Pengcheng Liu

A new mathematical model and experimental validation on foamy-oil flow in developing heavy oil reservoirs

To model foamy-oil flow in the development of heavy oil reservoirs, three depletion experiments were conducted with foamy oil treated as a pseudo-single-phase flow. In this pseudo single phase, dispersed bubbles are viewed as a part of the oil, and the redefined effective permeability varies with the changes of pressure depletion rate, oil viscosity, and gas saturation. A mathematical expression for the effective permeability was developed based on experiments, where the viscosity of foamy oil is assumed to be approximately equal to the saturated oil under equivalent conditions. The compressibility coefficient of foamy oil is treated as a volume-weighted compressibility coefficient of that of oil and gas phases. A new mathematical model for foamy-oil flow was proposed with consideration of foamy-oil supersaturation. To validate the mathematical model, the oil recovery and the production gas-oil ratio (GOR) calculated by the new model, conventional black oil model, supersaturation model and pseudo-bubble-point (PBP) model were all compared with those of the experimental data. The new model provided a substantially improved fit to the experimental data compared with the rest three models, which verifies the suitability of the mathematical model presented for simulating foamy-oil flow in the development of heavy oil reservoirs.

Experimental Study of Key Effect Factors and Simulation on Oil Displacement Efficiency for a Novel Modified Polymer BD-HMHEC

A novel synthetic hydrophobically modified hydroxyethyl cellulose (HEC) using bromododecane (BD) was developed in our previous paper, which we denote as BD-HMHEC. A series of one dimensional core displacement experiments were continually conducted to evaluate the key effect factors on the resistance factor (FR) and residual resistance factor (FRR) of BD-HMHEC solution, including polymer concentration, core permeability and injection rate. Results have shown that BD-HMHEC has higher FR and FRR and has much better oil displacement performance than HEC during oil displacement process. Meanwhile, compared with HEC flooding, the key effects on oil displacement efficiency of BD-HMHEC flooding were investigated, including polymer concentration, injection slug and injection rate. A numerical simulation study has been developed by the Computer Modelling Group (CMG) simulator. Results have shown that BD-HMHEC flooding could cause better oil displacement efficiency than HEC flooding at the same condition. As indicated by one dimensional core displacement experimental results, the further incremental oil recovery of switching to BD-HMHEC flooding could increase by 7.0~8.0% after hydrolyzed polyacryamide (HPAM) flooding. The studies indicate that BD-HMHEC has great potential application during enhanced oil recovery (EOR) processes in oilfields.

Experimental studies on effects of temperature on oil and water relative permeability in heavy-oil reservoirs

A heavy-oil sample derived from a block of Venezuelan oil was used to investigate effects of temperature on relative permeability to oil and water. Measurements of relative permeability were based on one-dimensional core-flow simulated systems using an unsteady-state technique at different temperatures, and then impact rules of temperature dependency were discussed. Both water and heavy oil in cores were reconfigured under the consideration of actual reservoir conditions. Study results suggest that relative permeability is high to oil phase and is very low to water phase, and fluid flow capability is extremely imbalanced between oil and water. As temperature increases, irreducible water saturation linearly increases, residual oil saturation performs a nonlinear decrease, and water saturation exhibits a nonlinear increase at equal-permeability points. The water-wettability of rocks is heightened and overall relative permeability curves shift to the right with increasing temperature; furthermore, two-phase flow area becomes wider and both oil and water relative permeability increases apparently, but the increase ratio of water is less than that of oil.

Experimental study on blocking mechanism of nitrogen foam for enhancing oil recovery in heavy oil reservoirs

ABSTRACT Foam flooding is one of the effective techniques during thermal recovery process in heavy oil reservoir. Nitrogen is generally co-injection with the foaming agent for the generation of foam. However, the mechanism has not been totally understood, thereby requiring further discussion. In this study, a series of sand pack experiments for nitrogen foam steam flooding were designed and conducted. A comparison of influencing factors, including gas-liquid (foaming agent) ratio, permeability, injection scheme, and oil saturation was used to evaluate the stability and blocking mechanisms of foam. The results show that the blocking capacity of the gas-liquid ratio of 1:1 is the greatest in all cases under high-temperature condition. The blocking mechanism of foam is analyzed, which indicates that foam is selective to block larger pores and throats in porous media with high-permeability. And also, the stability of foam becomes worse while meeting oil. This characteristic is favorable for improving the sweep efficiency to enhance oil recovery in developing heavy oil reservoir.

