Threshold Pressure Gradient Research Articles

Mathematical model and field application of aqueous phase trapping release

ABSTRACT Aqueous phase trapping (APT) is a kind of mechanical formation damage, which occurs in tight sandstone gas reservoirs. The occurrence of APT has a dramatically adverse effect on the productivity of gas wells due to the decrease of water saturation and gas permeability near wellbore. In this research, a spontaneous imbibition experiment was carried out. The Lucas–Washburn model was used to describe the imbibition behavior. Then, a mathematical model of release judgment conditions was established based on the imbibition model, taking the threshold pressure gradient into consideration. Finally, combined with the two-phase flow mechanism of gas and water, the release time of APT was deduced. This model was used to calculate the releasing time of APT in actual producing wells, and the difference between the actual release time and predicted release time is only 0.1%, which indicates that the model established in this paper can be applied to predicting release judgment condition and release time in tight sandstone gas reservoirs precisely. The proposed model along with the findings of this research can pave the way for the continuous development of water breakthrough wells in tight sandstone gas reservoirs.

Investigation of the impact of threshold pressure gradient on gas production from hydrate deposits

Many hydrate-bearing sediments are featured with unconsolidated argillaceous siltstones, which exist the non-Newtonian flow and threshold pressure gradient due to the high content of clay. In this study, the threshold pressure gradient of hydrate reservoir in the South China Sea is experimentally clarified. The quantitative relationship between it and the reservoir parameters is established. The function of threshold pressure gradient has been added into TOUGH + HYDRATE simulator. Here, site SH2, a candidate for field testing comprising a clayey silt gas hydrate reservoir in the Shenhu area of the South China Sea, was chosen to investigate the effect of threshold pressure gradient on gas production behavior through numerical simulations. The simulation results show that threshold pressure gradient has a significant impact on gas extraction. When the experimental value was applied, the gas production was enhanced unexpectedly, where cumulative gas output doubled in 5 years. The active hydrate dissociating area (gas, water and hydrate coexist) has notably extended, accompanying with the expanding cool zone. Water blockage near well was relieved. However, with the increasing of threshold pressure gradient, propagation of pressure would be restrained seriously. The pressure and hydrate of far-field formations stay “frozen”. The bottom water invasion was weakened.

A Production Performance Model of the Cyclic Steam Stimulation Process in Multilayer Heavy Oil Reservoirs

Cyclic steam stimulation (CSS) is a typical enhanced oil recovery method for heavy oil reservoirs. In this paper, a new model for the productivity of a CSS well in multilayer heavy oil reservoirs is proposed. First, for the steam volume of each formation layer, it is proposed that the total steam injection volume will be split by the formation factor (Kh) for the commingled steam injection mode. Then, based on the equivalent flow resistance principle, the productivity model can be derived. In this model, the heavy oil reservoir is composed of a cold zone, a hot water zone, and a steam zone. Next, using the energy conservation law, the equivalent heating radius can be calculated with the consideration of the steam overlay. Simultaneously, a correlation between the threshold pressure gradient (TPG) and oil mobility is also applied for the productivity formula in the cold zone and the hot water zone. Afterward, this model is validated by comparing the simulation results with the results of an actual CNOOC CSS well. A good agreement is observed, and the relative error of the cumulative oil production is about 2.20%. The sensitivity analysis results indicate that the effect of the bottom hole pressure is the most significant, followed by the TPG, and the effect of the steam overlay is relatively slight. The formation factor can affect the splitting of the steam volume in each layer; thus, the oil production rate will be impacted. The proposed mathematical model in this paper provides an effective method for the prediction of preliminary productivity of a CSS well in a multilayer heavy oil reservoir.

Nonlinear Seepage Mathematical Model of Fractured Tight Stress Sensitive Reservoir and Its Application

