholars have developed studies on effective displacement of different fluids in tight reservoirs, mainly including gas injection and chemical injection in Bakken tight oil formations [15,16]. Due to the narrow pore throat in tight reservoirs, gas injection, with its lower viscosity and larger injectivity, is considered to be much easier than water injection. CO₂ is one of the most effective injection gases for enhanced oil recovery, and the use of CO₂ to improve the recovery also serves a role of greenhouse gas storage, so it is attracting increasing attention. In the study of the enhanced oil recovery (EOR) by fluid injection, most of the studies focus on the comparison of the miscible process and immiscible process mechanisms [13,14,17,18,19,20,21,22].

In the CO₂ huff-‘n-puff process, CO₂ is first injected into a producer well, then the well is shut off for soaking, finally, the well is reopened for fluids to be produced [23]. Its application to unconventional reservoirs has been investigated by lots of researchers recently [18,24,25,26,27]. The traditional EOR mechanisms of CO₂ are: (1) viscosity reduction, (2) oil swelling, (3) solution gas drive, (4) hydrocarbon extraction by CO₂. The most important operating parameters in CO₂ huff-‘n-puff include injection rate and time, number of cycles, soaking time, and pressure.

Hawthorne et al. [28] explained CO₂ EOR process in tight reservoirs relatively clearly: (1) CO₂ is preferentially injected into the fractures, (2) CO₂ contacts the matrix rock through fractures, (3) CO₂ will further seep into the matrix, dominated by pressure gradients. When CO₂ dissolves in crude oil, the oil swells and its viscosity decreases, (4) oil drains into the fractures under the effect of CO₂, and (5) when the pressure gradient drops, oil transport is dominated by the concentration gradient across the matrix and the fractures.

A considerable number of scholars have also focused on the study of CO₂ in porous media and crude oil mass transfer mechanisms [15,29]. The mechanisms of CO₂ EOR in tight oil reservoirs is considered to be significantly different from those in conventional reservoirs, due to the special petrophysical properties, reservoir fluid thermodynamics, and mass transport mechanisms. Diffusion is considered to be an especially important mechanism affecting gas transportat under tight reservoir conditions, and its effect on enhanced oil recovery of tight oil cannot be neglected based on the core scale experiments.

In addition, experimental results from both 2D core slice and 3D homogeneous core scale models show that diffusion plays a significant role [30]. However, their field scale huff-‘n-puff simulation model showed that convection is considered the dominating mechanism instead of diffusion. Vega carried out CO₂ injection experiments in miscible conditions [31]. The results showed that both diffusive and convective transfer mechanisms were significant.

In addition to CO₂, N₂ was also used to explore the EOR potential in tight reservoirs [32]. Cores from Eagle Ford were used in this research. Similar experiments can also be found in Li and Sheng’s research [33]. The results indicated that oil recovery was improved when the soaking pressure increased. Extending soaking time can also significantly improve oil recovery. In addition, increasing huff-‘n-puff cycles improved oil recovery. After six cycles, the recovery reached 30.99%.

Different from traditional steam huff-‘n-and puff, cold water injection relies on the mechanism of imbibition for oil displacement in water-wet reservoirs in the presence of fractures [34,35]. This requires the rock to be water-wet. To alter the rock wettability, surfactants can be used [36,37,38].

In the extensive study of tight reservoirs, it is also found that the fracture formation process in tight reservoirs is complex and diverse. The fracture form (such as the Figure 1) is mainly influenced by the natural fractures and properties of the reservoir (the parameters of brittleness, modulus of elasticity, etc.) and the distribution characteristics of natural fractures [2,3,7,10,39,40]. The expansion and connection of the fractures occurs both in the plane and three-dimensional direction. The diversity in the fracture expansion and connection leads to the fact that the contact between fractures and matrix is a multi-contact relationship [39]. This undoubtedly increases the difficulty of evaluating the development effect of tight reservoirs, because the fractures are often simplified to simple uniform and single contact surfaces. In the fluid injection process, especially in huff-‘n-puff mode, the mass exchange between crude oil and injected fluid is unavoidably partially ignored due to the lack of multi-contact relationships between fractures and the matrix. Research on the effect of processing under complex fracture conditions has also progressed. In Molero’s research, different types of complex fractures were simulated and the effects of CO₂ huff-‘n-puff evaluated. The results confirmed that the appropriate modeling of fracture geometry plays a critical role in the estimation of the incremental oil recovery. In Meng’s research about imbibition effects, for fractured reservoirs the area of the water-covered-face between the fractures and matrix also had a significant effect on the oil production process. Therefore, the simulation of fractures is essential when evaluating the oil recovery in both depletion and huff-‘n-puff processes [38].