A mathematical model and semi-analytical solution for transient pressure of vertical fracture with varying conductivity in three crossflow rectangular layers:

This paper first describes a mathematical model of a vertical fracture with constant conductivity in three crossflow rectangular layers. Then, three forms of vertical fracture (linear, logarithmic, and exponential variations) with varying conductivity are introduced to this mathematical model. A novel mathematical model and its semi-analytical solution of a vertical fracture with varying conductivity intercepting a three-separate-layered crossflow reservoir is developed and executed. Results show that the transient pressures are divided into three stages: the linear-flow phase, the medium unsteady-flow stage, and the later pseudo-steady-flow phase. The parameters of the fracture, reservoir, and the multi-permeability medium directly influence the direction, transition, and shape of the transient pressure. Meanwhile, the fracture conductivity is higher near the well bottom and is smaller at the tip of the fracture for the varying conductivity. Therefore, there are many more differences between varying conductivity and constant conductivity. Varying conductivity can correctly reflect the flow characteristics of a vertical fractured well during well-test analysis.

Characteristics and quantitative study on gas breakthrough in developing Yaha-2 condensate gas reservoir in Tarim Basin, China

In order to keep the formation pressure be larger than the dew-point pressure to decrease the loss of condensate oil, cyclic gas injection has been widely applied to develop condensate gas reservoir. However, because the heterogeneity and the density difference between gas and liquid are significant, gas breakthrough appears during cyclic gas injection, which apparently impacts the development effects. The gas breakthrough characteristics are affected by many factors, such as geological features, gas reservoir properties, fluid properties, perforation relations between injectors and producers, and operation parameters. In order to clearly understand the gas breakthrough characteristics and the sensitivity to the parameters, Yaha-2 condensate gas reservoir in Tarim Basin was taken as an example. First, the gas breakthrough characteristic of different perforation relations by injecting natural gas was studied, and the optimal relation was achieved by comparing the sweep efficiency. Then, the designs of orthogonal experiments method were employed to study the sensitivity of gas breakthrough to different parameters. Meanwhile, the characteristic parameters, such as gas breakthrough time, dimensionless gas breakthrough time, and sweep volume, were calculated and the prediction models were achieved. Finally, the prediction models were applied to calculate the gas breakthrough time and sweep volume in Yaha-2 condensate gas reservoir in Tarim Basin. The reliability of the model was verified at the same time. Please see the Appendix for the graphical representation of the abstract.

A novel method for calculating the dynamic capillary force and correcting the pressure error in micro-tube experiment

Micro-tube experiment has been implemented to understand the mechanisms of governing microcosmic fluid percolation and is extensively used in both fields of micro electromechanical engineering and petroleum engineering. The measured pressure difference across the microtube is not equal to the actual pressure difference across the microtube. Taking into account the additional pressure losses between the outlet of the micro tube and the outlet of the entire setup, we propose a new method for predicting the dynamic capillary pressure using the Level-set method. We first demonstrate it is a reliable method for describing microscopic flow by comparing the micro-model flow-test results against the predicted results using the Level-set method. In the proposed approach, Level-set method is applied to predict the pressure distribution along the microtube when the fluids flow along the microtube at a given flow rate; the microtube used in the calculation has the same size as the one used in the experiment. From the simulation results, the pressure difference across a curved interface (i.e., dynamic capillary pressure) can be directly obtained. We also show that dynamic capillary force should be properly evaluated in the micro-tube experiment in order to obtain the actual pressure difference across the microtube.