A tight reservoir can only have industrial production value after fracturing. After volume fracturing, there are artificial fracturing zones and fracturing unmodified zones composed of a matrix, microfractures, and main fractures. There are also pressure-sensitive effects and nonlinear seepage in the matrix. There is an unsteady channeling flow between the matrix and microfractures and main fractures and a threshold pressure gradient in the matrix. The fluid flow between the three media and the transfer flow between the media are very complex. Aiming at the problem of poor simulation accuracy because the above characteristics of tight reservoir fracturing development are not considered in the current commercial numerical simulation software Eclipse, CMG, and VIP, the triple medium coupling nonlinear mathematical model of tight reservoir fracturing development matrix/microfractures/main fractures was established in this study, and the discrete mathematical model was constructed using the full implicit numerical solution method. The model considered the effects of threshold fracturing gradient and nonlinear seepage on the reverse side of seepage. In terms of pressure-sensitive effect, the latest generalized pressure-sensitive effect calculation model, considering rock physical parameters established by authors, was adopted. In terms of matrix/fracture transfer flow, the nonlinear matrix/fracture transfer flow model considering threshold pressure gradient and pressure-sensitive effect established by authors was adopted. Finally, a tight reservoir numerical simulation software was developed based on a triple medium coupling nonlinear model. The software was used to simulate the development effect of turbidite tight reservoir in Wang 587 Block of Jiyang depression, Shengli Oilfield. The results showed that the fitting accuracy of the new model was 13.3% higher than that of Eclipse, and the calculation results were more in line with the production practice of tight reservoirs. The new model established an important theoretical basis for scientifically and effectively guiding the development of tight reservoirs.

Analytical and numerical studies on a moving boundary problem of non-Newtonian Bingham fluid flow in fractal porous media

Non-Darcy flow with a threshold in fractal porous media has been widely used in the development of unconventional petroleum resources such as heavy oil and tight oil. Mathematical modeling of such challenging “threshold flow” problems with strong nonlinearity has great significance in improving petroleum science and technology. Based on a fractal theory, a new non-Darcy kinematic equation with a fractal threshold pressure gradient (TPG) is mathematically deduced in order to describe the non-Darcy flow of a non-Newtonian Bingham fluid with a threshold in fractal porous media. Then mathematical modeling of planar radial non-Darcy flow in a fractal heavy oil reservoir is performed as a nonlinear moving boundary problem. In addition, a steady analytical solution method and a transient numerical solution method are developed. The analytical solution of an ordinary differential equation system for a simple steady model is derived directly, and the transient numerical solution of a partial differential equation system for an unsteady flow model is obtained based on the finite element method with good convergence. These two model solutions are validated by cross-comparisons. It is found from the calculation results that for the steady state, the extremely disturbed moving boundary and its corresponding pressure distribution are affected only by a TPG, production pressure, and a transport exponent; by contrast, for the unsteady state, the moving boundary and its corresponding pressure distribution are affected by many more factors including the fractal dimension. Furthermore, neglect of the fractal TPG and the induced moving boundary can lead to high overestimation of well productivity.

Experimental Study of the Flow Mechanism of Deep Lacustrine Carbonate Reservoirs in the Yingxi Area of the Qaidam Basin

Many of the exploration and development theories derived for conventional clastic rock reservoirs are not applicable to pore-fracture lacustrine carbonate reservoirs. The fluid flow mechanisms under reservoir conditions are still unclear. Therefore, in this study, the rock samples were characterized using X-ray diffraction (XRD), porosity-permeability analysis, scanning electron microscopy (SEM), plain thin sections, and casting thin sections. The core samples were classified into two types (fractures and matrix pores) based on their reservoir spaces. The core flow experiments were performed under reservoir conditions using reservoir core plugs. The experimental results demonstrate that the cores, especially the fractured cores, have a strong stress sensitivity. The oil phase flow in the core has the characteristics of non-Darcy flow, and the threshold pressure gradient is 0.01–0.003 MPa/m. Additionally, for the oil-water two-phase flow in the fractured core, the water phase relative permeability of the residual oil is high. In contrast, the water phase relative permeability of the matrix core is less than 0.2. The nuclear magnetic resonance (NMR) transverse relaxation time ( T 2 ) spectra were used to analyze the differences between the water flooding characteristics of the two pore structures. The experimental results show that the peaks of the T 2 spectra after water flooding are lower than those before water flooding, and the matrix cores have a better oil displacement effect. The relaxation time of 0.1–10 ms makes the greatest contribution to the water flooding efficiency. The micropores smaller than 10 μm in diameter play an important role in the water flooding of the matrix core. These results will provide theoretical basis for solving the difficult problems of developing deep lacustrine carbonate reservoirs.