In terms of core scale experiments, cutting cores and then re-splicing them is the most common method for fracturing simulation. By cutting a complete vertical core with a saw or cutter, the core is separated in half. The fracture is then simulated by splicing the two core parts. The disadvantages of this method are usually a large fracture width (2 mm) and a loss of core and single shape of fractures. The cores also cannot be reused. Tovar et al. [30] simulated fractures by surrounding tight cores with glass beads. To prevent the loss of the glass beads, two sandstone plugs were mounted at both ends as filters. This method doesn’t break the cores and keep them reusable. However, the shape of the fracture is still too single, and the whole surrounding space of the core is treated as fracture, so the rationality is questionable. In addition, the spatial arrangement of fractures still cannot be easily simulated in these methods.

On the basis of the established importance of complex fractures for tight oil huff-‘n-puff processes, this research aims to mechanistically understand how complex fractures impact EOR in huff-‘n-puff for different injected fluids. First, indoor core experiments were carried out, and a new fracture simulation method using woven metallic wires was proposed. Then a numerical simulation method was used to perform historical fitting of the experimental results with GMG GEM, which fully considers unconventional fluid flow, composition interaction and the mass transfer mechanism mentioned in fractured tight reservoirs. Three different injecting fluids are used, including CO₂, N₂ and water. Finally, core scale simulation cases with eight different fracture patterns are used in the study to understand how fractures mechanistically impact EOR in huff-‘n-puff for different injecting fluids with a numerical method. Through this research, a more regular understanding of the influence of fracture and matrix distribution relationship on EOR process can be clear. It is of great significance for guiding fracturing construction. When selecting the optimal injected fluids corresponding to spatial arrangement fracture, theoretical support can also be obtained from this study.

2. Methodology

2.1. Experiments

The core plug used in this experiment was from the J Oilfield with a water-wet wettability. Three cores were selected to perform the huff-‘n-puff process with CO₂, water and N₂. For the experimental system, a degassed crude oil is selected, so the weighing method is adopted to measure the amount of oil produced. Then the oil recovery of each round is calculated. The length is 5 cm with a diameter of 2.5 cm. The permeability is about 0.0375 mD, and porosity is 17.5%. Three cores are selected and their properties are listed in

Table 1. Experimental core data.

Core Number	Porosity, %	Gas Permeability, mD	Liquid Permeability, mD
1	0.177513	0.0356	0.02835
2	0.175812	0.03691	0.0304
3	0.173267	0.03994	0.0339
Average	0.175531	0.037483	0.030883

.

In this paper, a new method for the simulation of core-scale fractures was designed. As shown in Figure 2, woven metallic wires attached to the outer surface of the core create a space between the core holder and core as a high permeable zone, equivalent to a fracture. The shape of the metallic cloths can be adjusted to mimic different fracture geometries and relative positions in space. In order to ensure the same fracture area, the same metal meshes were used and the cropped different shaped metal meshes kept at the same weight. The flow chart is shown in Figure 3.

In a specific experimental process, first, we wash, dry and weigh the tight core. The core is saturated with a vacuum saturate. The weight of the core before and after oil saturation is measured separately to determine the weight of oil. Finally, 3.5 mL oil is saturated in the tight core. Then, the core is placed into the core holder. A confining pressure of 30 MPa was applied to the core holder by the hand pump. Then it was saturated with an extra 1.2 mL of oil when initial pressure reached 30 MPa. The viscosity of the oil is 6 mPa·s at 60 °C. The entire system was placed in an incubator at 60 °C. Thus, the core scale tight reservoir system has been simulated using a lab method.

The injection scheme for the huff-‘n-puff process is as follows: first, reduce the core pressure from an initial pressure of 30 MPa to 5 MPa. Then, inject CO₂/N₂/Water until the BHP reaches 40 MPa. The huff-‘n-puff is repeated 12 times. The oil produced in the depletion process and CO₂/N₂ huff-‘n-puff processes can be directly weighed, while in water huff-‘n-puff, the water should be dried before weighing the produced oil.

The lab method can only provide practical oil recovery data. Subjected to laboratory conditions, the internal pressure and saturation, as well as other properties of fluids, are difficult to measure during a core-scale huff-‘n-puff process. Then based on the experimental results, the parameters of relative permeability and fracture permeability are determined by fitting historical experimental data (shown in Figure 4). Finally, the numerical simulation method is used for more detailed analysis and research in the tight core production process.

