# Factoring Permeability Anisotropy in Complex Carbonate Reservoirs in Selecting an Optimum Field Development Strategy

^{*}

## Abstract

**:**

## 1. Introduction

## 2. Materials and Methods

- (a)
- X-direction$$\mathrm{Fracture}\text{}\mathrm{type}\text{}{\mathrm{k}}_{\mathrm{xf}}=0.8384\xb7{e}^{\left(0.356\xb7\mathsf{\phi}\right)}$$$$\mathrm{Matrix}\text{}\mathrm{type}\text{}{\mathrm{k}}_{\mathrm{xm}}=0.1037\xb7{e}^{\left(0.264\xb7\mathsf{\phi}\right)}$$
- (b)
- Y-direction$$\mathrm{Fracture}\text{}\mathrm{type}\text{}{\mathrm{k}}_{\mathrm{yf}}=0.216\xb7{e}^{\left(0.468\xb7\mathsf{\phi}\right)}$$$$\mathrm{Matrix}\text{}\mathrm{type}\text{}{\mathrm{k}}_{\mathrm{ym}}=0.0725\xb7{e}^{\left(0.273\xb7\mathsf{\phi}\right)}$$
- (c)
- Z-direction$$\mathrm{Fracture}\text{}\mathrm{type}\text{}{\mathrm{k}}_{\mathrm{zf}}=0.2979\xb7{e}^{\left(0.302\xb7\mathsf{\phi}\right)}$$$$\mathrm{Matrix}\text{}\mathrm{type}\text{}{\mathrm{k}}_{\mathrm{zm}}=0.0418\xb7{e}^{\left(0.286\xb7\mathsf{\phi}\right)}$$

_{Wn}—normalised water saturation, S

_{WCR}—critical water saturation, S

_{OWCR}—critical oil saturation, S

_{GL}—gas saturation.

## 3. Results and Discussions

- Model 2 calculations made minimum difference between the options (oil production is 30,000 m
^{3}, watercut is 0.01). - Model 2 calculations indicated notably low watercut performance during development and values at the end of development. Model 2 did not expose flooding risks in higher reservoir porosity and permeability zones, and permeability anisotropy.
- In Model 1 calculations, the difference between the options in terms of cumulative oil production was 145,000 m
^{3}. In terms of watercut at the end of development, the difference was insignificant, while the watercut trends were completely different. Model 1, with allowance for anisotropy, shows that different orientation of horizontal wellbores considerably impacted the cumulative production and watercut. - Model 1 calculations suggested that Option 1, i.e., the orientation of horizontal wellbores along the strike, was a better choice. With the probability of fracture zones and permeability anisotropy, a faster flooding from the injection wells was predicted for the perpendicular wellbore option; there was a substantial risk of the horizontal wellbore heel flooding, which would cause the rapid flooding of wells.

## 4. Conclusions

- -
- three-dimensional parameters reflecting the directivity of fracture intensity distribution in the lateral and vertical strike were integrated into the fluid flow simulation model;
- -
- rock reservoirs in the reservoir volume were classified into fractured and porous;
- -
- permeability–porosity petrophysical correlations describing lateral and vertical anisotropy were plotted for different rock types and factored into the fluid flow model;
- -
- phase permeabilities were differentiated by rock type;
- -
- the fluid flow model was history-matched, the discrepancy in the cumulative oil production not exceeding 5%;
- -
- predicted options for the reservoir development were calculated;
- -
- it was discovered that Model 2 (with no allowance for anisotropy) does not allow reliable estimates of fluid flow processes in a complex carbonate reservoir;
- -
- Model 1 calculations showed Option 1 as the most effective, as it allows the production of 145,000 m
^{3}more oil compared to Option 2.

## Author Contributions

## Funding

## Data Availability Statement

## Conflicts of Interest

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**Figure 1.**Classification of the reservoir in the volume according to the aperture of the distribution of duplex waves: (

**a**) in the X-direction, (

**b**) in the Y-direction, (

**c**) in the Z-direction.

**Figure 2.**Results of x-ray tomography study of rock samples: (

**a**) XY slice; (

**b**) YZ slice; (

**c**) 3D model of pore space.

**Figure 3.**Permeability–porosity correlation: (

**a**) in the X-direction, (

**b**) in the Y-direction, (

**c**) in the Z-direction.

Parameter | Fractures Type (Mean, mD) | Matrix Type (Mean, mD) | t-Test/p-Value | F-Test/p-Value |
---|---|---|---|---|

Permeability (X direction) | 63 | 19 | 2.26/0.02 | 11.4/<0.01 |

Permeability (Y direction) | 38 | 12 | 1.86/0.04 | 4.0/<0.01 |

Permeability (Z direction) | 8 | 22 | −1.92/0.05 | 5.1/<0.01 |

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**MDPI and ACS Style**

Krivoshchekov, S.; Kochnev, A.; Kozyrev, N.; Ozhgibesov, E. Factoring Permeability Anisotropy in Complex Carbonate Reservoirs in Selecting an Optimum Field Development Strategy. *Energies* **2022**, *15*, 8866.
https://doi.org/10.3390/en15238866

**AMA Style**

Krivoshchekov S, Kochnev A, Kozyrev N, Ozhgibesov E. Factoring Permeability Anisotropy in Complex Carbonate Reservoirs in Selecting an Optimum Field Development Strategy. *Energies*. 2022; 15(23):8866.
https://doi.org/10.3390/en15238866

**Chicago/Turabian Style**

Krivoshchekov, Sergey, Alexander Kochnev, Nikita Kozyrev, and Evgeny Ozhgibesov. 2022. "Factoring Permeability Anisotropy in Complex Carbonate Reservoirs in Selecting an Optimum Field Development Strategy" *Energies* 15, no. 23: 8866.
https://doi.org/10.3390/en15238866