Productivity model with mechanisms of multiple seepage in tight gas reservoir

The productivity model with unilateral threshold pressure gradient, real gas effect or non-Darcy effect has been documented in the research of tight gas reservoir. However, the multiple seepage mechanisms are poorly addressed in a productivity model, especially the application of gas-water relative permeability curve changing with the displacement pressure. A novel productivity model of multi-stage fractured horizontal wells with mechanisms of multiple seepage was proposed the present study. Results show that the stress effect has a negative effect on the effective permeability, while the Knudsen diffusion effect of gas has a positive effect. The water flow can inhibit the gas flow in the tight gas reservoir, whose effect is more significant with larger displacement pressure differences. The higher initial water saturation and reservoir temperature, whereas the lower gas well productivity, contribute to a high gas well productivity in the reservoir of high pressure.

Study on the Effect of Threshold Pressure Gradient on Remaining Oil Distribution in Heavy Oil Reservoirs

Due to the spatial network structure, heavy oil has a high threshold pressure gradient when it flows through porous media, and the threshold pressure gradient plays a crucial role in the distribution of remaining oil. In previous study, the common methods to measure the threshold pressure gradient include the microflow-established differential pressure (MFEDP) method, capillary equilibrium method, and the percolation curve fitting method. In this study, a sample from the SZ36-1 oilfield was analyzed for the basic physical properties based on the comparison of the previous measurement to study the influence of mobility on the threshold pressure gradient and then an independently developed numerical simulator was established to study the effect of the threshold pressure gradient on the remaining oil distribution considering the permeability range, crude oil viscosity, well network deployment, well spacing, and fluid recovery rate. The results show that the SZ36-1 oilfield fluid belongs to Bingham fluids with yield stress and the mobility having an exponent relation to the threshold pressure gradient based on the measurement of the MFEDP method. Considering the threshold pressure gradient of heavy oil, the uneven distribution of remaining oil is intensified and the remaining oil is enriched. This study provides a reference for efficient development of heavy oil reservoirs.

Threshold pressure experiment of liquid flows through nanochannels and tight cores

Compared with low-permeability oil reservoirs, tight oil reservoirs have more nanopores, complex pore structure, and more obvious nonlinear seepage characteristics. Under the macro-scale channel flow, the influence of micro-forces is often ignored, but micro-forces of the micro-nano-scale have become the main factors affecting the flow. The micro-nano-scale flow is different from the macro-scale flow, and the flow requires the force between the fluid and the micro-nano tubes. The article conducts the threshold pressure experiment of nanochannels and cores, and results show that exists a pressure threshold under liquid flows through nanochannels and cores. The influence of the threshold pressure gradient in the micro-nanochannels is analyzed, and it is found that the nature of the fluid and the diameter of the pores affect the threshold pressure of micro the tube; core experiments prove the threshold pressure gradient exists in the core. The main factors affecting the threshold pressure gradient of the core are the permeability of the core and the nature of the experimental fluid.

Division Method and Seepage Law of Seepage Channels in a Tight Reservoir

Tight oil reservoirs are characterized by a low porosity, low permeability, and strong heterogeneity. The macropores, throats, and microcracks in reservoirs are the main seepage channels, which affect the seepage law in the reservoirs. In particular, oil-water two-phase flow in different types of pores requires further study. In this study, two groups of online NMR displacement experiments were designed to study the seepage characteristics of tight oil reservoirs. It was found that the main seepage channels for oil-water two-phase flow are the microcracks, large pores, and throats in the reservoir. The large pores are mainly micron and submicron scale in size. The oil in the small pores is only transferred to the large pores through imbibition to participate in the flow, and there is no two-phase flow. Based on the influence of different pore structures on the seepage law of a tight reservoir, the pores were divided into seepage zones, and a multistage seepage model for tight reservoirs was established. Based on this model, the effects of the imbibition, stress sensitivity, threshold pressure gradient, and Jamin effect on model’s yield were studied. The results show that imbibition is no longer effective after a while. Owing to the stress sensitivity, the threshold pressure gradient, and the Jamin effect, oil production will be reduced. As the parameter value increases, the oil production decreases. The production decreases rapidly in the early stage of mining while decreases slowly in the later stage, exhibiting a trend of high yield in the early stage and stable yield in the later stage.