2.2. Numerical Simulation

2.2.1. Reservoir Simulation Model

To investigate the several mechanism effect on oil recovery, a Cartesian grid model is built in CMG GEM [41] based on the core experiments. The governing equation describing the mass balance of component i in the oil/gas phases is given by the following expression [15], including the cumulative term of component i in the rock and fluid phases, and the convection, dispersion and molecular diffusion term of component i in phase j:

$$\begin{array}{c}\frac{\partial }{\partial t}[(1-\varphi ){\rho }_s{w}_{is}+\varphi {\displaystyle \sum _{j=1}^n{\rho }_j}{S}_j{w}_{ij}]+\overrightarrow{\nabla }·[{\displaystyle \sum _{j=1}^{N_p}{\rho }_j{w}_{ij}{u}_j}-\varphi {\rho }_j{S}_j{K}_{ij}\nabla w_{ij}]-r_i=0,\\ i=1,2,\dots N_c,\\ j=1,2,\dots N_p,\end{array}$$

(1)

where $\varphi$ is the porosity of the tight matrix, ${\rho }_s$ is the density of the tight matrix, ${\rho }_j$ is the density the of j phase, $S_j$ is the saturation of phase j, $w_{is}$ is the fraction of component i that precipitates in the tight matrix rock, $w_{ij}$ is the fraction of component i in the phase j. $r_i$ is the injection or production rate as a source or sink term, $N_p$ is the total number of phases, $N_c$ is the total number of components, $u_j$ is the flow velocity, which is defined based on Darcy’s law as:

$$u_j=\frac{K{k}_{rj}}{{\mu }_j}(\nabla p_j-{\rho }_{j}g)$$

(2)

In particular when both oil and water phases exist, the capillary pressure also has effect on the flow velocity, and the equation is described as:

$$u_w=\frac{K{k}_{rw}}{{\mu }_w}(\nabla p_w+\nabla p_{\mathrm{cow}}(S_{\mathrm{w}})-{\rho }_{w}g)$$

(3)

where K is the formation permeability, $k_{rj}$ is the relative permeability of phase j, $p_j$ is the pressure of phase j, and ${\mu }_j$ is the viscosity of phase j. $K_{ij}$ is the dispersivity coefficient of component i in the phase j,which is defined as:

$$K_{ij}=\frac{D_{ij}}{\tau }+\frac{{\alpha }_l\left|u_l\right|}{\varphi S_l}$$

(4)

where $\tau$ is the tortuosity of the tight matrix, $D_{ij}$ is the diffusion coefficient of component i in phase j, and ${\alpha }_l$ is the dispersity coefficient of fluid j in different directions.

$D_{ij}$ (its units are cm²/s) can be calculated based on the Sigmund correlation [42]. The diffusion in water phase is ignored. The diffusion coefficient $D_{ik}$ is calculated by:

$$D_{ik}=\frac{{\rho }_j^0{D}_{ik}^0}{{\rho }_j}(0.99589+0.096016{\rho }_{jr}-0.22035{\rho }_{jr}^2+0.032674{\rho }_{jr}^3)$$

(5)

where ${\rho }_j^0{D}_{ik}^0$ is the zero-pressure limit of the product of density and diffusivity, which can be calculated by:

$${\rho }_j^0{D}_{ik}^0=\frac{0.001853T^{0.5}}{{\sigma }_{ik}^0{\mathrm{\Omega }}_{ik}R}{(\frac{1}{M_i}+\frac{1}{M_k})}^{0.5}$$

(6)

where $T$ is the absolute temperature (K), ${\sigma }_{ik}^{}$ is the collision diameter (Å), ${\mathrm{\Omega }}_{ik}$ is the collision integral of the Lennard-Jones Potential, $R$ is the universal gas constant, and $M_i$ is the molecular weight of component $i$. These parameters can be calculated by the following equations [43]:

$${\sigma }_i=(2.3551-0.087{\omega }_i)\times {(\frac{T_{ci}}{P_{ci}})}^{1/3}$$

(7)

$${\epsilon }_i={\kappa }_B(0.7915-0.1963{\omega }_i)T_{ci}$$

(8)

$${\sigma }_{ij}=\frac{{\sigma }_i+{\sigma }_j}{2}$$

(9)

$${\epsilon }_{ij}=\sqrt{{\epsilon }_i{\epsilon }_j}$$

(10)

$$T_{ij}^{\ast }=\frac{{\kappa }_{B}T}{{\epsilon }_{ij}}$$

(11)

$${\mathrm{\Omega }}_{ij}=\frac{1.06036}{{(T_{ij}^{\ast })}^{-0.15610}}+\frac{0.19300}{\exp (-0.47635T_{ij}^{\ast })}+\frac{1.03587}{\exp (-1.52996T_{ij}^{\ast })}+\frac{1.76464}{\exp (-3.89411T_{ij}^{\ast })}$$

(12)

where $\omega$ is the acentric factor, $P_c$ is the critical pressure (atm), $T_c$ is the critical temperature (K), $\epsilon$ is the characteristic Lennard-Jones energy and ${\kappa }_B$ is the Boltzmann constant:

$${\kappa }_B=1.3805\times {10}^{-16}ergs/K$$

(13)

