Modelling and Simulation of Reservoir Formation Damage Due to Chemical Precipitation and Particulate Processes

Modelling and Simulation of Reservoir Formation Damage Due to Chemical Precipitation and Particulate Processes
Chapter One

Objectives  

The objectives of this work are as follows:

1. To develop a mathematical model for the simulation of formation damage due to chemical precipitation and particulate processes in two-phase flow of oil and water.
2. To obtain the numerical simulation of the developed model.
3. To compare the results obtained from the simulation with real experimental data

CHAPTER TWO

LITERATURE REVIEW

Formation damage is an undesirable operational and economic problem that can occur during various phases of oil and gas recovery from subsurface reservoirs including production, drilling, hydraulic fracturing, and workover operations. Formation damage assessment, control, and remediation are among the most important issues to be resolved for efficient exploitation of hydrocarbon reservoirs. Such damage is caused by various adverse processes, including chemical, physical, biological, and thermal interactions of formation and fluids, and deformation of formation under stress and fluid shear. Formation damage indicators include permeability impairment, skin damage, and decrease of well performance (Civan, 2000).

Formation damage assessment, control, and remediation are among the most important issues to be resolved for efficient exploitation of hydrocarbon reservoirs (Energy Highlights, 1990). Formation damage is caused by physic-chemical, chemical, biological, hydrodynamic, and thermal interactions of porous formation, particles, and fluids and mechanical deformation of formation under stress and fluid shear. These processes are triggered during the drilling, production, workover, and hydraulic fracturing operations.

Formation damage is not necessarily reversible and what gets into porous media does not necessarily come out. This phenomenon is called “the reverse funnel effect” (Porter, 1989). Therefore, it is better to avoid formation than to try to restore it. A verified formation damage model and carefully planned laboratory and field tests can provide scientific guidance and help develop strategies to avoid or minimize formation damage. Properly designed experimental and analytical techniques, and the modelling and simulation approaches can help understanding, diagnosis, evaluation, prevention, remediation, and controlling of formation damage in oil and gas reservoirs (Civan, 2000).

The consequences of formation damage are the reduction of the oil and gas productivity of reservoirs and noneconomic operation. Therefore, it is essential to develop experimental and analytical methods for understanding and preventing and are/or controlling formation damage in oil and gas bearing formations (Energy Highlights, 1990).

Mechanisms for Formation Damage

The fundamental processes causing damage in petroleum bearing formations are: (1) physicochemical, (2) chemical, (3) hydrodynamic, (4) thermal, and (5) mechanical. The following seven formation damage mechanisms have been discussed in the literature (Civan, 2000).

1. Fluid-fluid incompatibilities, for example emulsions generated between invading oil based mud filtrate and formation water.
2. Rock-fluid incompatibilities, for example contact of potentially swelling smectite clay or deflocculatable kaoinite clay by non-equilibrium water based fluids with the potential to severely reduce near wellbore permeability.
3. Solids invasion, for example the invasion of weighting agents or drilled solids.
4. Phase trapping/blocking, for example the invasion and entrainment of water based fluids in the wellbore region of a gas well.
5. Chemical adsorption/wettability alteration, for example emulsifier adsorption changing the wettability and fluid flow characteristics of a formation.
6. Fines migration, for example the internal movement of fine particulates within a rock’s pore structure resulting in the bridging and plugging of pore throats.
7. Biological activity, for example the introduction of bacterial agents into the formation drilling and the subsequent generation of polysaccharide polymer slimes which reduce permeability.

However, according to Ohen and Civan (1989), the mechanisms by which rock-fluid interactions can lead to permeability damage has been classified into three general categories.

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CHAPTER THREE

MODEL DEVELOPMENT AND NUMERICAL SOLUTION

Model Development

Several causes of petroleum reservoir formation damage have been discussed in the literature. In this chapter a mathematical model to account for various mechanisms causing permeability impairment in petroleum reservoirs is developed considering two-phase flow. The mechanisms considered include fines migration and insoluble scale deposition caused by chemical precipitation reaction. Transport equations of fluid phase flow and particulate matter based on general macroscopic continuity and momentum balance equations are derived. Different fluid-rock interactions are modelled by kinetic laws or empirical relations. Also a correlation relating particle retention to permeability alteration is included to establish a complete formation damage model.

Model Assumptions

Fluid and particulate flow through porous media is governed by the properties of particles, fluids and formations, and flow geometry. The following were the assumptions made for the model formulation:

1. Isotropic formation.
2. Isothermal processes throughout the system.
3. One-dimensional and horizontal flow was considered.
4. Two-phase flow of water and oil occurs in the reservoir.
5. There is no particle transfer at oil-water interface.
6. Solid particles are uniformly suspended in an incompressible fluid.
7. Variations of capillary pressure, relative permeabilities and dispersion coefficient are not considered during formation damage.
8. Single species of Particle is considered whose wettabilty is not altered during formation damage.
9. Interfacial drag force between water and oil phase is neglected.