Numerical study on non-Newtonian Bingham fluid flow in development of heavy oil reservoirs using radiofrequency heating method

Nowadays, development of heavy oil usually demands massive hot water injection and meanwhile produces considerable carbon footprint. Radiofrequency (RF) heating, as a “Non-aqueous” method, has potentials to be a cleaner and efficient way for heavy oil development in near future. In this paper, we presented a novel numerical model for simulating non-Newtonian Bingham fluid flow in heavy oil reservoirs based on RF heating. Compared to previous studies, this paper focuses on issues including: (1) Application of RF heating in heavy oil reservoir; (2) Non-Darcy flow induced by threshold pressure gradient (TPG) of Bingham fluid; (3) Temperature dependent TPG and viscosity; (4) Two-way coupling between non-Darcy flow, transient heat transfer and electromagnetic (EM) field. To incorporate TPG in numerical analyses, an effective method was utilized by modifying the gravitational acceleration vector in Darcy's law. This method was verified with analytical solution. By doing this, the induced moving boundary by TPG can be simulated, and pressure-disturbed area can be determined. Results show that RF heating significantly mitigates the impediment induced by TPG and high viscosity near well. The moving boundary stops motion at around 1000th day of production and the extreme disturbed distance is 63 m. Besides, it is found that no matter whether TPG is considered or not, RF heating has a positive impact on the reservoir development. However, for the production time less than 1000 days, RF heating is more effective when TPG is considered. Finally, we also found it very necessary to incorporate TPG in the simulations to determine optimal well spacing. If TPG is neglected in kinematic equation, the optimal well spacing would be overestimated by over 50%. At the same time, the change of TPG value with temperature cannot be ignored. Otherwise, the optimal well spacing would be underestimated by 15%. This paper reveals the potentials of RF heating method for non-Newtonian Bingham fluid production and provides an alternative way for clean, environmental, and highly efficient development of heavy oil reservoir.

Effects of miscible degree and pore scale on seepage characteristics of unconventional reservoirs fluids due to supercritical CO2 injection

Supercritical CO2 (ScCO2) injection is a potential way to enhance oil recovery (EOR). The displacement effect varies significantly with the difference of miscible degree and pore scale. However, studies in this field are rarely reported. In this paper, relative permeability curves of three miscible types are firstly measured. Interestingly, the ultimate oil recovery of near-miscible flooding is found to be comparative with that of miscible flooding due to the obvious decrease of gas relative permeability under higher residual oil saturation. On this basis, four main zones in the vicinity of oil-ScCO2 contact are divided in view of the multiple contact miscibility mechanism. A new threshold pressure gradient (TPG) considering both pressure sensitivity and oil properties, is proposed as the indicator of the seepage capacity for the reservoir fluids. The seepage resistance of different cores is greatly reduced due to the ScCO2 injection, especially for the permeabilities less than 5 × 10−3 μm2. The modified TPGs decreased exponentially with the increase of mobility indicating that the seepage capacity of reservoir fluids can be enhanced significantly by strong and sufficient interactions of ScCO2 and oil. Thus, CO2 soaking-alternating-gas (CO2-SAG) flooding is proposed and evaluated to verify the importance of contact time and mass transfer.

Study on Deliverability Evaluation of Staged Fractured Horizontal Wells in Tight Oil Reservoirs

At present, the existing deliverability evaluation models mainly consider the impact of specific factors on production, and the description of the complex fracture network structure primarily remains at the stage of an ideal dual-pore medium with uniform distribution. However, this cannot reflect the actual fracture network structure and fluid flow law of fractured horizontal wells. Thus, in this paper, a non-uniform fracture network structure is proposed considering the influence of the threshold pressure gradient and stress sensitivity characteristics on the production performance of horizontal wells. The stress sensitivity and the fractal theory are combined to characterize the permeability of the complex fracture network, and a three-zone compound unsteady deliverability model for staged fractured horizontal wells in tight oil reservoirs is successfully developed. Laplace transformation, perturbation theory, and numerical inversion are applied to obtain the semi-analytical solution of the proposed deliverability model. The reliability and accuracy of the analytical solution are verified by the classical tri-linear flow model and an oil field example. The effects of related influential parameters on the production of horizontal wells are analyzed. The deliverability evaluation method proposed in this paper can provide a theoretical basis for formulating rational development technology policies for tight oil reservoirs.