${\rho }_{jr}$ is the reduced density, which can be calculated by:

$${\rho }_{jr}={\rho }_j(\frac{{\displaystyle \sum _i^{N_c}{y}_{ij}{V}_{ci}^{5/3}}}{{\displaystyle \sum _i^{N_c}{y}_{ij}{V}_{ci}^{2/3}}})$$

(14)

$V_{ci}$ is the critical volume of component i, $y_{ij}$ is the mole fraction of component i in phase j. Nc is the total number of components. The diffusion coefficient of component i in the mixture $D_{ij}$ is defined as:

$$D_{ij}=\frac{1-y_{ij}}{{\displaystyle \sum _{i\ne k}\frac{y_{ij}}{D_{ik}}}}$$

(15)

In this paper, the core scale reservoir depletion and huff-‘n-puff process were simulated with CMG GEM based on the partial differential equation (PDE) of Equation (1).

2.2.2. Reservoir Model Description

The matrix is rectangular with dimensions of 5 × 2.5 × 2.5 cm (Figure 5). This core is divided into 10 × 5 × 5 gridblocks with dimensions of 0.5 cm × 0.5 cm × 0.5 cm. The matrix is assumed to be homogeneous and isotropic with a porosity of 0.175 and permeability of 0.03 mD. The relative permeability curve inside the matrix is given in Figure 6. Two layers of grid in each direction with dimensions of 0.1 cm × 0.5 cm × 0.5 cm, 0.5 cm × 0.1 cm × 0.5 cm and 0.5 cm × 0.5 cm × 0.1 cm are added to the periphery of the matrix model to serve as the grid space of the fracture, and thus the total number of model grids is 12 × 7 × 7.

The fractures are assumed to be thin highly permeable passages covering the surface of the core sample matrix. These assumptions are experimentally possible as shown in Figure 5. Woven metallic wires attached to the outer surface of the core create space between the core holder and core as a high permeability zone, an equivalent fracture. The shape of the metallic cloths can be adjusted to mimic different fracture geometries and relative positions in space.

Validating the model with experimental data is critical to ensure that the simulation results are correct. In the history matching work, the main adjustment parameters are the relative permeability curves and the fracture permeability. The porosity of the fractures is assumed to be 0.5 and permeability 50 mD through the history fitting of the experimental data. The relative permeability inside the matrix and the fractures are shown in Figure 6 and Figure 7.

The injected fluids for huff-‘n-puff in this paper are CO₂, N₂ and water. The initial oil and water saturations are 0.8/0.2. The initial pressure is 30MPa. The oil viscosity is 6 mPa·s. The CO₂ diffusion coefficient is set based on published simulated and laboratory measurements [15,30,44,45]. Other initial reservoir properties can be found in

Table 2. Basic reservoir properties in the numerical model.

Parameter	Value	Unit
Initial reservoir pressure	30	MPa
Porosity	0.175	-
Oil viscosity	6	mPa·s
Soak pressure	40	MPa
Soak time	45	min
Production time	6	min
Cycle number	12	-
Temperature	60	°C
Initial water saturation	0.2	-
Matrix permeability	0.03	mD
Fracture permeability	50	mD
CO2 diffusion coefficient	0.0005	cm2/s

. The phase behavior of water/oil, water/oil/CO₂, and water/oil/N₂ are modeled with the Peng-Robinson equation of state. Inputs for the EOS model is given in

Table 3. Binary interaction parameters.

Component	CO2	C1	C4	C7	C12	C19	C30	N2
CO2
C1	0.103
C4	0.1317	0.013
C7	0.1421	0.0358	0.0059
C12	0.1501	0.0561	0.016	0.0025
C19	0.1502	0.0976	0.0424	0.0172	0.0067
C30	0.1503	0.1449	0.0779	0.0427	0.0251	0.0061
N2	−0.02	0.031	0	0	0	0	0

and

Table 4. Component properties and composition.

Component	Pc/atm (atm)	Tc (K)	Acentric Factor	Mol. Weight (g/gmole)	Volume Shift	Crit. Volume (m3/kgmole)	Omega A	Omega B	Specific Gravity (SG)	Tb (°C)	Parachor
CO2	72.80	304.20	0.23	44.01	−0.09	0.10	0.46	0.08	0.60	−102.51	126.49
C1	45.24	189.67	0.01	16.21	−0.15	0.09	0.46	0.08	0.35	−161.15	40.38
C4	43.49	412.47	0.15	44.79	−0.09	0.23	0.46	0.08	0.80	−17.09	128.86
C7	37.69	556.92	0.25	83.46	−0.01	0.35	0.46	0.08	0.95	86.79	242.85
C12	31.04	667.52	0.33	120.52	0.06	0.50	0.46	0.08	1.05	176.75	345.92
C19	19.29	673.76	0.57	220.34	0.16	0.89	0.46	0.08	1.30	217.98	593.49
C30	15.38	792.40	0.94	321.52	0.21	1.06	0.46	0.08	1.50	331.76	799.68
N2	33.50	126.20	0.04	28.01	0.00	0.09	0.00	0.00	0.81	−195.75	41.00

. The initial oil components are provided by the J field, and shown in

Table 5. Oil composition in the simulation model.