CHAPTER FOUR

RESULTS AND DISCUSSIONS

The first simulation involved formation damage due to in situ fines migration in two-phase flow as conducted by Sarker (1988). As reported by Liu (1994), Saker’s experiment involved oil flooding to establish connate water saturation. The core was displaced with fresh water which caused formation damage due to in-situ fines migration. Although, in the present model, the injection fluid contains bicarbonates, Liu’s work was still used for validation  because of unavailability of established literature data. The simulation was carried out using the model parameter values as given in Table 4.1. Fig. 4.1 shows the pressure drop and pore volume injected. The pore volume injected was calculated from the porosity variation and core dimensions. A matching trend to some extend was obtained between the present model and that of Liu (1994). There is quite deviation between the two models as the volume of injecting fluid reaches about 0.8 cm³.

CHAPTER FIVE

CONCLUSIONS AND RECOMMENDATIONS

Conclusions

In this work a detailed model for petroleum formation damage due to chemical precipitation and fines migration during two-phase flow was developed. Only calcium carbonate was assumed to be the particulate matter that is formed as a result of the reaction. It is also the only fine attachment that can be dislodged from the solid rock structure. Hydrodynamic force was assumed to be the only factor causing fines mobilisation. For the permeability impairment, only pore body deposition was modelled. Permeability reduction caused by pore throat blocking was not taken into consideration. In general, a macroscopic approach to material and momentum balance was applied to the fluid and particle during the model development. Chemical reaction balance was also taken for the geochemical reaction. Different fluid-rock interactions are modelled by kinetic laws or empirical relations as was done in various literatures. A correlation relating permeability and porosity change was adopted to complete the model.

A numerical method was used for the solution to the model. The model was discretised using finite difference scheme. Thomas algorithm was used as the numerical method for the solution. The simulation was performed using Visual Basic programming language. The simulation results were compared using available models in the literature. Although exact modelling phenomena have not been found in the literature, a reasonable match was found for the various cases considered. A major cause of the mismatch between the present work and literature models is omission of pore throat blocking process in the model development. Never the less, the model was found to be a useful tool for predicting formation damage caused by inorganic deposition and fines migration during two phase flow of oil and water. In fact, it can be said with high degree of confidence that this is the first type of formation damage model that incorporated geochemical reactions and fines migration during two phase flow.

Recommendations

On the basis of findings from this research work, the following further studies are recommended to be carried out.

1. Pore throat blocking which is an essential part of permeability impairment mechanism should be considered in the model development. The effect of salt concentration and pH on particle mobilisation and capture should also be incorporated.
2. The model can be extended to include other types of geochemical reactions such as dissolution and precipitation of alumina-silicate minerals, cation exchange, and crystal growth and nucleation. The effects of organic precipitation should be incorporated too.
3. The model should be modified to include different types of particles. Effect of particle wettability is highly recommended for consideration.
4. The model was developed for one-dimension. Future model should be developed to include reservoir multi-dimensional structure.
5. A parameter estimation technique should be used to determine the model parameters. A well designed laboratory experiment is recommended for the measurement of the system parameters. The results obtained from this experiment are to be compared with the estimated values. Sensitivity analysis of the system parameters should also be carried out with the aim of establishing the most sensitive system parameters which are then ranked.

REFERENCES

• Amaefule, J. O., Kersey, D. G., Norman, D. L., $ Shannon, P. M., “Advances in Formation
• Assessment and Control Strategies” CIM Paper No. 88-39-65., Proceedings of the 39^th Annual Technical Meeting of Petroleum Society of CIM and Canadian Gas Processors Association, June 12-16, 1988, Calgary, Alberta, pp. 16.
• Arshad, S. A., “A Study of Surfactant Precipitation in Porous Media with Applications in Surfactant-Assisted Enhanced Oil Recovery Processes”, PhD dissertation, U. of Oklahoma, Norman, OK (1991).
• Bhuyan, D., Lake, L. W., and Pope, G. A.: “Mathematical Modelling of High-pH Chemical Flooding”, SPE Reservoir Engineering (May 1990) 213-220.
• Briant, S. L. And Buller, D. C., “Formation Damage from Acid Treatments” paper SPE 17597 presented at the SPE International Meeting on Petroleum, Tianjin, China, Nov. 1-4, 1988.
• Chadman, J., Hoff, D., Merino, E., Ortoleva, P., and Sen, A.: “Reactive Infiltration Instabilities” IAM J. Applied Math. (1986) 36, 207-221.
• Chang, F. and Civan, F. “Predictability of Formation Damage by Modeling Chemical and
• Mechanical Processes”, paper SPE 23793 presented at the SPE International Symposium on Formation Damage Control held in Lafayette, Louisiana, Feb. 26-27, 1992. Pp. 1-7.

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