Threshold pressure gradient for helium seepage in coal and its application to equivalent seepage channel characterization

Seepage is the main gas migration form in coal seam. The experiments in this study show that there exist threshold pressure gradient and low-velocity nonlinear seepage phenomenon when non-adsorbable helium flows in coal briquette. To further explain that from microscopic view, we establish a capillary seepage model and use a new experimental method to characterize the equivalent seepage channel size distribution (ESCSD) of coal under different effective stress conditions (3–48 MPa). The experimental results prove that the ESCSD of coal obeys fractal distribution. The fractal dimensions in this study are in the range of 2.30–3.36, and decrease significantly with the increase of effective stress. Under the condition of effective stress <48 MPa, the seepage channels with size >1 μm in the experimental coal sample always control most seepage discharge (>90%). Based on the theoretically simplified seepage model and the measured threshold pressure gradient for seepage, the relationship between the critical seepage channel size (dcr) of helium in coal and the pressure gradient (∂P/∂L) is obtained, that is, dcr=α∂P/∂L and α is in the range of 0.0024–0.0033 Pa. Note that the critical condition here represents the transition not from flow to no flow but from seepage to diffusion.

Effect of non-Darcy seepage on productivity of tight gas reservoir

In the process of gas reservoir development, with the production of formation fluid, the effective overburden pressure on the rock skeleton of the reservoir increases, and the rock is deformed under compression, which changes the physical properties of the rock (porosity, permeability, etc.), especially the influence on permeability. Stress sensitivity and threshold pressure gradient are important factors for non-linear seepage in tight gas reservoirs. This paper establishes an empirical prediction model through experimental tests and uses numerical simulation to analyze the effects on productivity. The experimental results show that the relationship between stress sensitivity and permeability is exponential, and there is a strong hysteresis effect. The starting pressure gradient of gas presents a power function relationship with water saturation and permeability respectively, and an empirical relationship is established to predict the starting pressure gradient by comprehensively considering the influence of permeability and water saturation. The single well productivity simulation shows that: The effect of starting pressure gradient on gas well development is greater than stress sensitivity. When starting pressure gradient or stress sensitivity is taken into account, the formation average pressure increases relative to each other and the stable production period decreases obviously.

Polymer Flooding in Heterogeneous Heavy Oil Reservoirs: Experimental and Simulation Studies.

Polymer flooding (PF) in heterogeneous heavy oil reservoirs is not only closely related to polymer degradation, but also to non-Newtonian flow. In this paper, both experimental and simulation methods are combined to investigate this type of flooding. Through experiments, the degradation of polymer, rheological properties of fluids, and flow of fluids in porous media were determined. Based on the experimental results, a novel mathematical model was established, and a new PF simulator was designed, validated, and further applied to study the effects of polymer degradation, polymer solution shear thinning, and non-Newtonian flow on PF in heterogeneous heavy oil reservoirs. These experimental results demonstrated that the polymer first-order static degradation rate constant was lower than the polymer first-order dynamic degradation rate constant; the polymer solution and heavy oil were non-Newtonian fluids, with shear thinning and Bingham fluid properties, respectively; and the heavy oil threshold pressure gradient (TPG) in low-permeability porous media was higher than that in high-permeability porous media. All comparison results showed that the designed simulator was highly accurate and reliable, and could well describe both polymer degradation and non-Newtonian flow, with special emphasis on the distinction between polymer static and dynamic degradation and heavy oil TPG. Furthermore, the simulation results verified that polymer degradation, polymer solution shear thinning, and heavy oil TPG all had negative effects on the efficiency of PF in heterogeneous heavy oil reservoirs.

Mathematical Simulation about Gas Transport in a Dual-Porosity Tight Gas Reservoir considering Multiple Effects

Threshold pressure gradient, gas slippage, and stress sensitivity have important effects on the production of a tight gas reservoir. But previous studies only focused on one or two of these effects. In this study, a mathematical model considering these three effects was established to describe gas transport in a dual-porosity tight gas reservoir. Threshold pressure gradient, gas slippage, and stress sensitivity are simultaneously considered in the velocity term of continuity equation which is mainly different from the previous research results. The partial differential equation and definite solution condition are discretized by a central difference method. A finite difference procedure was compiled and applied to solve this numerical model and predict the productivity of a production well in a dual-porosity tight gas reservoir. The difference between the predicted and tested cumulative production is less than 10%, which indicates that the proposed mathematical model can be used to describe the characteristics of gas flow in the dual-porosity tight gas reservoir. Then, gas productivity of five different scenarios considering these effects was compared. Results show that both stress sensitivity and threshold pressure gradient are negatively correlated with gas production, while gas slippage is positively correlated with gas production. Among them, stress sensitivity has the greatest impact on the production of a dual-porosity tight gas reservoir. Overall, these three effects have great influence on the development of the dual-porosity tight gas reservoir, which should be considered in the production prediction.