Competent	Percent/%
ZGLOBALC ‘N2’	1
ZGLOBALC ‘CO2’	0.01
ZGLOBALC ‘C1’	23.79
ZGLOBALC ‘C4’	4.38
ZGLOBALC ‘C7’	11.26
ZGLOBALC ‘C12’	36.18
ZGLOBALC ‘C19’	16.51
ZGLOBALC ‘C30’	7.87
Sum	100

. The well is located at (12,4,4) as indicated in Figure 5. The injection scheme for the huff-n-puff process are as follows: first, depletion and pressure to 5 MPa. Then, inject CO₂/N₂/Water until BHP reaching 40 MPa. Huff-‘n-puff is repeated 12 times.

The relative arrangement of matrix and several fractures are modeled on a core scale with CMG GEM.

Table 6. Settings of fracture contact relationships.

Fracture Pattern		I = 1	I = 10	Remarks
0				Baseline
1				Scattered fracture-1
2				Scattered fracture-2
3				Scattered fracture-3
4				Scattered fracture-4
5				Near well
6				Far well
7				Relationship with Kv and Gravity

lists the core-scale tight oil-reservoirs with the same contact area between fractures and cores, but with different fracture spatial arrangements.

3. Results

3.1. Depletion and Huff-‘n-puff with Different Fluids

3.1.1. Depletion Mode

By comparing the simulation results of the different fracture mode cases (Figure 8), it is found that in the depressurization period, the existence of fractures is significant for the enhanced oil process. With the same contact area between fracture and matrix, the cases with fractures have approximately 18% higher oil recovery than the case without any fracture. Figure 9 shows the pressure distribution in several cases. Without fractures, the pressure drop is not obvious. The pressure change area in the cases with fracture is wider and the pressure drop is more significant, especially in Case-4. This shows that the fractures supply the more efficient and convenient channels and contact relationships.

In the depletion mode, crude oil flows mainly by the pressure drop caused by elastic energy, and there is no contact between other fluids and crude oil in the matrix through fractures. Therefore, in the case of depletion mode, when fractures have the same contact area with spatial arrangement, the obvious difference in oil recovery cannot be observed.

Case-4 represents the most typical contact relationship between horizontal well fracturing artificial fracture and tight matrix without natural fracture. Case-4 is consistent with the experimental scheme. Figure 9 shows that the fracture type in Case-4 has the best pressure spread effect. In the next study, Case-4 is used as the basis for comparing different fluid using huff-‘n-puff.

3.1.2. Comparison of CO₂, N₂ and Water as Injecting Fluids for Huff-n-puff

• Oil recovery comparison

In this part, Case-4 is used to illustrate the mechanisms of using CO₂, N₂ and water for the huff-‘n-puff process. Figure 10 shows the oil recovery factor on surface conditions by using the three different injecting fluids. CO₂ was able to enhance oil recovery by 21% after depletion, water by 13%, and N₂ by 10% so CO₂ has obvious advantages over water and N₂.

• Gas/liquid injection volume

Firstly, injection fluid volume under the reservoir conditions was selected as a comparison index for the injectivity (Figure 11) to evaluate the EOR effect of different fluids.

From the comparison it can be found that the injectivity of N₂ is the highest among the three fluids, but its impact on EOR is the least. CO₂ has the secondary injectivity with the best EOR effect. The injected volume of water is the least, but with a moderate oil recovery.

Then, we also found the relationship between the volume of the accumulative injection of fluid and the oil recovery under the reservoir conditions of different fluids (CO₂, N₂ and water) cannot be satisfactorily correlated (shown in Figure 11a). It shows that that the injectivity is only part of the basis for the EOR effect of fluids. Because of the obvious difference of EOR mechanism among the three fluids, the oil recovery only shows a good linear relationship with cumulative injected volume under reservoir conditions in same fluid cases (shown in Figure 11b–d).

The following is a detailed comparison of EOR processes of different fluids, to analyze how distributions of the fractures mechanistically affect the performance of the three different injectants:

• Viscosity profile and CO₂ concentration in oil phase

To further understand the EOR mechanisms of the three different injecting fluids, the influential factors in oil recovery are examined. One of the most important factors is the viscosity of the oil phase, which is affected by the thermodynamic conditions and oil composition. Figure 12 shows the viscosity of oil phase during the soaking process in the 12th cycle by using the three different fluids. It can be found that the effect of CO₂ on crude oil viscosity reduction is very significant, especially the viscosity of crude oil near the well and near the interface of fractures has the most significant change from the initial 6 mPa·s to about 1 mPa·s. However, N₂ is also mixed as a gas during the contact with crude oil, but there is no obvious viscosity reduction effect. After the water injection, the viscosity of crude oil may even increase to 7.5 mPa·s.

CO₂ is only fluid that is miscible with oil (even at 90% mole fraction with CO₂ in the oil phase as shown in Figure 13, Figure 14 and Figure 15). The solubility of CO₂ results in the lowest oil phase viscosity of the three cases. In contrast, N₂ mainly exists in the gas phase and is much less soluble in the oil phase compared to CO₂. Water does not dissolve in the oil and water mainly enhances oil recovery through capillary force, gravity and elasticity displacement.

Figure 16 shows the produced components of all three cases. CO₂ gives the most incremental C19 and C30 compared to depletion. However, in the water case, more C7 are produced, leaving a deprived heavy mass that causes an increase in the viscosity of the crude oil. N₂ has the least incremental effect on oil components in all carbon number ranges.

• Oil swelling

The mixture of gas and crude oil will cause a volume expansion of crude oil. Figure 17 shows that the volume expansion of crude oil under reservoir conditions is most obvious after CO₂ injection, and N₂ has only a slight expansion effect on oil volume. When injecting water, the oil is compressed and its volume in reservoir condition decreased. Based on the expansion mechanism, CO₂ showed much better displacement performance than N₂ and water.

• Saturation profile and relative permeability profile

Another influential factor is the relative permeability of the oil phase. Figure 18 shows the relative permeability of the oil phase in the same production process in the 12th cycle. Figure 19 shows the oil, water and gas saturations at the same time. It can be seen with similar oil saturation, the relative oil relative permeability in the CO₂ and water case is much higher than the N₂ case. This is a consequence of the much lower relative permeability to liquid with the existence of gas phase. Based on the gas/liquid relative permeability curve, when two-phase flow occurs, the gas flows more easily than the liquid. Because the gas-liquid two-phase flow area is obviously narrower than the oil-water two-phase flow area (Figure 6 and Figure 7).

From the saturation distribution of production stage in Figure 19, it can be seen that for gas huff-‘n-puff, oil saturation in some areas is even higher than that in water huff-‘n-puff. In water huff-‘n-puff, because of the wider two-phase flow area of water and oil, the overall saturation decline area is larger. However, influenced by comprehensive mechanisms, water’s EOR effect is still not as good as CO₂ with viscosity reduction mechanism, but better than N₂.

• CO₂ diffusion

Figure 20 shows that the oil recovery considering the CO₂ diffusion effect at 0.005 cm²/s is 1.42% higher than the cases without considering it. Figure 21 compares the CO₂ global mole fraction distribution profile with and without CO₂ diffusion. From the profile, the matrix grids have higher CO₂ mole fraction with consideration of CO₂ diffusion, which indicates that more CO₂ may enter into the tight matrix from fractures to mix with the crude oil. Therefore, in order to accurately enhance the oil recovery effect of CO₂ in the tight reservoir simulation model, CO₂ diffusion effects cannot be ignored. On the basis of CO₂ diffusion to improve CO₂ EOR, a reasonable value of diffusion coefficient is critical for the reasonable evaluation of oil recovery in CO₂ huff-‘n-puff.

• Capillary imbibition

According to Meng’s research, in the presence of fractures the capillary force can play a role of imbibition, which can also promote the drainage process [39]. In comparison (Figure 22), oil recovery considering the imbibition effect is 1.3% higher than cases without considering it. From the water saturation profile (Figure 23) the matrix grids have higher water saturation with consideration of imbibition, which indicates that more water in the fracture may enter the matrix, and then impact the oil drainage.

• Gravity

Another observation of the water saturation profiles is that water can be imbibed and is subject to density differences in the water case, which can displace more oil towards the fracture. Water is denser than oil, and N₂ is less dense than oil. Aggregation of different phase during the soaking period may affect the performance of huff-‘n-puff as well. By setting the Kv = 1, the permeability anisotropy is eliminated, and the difference between Case-4 and Case-7 is dominated by gravity effects. It can be seen from Figure 24 that the gravity effect is almost negligible in the depletion mode and the gas huff-‘n-puff mode. In water huff-‘n-puff, the oil recovery finally has a difference of 0.95% in Case-4 and Case-7. By comparing the oil saturation profiles of different layers (Figure 25), there are slight differences between top and bottom layers in CO₂ and N₂ huff-‘n-puff, but the differences are not significant. The difference of saturation between top and bottom layers is more obvious in water huff-‘n-puff. Thus, the gravity effect can be neglected in core scale model. Whether there is a significant impact on large size will be verified and discussed in the authors’ later studies.