A New Method for Research on Unsteady Pressure Dynamics and Productivity of Ultralow-Permeability Reservoirs

In the numerous low-permeability reservoirs, knowing the real productivity of the reservoir became one of the most important steps in its exploitation. However, the value of permeability interpreted by a conventional well-test method is far lower than logging, which further leads to an inaccurate skin factor. This skin factor cannot match the real production situation and will mislead engineer to do an inappropriate development strategy of the oilfield. In order to solve this problem, key parameters affecting the skin factor need to be found. Based on the real core experiment and digital core experiment results, stress sensitivity and threshold pressure gradient are verified to be the most influential factors in the production of low-permeability reservoirs. On that basis, instead of a constant skin factor, a well-test interpretation mathematical model is established by defining and using a time-varying skin factor. The time-varying skin factor changes with the change of stress sensitivity and threshold pressure gradient. In this model, the Laplace transform is used to solve the Laplace space solution, and the Stehfest numerical inversion is used to calculate the real space solution. Then, the double logarithmic chart of dimensionless borehole wall pressure and pressure derivative changing with dimensionless time is drawn. The influences of parameters in expressions including stress sensitivity, threshold pressure, and variable skin factor on pressure and pressure derivative and productivity are analyzed, respectively. At last, the method is applied to the well-test interpretation of low-permeability oil fields in the eastern South China Sea. The interpretation results turn out to be reasonable and can truly reflect the situation of low-permeability reservoirs, which can give guidance to the rational development of low-permeability reservoirs.

Surface anchoring mediates bifurcation in nematic microflows within cylindrical capillaries

Capillary microflows of liquid crystal phases are central to material, biological and bio-inspired systems. Despite their fundamental and applied significance, a detailed understanding of the stationary behavior of nematic liquid crystals (NLC-s) in cylindrical capillaries is still lacking. Here, using numerical simulations based on the continuum theory of Leslie, Ericksen, and Parodi, we investigate stationary NLC flows within cylindrical capillaries possessing homeotropic (normal) and uniform planar anchoring conditions. By considering the material parameters of the flow-aligning NLC, 5CB, we report that instead of the expected, unique director field monotonically approaching the alignment angle over corresponding Ericksen numbers (dimensionless number capturing viscous vs elastic effects), a second solution emerges at a threshold flow rate (or applied pressure gradient). We demonstrate that the onset of the second solution, a nematodynamic bifurcation yielding distinct director configurations at the threshold pressure gradient, can be controlled by the surface anchoring and the flow driving mechanism (pressure-driven or volume-driven). For homeotropic surface anchoring, this alternate director field orients against the alignment angle in the vicinity of the capillary center; while in the uniform planar case, the alternate director field extends throughout the capillary volume, leading to reduction of the flow speed with increasing pressure gradients. While the practical realization and utilization of such nematodynamic bifurcations still await systematic exploration, signatures of the emergent rheology have been reported by the authors previously within microfluidic environments, under both homeotropic and planar anchoring conditions.

Numerical Simulation Study on Waterflooding Heavy Oil Based on Variable Threshold Pressure Gradient

The heavy-oil flow in porous media is characterized by non-Darcy law with variable threshold pressure gradient (TPG) due to the large fluid viscosity. However, available analytical and numerical models hardly consider this effect, which can lead to erroneous results. This paper is aimed at presenting an innovative approach and establishing a numerical simulator to analyze the heavy-oil flow behavior with waterflooding. The apparent viscosity of the oil phase and flow correction coefficient characterized by the TPG were applied to describe the viscosity anomaly of heavy oil. Considering the formation heterogeneity, the TPG was processed into a variable related to mobility and the directionality. The discretization and linearization of the mathematical model were conducted to establish a fully implicit numerical model; the TPG value on each grid node was obtained through oil phase mobility interpolation, and then, the Jacobi matrix was reassembled and calculated to solve pressure and saturation equations. The corresponding simulator was thus developed. The pre-/postprocessing module of the simulator is connected to ECLIPSE; then, an efficient algorithm is introduced to realize a fast solution. Results show that considering the TPG will not only reduce the waterflooding area but also reduce the oil displacement efficiency because of aggravating the nonpiston phenomenon and interlayer conflict. The numerical simulation study on the TPG of heavy oil provides theoretical and technical support for the rational development and adjustment of water-driven heavy oil.