3.2. Fracture Characteristics

Now that the fundamental mechanisms of huff-‘n-puff by using CO₂, N₂ and water are clear, it is of interest to understand how the distribution of fractures affects their performance in huff-‘n-puff. For different fracture characteristics, the direction of scattered fracture, fracture in end face or lateral face, Scattered pattern of fractures, fracture relative location with well and fracture area are designed to mechanistically understand the impact of fracture characteristics on huff-‘n-puff.

3.2.1. Scattered Pattern of Fractures

It is found that the dispersion characteristics of fractures has little effect on the recovery in N₂ and water huff-‘n-puff. However, it has a great influence on the EOR effect in CO₂ case (Figure 26). When designing a fracture contact relationship, we compared four scattered fracture (Cases-1–4).

In the depletion development mode, the final oil recoveries are not very different. In CO₂ huff-‘n-puff, the oil recovery in Case-4 is the highest. The EOR effect in Case-1 is the worst. It can be seen from the comparison of CO₂ that the more scattered and farther in distance, the better the recovery effect of CO₂ huff-‘n-puff. In N₂ huff-‘n-puff cases, Case-3 and Case-4 are the best. In water huff-‘n-puff cases, Case-4 is the best, followed by Case-3.

By comparing the oil viscosity distribution in different fractures (Figure 27), the fracture type in Case-4 can result in much less oil viscosity in the soaking process, and hence more oil can be produced. Therefore, the oil saturation is much lower in the Case-4 profile (Figure 28).

3.2.2. Direction of Scattered Fracture (with Kv = 0.2)

In this section, Case-4 and Case-7 are used to illustrate the mechanisms of permeability anisotropy by setting fractures in different directions. Figure 29 shows the oil recovery factor effect on surface conditions by using three different injecting fluids with fractures in different directions. The conclusion of this comparison is that permeability anisotropy plays a significant role in the water case (Case-7 is 4.38% higher than Case-4; but gravity has a negligible impact on CO₂ and N₂). The cross section of Cases-4 and -7 in k-j direction is specifically selected for analysis (Figure 30 and Figure 31). From the viscosity comparison (Figure 30), the viscosity reduction area in Case-4 is larger than the area in Case-7.

From the saturation profiles (Figure 31), it can be seen that in Case-4, more water can enter the matrix grid, but in Case-7 less oil can be displaced by water in this type fracture. As in the Kv and gravity effect, in Case-4, the oil recovery is significantly better than in Case-7. The fracture patterns in Cases-4 and -7 represent the typical horizontal well fracture and vertical well fracture. When it is extended to engineering applications, it can be considered that the horizontal well fractures are more effective than the vertical well fracture, and the horizontal fracture well is more suitable for water huff-n-puff. CO₂ huff-n-puff can be used both in horizontal and vertical fracture wells.

3.2.3. Fracture Near Well and Far Well

Due to the high conductivity of the fracture, the crude oil can flow into the well through the fractures, and the difference of oil recovery between the near-well and the far-well cases is small (Figure 32).

Comparing the EOR effects of near-well and far-well fracture in different development modes (Cases-5,6), it can be found that the results are not consistent either. For the depletion period, the far-well fracture (in Case-6) has an advantage over the near-well case (Case-5) by 1% higher oil recovery.

In the CO₂ and N₂ huff-‘’n-puff periods, the oil recovery of the two fracture types are close to each other. In water huff-‘n-puff, the fracture in Case-5 has a higher incremental oil content. In the fourth round, the difference in oil recovery can even reach 3.1%, but in the later rounds, the difference is less than 0.74%.

3.2.4. Fracture Contact Area

Comparing the relationship between fracture contact area and oil recovery (Figure 33), it can be found that in the depletion period, the larger the contact area of the fracture, the higher the oil recovery, but when the contact area is greater than 25, the increase of the oil recovery is obviously slowed down. In the CO₂ huff-‘n-puff, oil recovery is the highest when the contact area is 25. In N₂ and water huff-‘n-puff, there is still not a clear trend between the contact area and oil recovery. Therefore, the contact area is not sensitive for the huff-‘n-puff process based on this research.

3.2.5. Components Analysis

Through the previous comparison of oil recovery, viscosity, phase permeability and mobility, the EOR effect of different fluids in different fracture can be examined and compared macroscopically. In order to analyze the microscopic differences in more detail, we also selected Cases-4, 5 and 8 as the comparison experiments, adding the analysis of EOR produced components of different fluids in different fracture modes.

As can be seen from the figure (Figure 34), the mainly produced crude oil components include C7, C19 and C30. The proportion of C1 and C4 components in crude oil is originally small, and their production amount did not differ significantly between different fractures. First, for C7 analysis, the most component C7 can be produced in water huff-‘n-puff, followed by CO₂, with the least amount of C7 produced during N₂ huff-‘n-puff. For C19 and C30, CO₂ has a better drainage effect on them, followed by water, and N₂ is still the worst. This shows that different fluids have different drainage effects on different oil components. More interestingly, the fracture condition also has an effect on the composition of the components produced. Taking C19 as an example, C19 can be produced much easier in Case-5 in CO₂ huff-‘n-puff. For water, the fracture in Case-8 is more conducive to the production of C19. This indicates that the fracture distribution pattern also has a non-negligible effect on the EOR effect of different fluids.

Finally, it should be noted that the main EOR effect is still due to the fluid. Fractures only provide a more efficient and convenient channel and contact relationship for fluids to exert their EOR effects. Finally, in the fluid selection of tight reservoir EOR huff-‘n-puff, it is necessary to accurately and reasonably evaluate the distribution characteristics of fractures, and select the optimal injected fluid for specific fracture morphology.

4. Conclusions

This paper takes a fractured tight reservoir as the basic research object. Natural tight cores from the J field in China are used to conduct experimental studies on different fluid huff-‘n-puff processes. A new experimental core-level fracture simulation method that is easy to operate and reusable is proposed. Three different injecting fluids are used, including CO₂, N₂ and water. The equivalent core scale reservoir numerical models in depletion and huff-‘n-puff mode are then restored by numerical simulation with CMG GEM. Simulation cases with eight different fracture patterns were used in the detail study to understand how fracture mechanistically impact EOR in huff and puff for different injecting fluids including CO₂, N₂ and water. Finally, the key findings can be summarized as follows:

(1)

In core-scale fractures, a new experimental core-level fracture simulation method that is easy to operate and reusable is proposed. In this method, woven metallic wires are attached to the outer surface of the core to create a space between the core holder and the core as a high permeability zone, equivalent to a fracture. This avoids the defects of single fracture shape, sanding, and difficulty in reusing the core. Different spatial arrangement of fractures can be set up in core-scale experiments.

(2)

Based on the core-scale experiments and numerical simulation analyses, the existence of fractures is significant for the enhanced oil process in tight reservoirs. The presence of fractures not only has a significant effect on the depletion mode, but also has an important effect on the enhanced oil recovery (EOR) performance of the huff-‘n-puff method. After comparison, fracture arrangement in space has most impact on CO₂ huff-‘n-puff, followed by water and finally N₂.

(3)

In the depletion mode, crude oil flows mainly due to the pressure drop caused by elastic energy, and there is no contact between other fluids and crude oil in the matrix through fractures. Therefore, in the case of depletion mode, when fractures have the same contact area with spatial arrangement, the obvious difference in oil recovery cannot be observed.

(4)

CO₂ has more advantages over water and N₂ in tight reservoir with huff-‘n-puff. Through the EOR mechanism analysis, CO₂ is the only fluid that is miscible with oil (even a 90% mole fraction with CO₂ in the oil phase is possible). This solubility of CO₂ results in the lowest oil phase viscosity in the three cases. The CO₂ diffusion mechanism is pronounced. In contrast, N₂ mainly exists in the gas phase and is much less soluble in the oil phase compared to CO₂, however, it still has a certain swelling effect on crude oil. Water does not dissolve in the oil and water mainly enhances oil recovery through capillary force, gravity and elasticity displacement.

(5)

When considering the anisotropy, the direction of fracture will have a greater impact on oil recovery for the water huff-‘n-puff. The conclusion from this comparison is that permeability anisotropy plays a significant role in the water case (Case-7 is 4.38% higher than Case-4; but anisotropy has a negligible impact on CO₂ and N₂).

(6)

When it comes to the relative location between well and fracture, for the depletion development mode, the far-well fracture has an advantage over the near well case by 1% higher oil recovery. In the CO₂ and N₂ huff-‘n-puff modes, the oil recovery of the two fracture types are not much different. In water huff-‘n-puff, the fractures near the well have a better effect on the EOR process.

(7)

The fracture contact area is not sensitive for the huff-‘n-puff process for N₂ and water cases based on this research.

(8)

From analysis of the produced components, CO₂ gives the most incremental C19 and C30 compared to depletion. However, in the water case, more C7 are produced, leaving a depleted heavy mass that causes an increase in the viscosity of the crude oil. N₂ has the least incremental effect oil components for all carbon number ranges.

(9)

Finally, the main EOR effect is mainly applied by the fluid. Fractures only provide a more efficient and convenient channel, and offer a better contact relationship for fluids to exert their EOR effects. In the fluid selection of tight reservoir EOR huff-n-puff, it is necessary to accurately and reasonably evaluate the distribution characteristics of fractures, and select the optimal injected fluid for specific fracture morphology.