Starting Pressure Gradient Research Articles

Crude oil mobility and its controlling factors in tight sand reservoirs in northern Songliao Basin, East China

Abstract Taking tight oil in Gaotaizi and Fuyu oil layers of the Upper Cretaceous Qingshankou Formation in northern Songliao Basin as an example, based on analyses of nuclear magnetic resonance and high pressure mercury injection, experiment methods of supercritical carbon dioxide displacement and extraction are firstly employed to quantify crude oil mobility in tight sand reservoirs with different lithologies and oil contents. The results show that, under the conditions of simulating the Cretaceous Qingshankou Formation in the northern Songliao Basin at a temperature of 76−89 °C and a pressure of 35−42 MPa, the lower limit of the porosity of the movable oil is 4.4%, and the lower limit of the permeability is 0.015×10−3 μm2. The lower limit of the average pore throat radius is 21 nm. On this basis, a classification standard for three types of tight sand reservoirs is proposed. Type I reservoirs are characterized by the movable fluid saturation larger than 40%, the movable oil ratio (ratio of movable oil to total oil) greater than 30% and the starting pressure gradient in the range of 0.3−0.6 MPa/m; Type II reservoirs are characterized by the movable fluid saturation in the range of 10%–40%, the movable oil ratio in the range of 5%–30% and the starting pressure gradient in the range of 0.6–1.0 MPa/m; Type III reservoirs are characterized by the movable fluid saturation less than 10% in general, the movable oil ratio less than 5%, and the starting pressure gradient greater than 1.0 MPa/m. The fluid mobility in tight sand reservoirs is mainly affected by diagenesis and sedimentary environment. Reservoirs with depth lower than 2 000 m are dominated by type I reservoir, whereas those with greater depth are dominated by type I and II reservoirs. Reservoirs in inner delta-front facies are dominated by type I reservoir, whereas those in outer delta-front facies and shore-shallow lacustrine facies are dominated by type II and III reservoirs.

New analytical equations for productivity estimation of the cyclic CO2-assisted steam stimulation process considering the non-Newtonian percolation characteristics

The research course in the estimation of productivity of cyclic steam stimulation wells can be divided into three stages: (a) the mobility of heavy oil in the cold area is neglected, (b) the mobility of heavy oil in the cold area is considered—however, it is Newtonian fluid seepage, and (c) it is conserved as non-Newtonian fluid seepage in the cold area. However, the distribution of the value of starting pressure gradient in the heated area where heavy oil is still non-Newtonian fluid is neglected. In this paper, a new model is developed for productivity estimation of cyclic steam stimulation wells with consideration of the non-Newtonian fluid flow behaviors in the heated area where the temperature is higher than the turning point. New percolation equations are developed based on the new proposed concept of “the transition region” in the heated area. The results show that: (1) when the non-Newtonian fluid characteristic is neglected, the predicted results from the new model match the results from the numerical simulator perfectly, and (2) in oil field, the non-Newtonian fluid characteristic cannot be neglected. When the non-Newtonian fluid characteristic is considered in the model, the average oil production in each cycle can match the filed data better than Yang et al.’s model. This new model laid a basic reference for oil companies and researchers involved in the area when they are designing the well pattern, spacing or estimating the productivity of oil wells.

Numerical simulation of pressure gradient of coalbed gas outburst and migration considering moving boundary

The gas flow model is developed considering effects of gas convection, diffusion and slippage based on pore characteristics of medium and gas seepage theory in order to study the slippage effect and the effect of threshold pressure gradient on gas migration through the coal seam and determine the reasonable diameter of exposed surface. The numerical model was solved using the multiple physical coupling analysis software COMSOL Multiphysics, and good agreement was obtained by comparing the solution of numerical model with measured results. The speed of pressure change is larger when slippage effect is considered than the migration velocity of gas when slippage effect is not considered, and smaller of pressure decreases for the same cross-section. It is also concluded that the gas pressure changes faster in the coal seam, and the gas starting pressure gradient gets lower when the diameter of the exposed surface is larger. The model can be used to analyze the law of gas migration in coal seam and to determine the position of the cracking surface in coal seam effectively.

English

In the traditional well test models, the quadratic gradient term of nonlinear partial differential equation was neglected according to the assumption of slightly compressible fluid, which could lead to error when the well test time was too long. As time went by, the fluid flowing boundary of low permeability reservoirs extended outwards continuously. In order to study the flowing law of low permeability reservoirs with deformed media, the flow model of low permeability reservoirs of deformed media was built, which considered the influence of starting pressure gradient, moving boundary and quadratic gradient term. The numerical solution of the flow model was obtained by the fully implicit finite difference method. The pressure dynamic curves were drawn to analyse the seepage law of different starting pressure gradient, deformed media and moving boundary. The influence of the quadratic gradient term on the pressure dynamic curves was analyzed. The results could help people understand the seepage mechanism of low permeability reservoirs and provide the theoretical basis for exploring the low permeability reservoirs.   Key words: The quadratic gradient term, moving boundary, starting pressure gradient, deformed media, low permeability reservoirs.

The Researches on Reasonable Well Spacing of Gas Wells in Deep and low Permeability Gas Reservoirs

This Gs64 gas reservoir is a condensate gas reservoir which is relatively integrated with low porosity and low permeability found in Dagang Oilfield in recent years. The condensate content is as high as 610g/m3. At present, there are few reports about the well spacing of similar gas reservoirs at home and abroad. Therefore, determining the reasonable well spacing of the gas reservoir is important for ensuring the optimal development effect and economic benefit of the gas field development. This paper discusses the reasonable well spacing of the deep and low permeability gas reservoir from the aspects of percolation mechanics, gas reservoir engineering and numerical simulation. considering there exist the start-up pressure gradient in percolation process of low permeability gas reservoir, this paper combined with productivity equation under starting pressure gradient, established the formula of gas well spacing with the formation pressure and start-up pressure gradient. The calculation formula of starting pressure gradient and well spacing of gas wells. Adopting various methods to calculate values of gas reservoir spacing are close to well testing' radius, so the calculation method is reliable, which is very important for the determination of reasonable well spacing in low permeability gas reservoirs.

Non-linear seepage characteristics and influential factors of water injection in gassy seams

High-pressure water injection, as an approach for the prevention and control of gas- or dust-induced disasters, has been adopted in coal exploitation globally. To further decode the complicated seepage process of water injection in gassy seams, we introduced an experimental approach to uncover the dynamic characteristics of water injection and gas scavenging. We also built a mathematical model describing non-linear seepage of water injection in gassy seams based on experimental data. We then discussed how overburden pressure and coal seam gas pressure affect the starting pressure gradient of water injection. We determined that a hydraulic gradient within coal seams is the major driving source for water injection and gas scavenging. The entire process goes through (1) the initiation of water injection, (2) water-gas coupled seepage and gas scavenging, (3) the saturation of water in fractures and pores and (4) the end of injection. During the priming stage, there exists a starting pressure gradient, which is non-linear, for water flow within a coal seam. The starting pressure gradient soars as overburden pressure increases, which are attributed to the drop in coal seam permeability. Specifically, the starting pressure gradient forms a power exponential function relationship with coal seam permeability, and we thus established a functional relationship between starting pressure gradient and overburden pressure of different embedded depths. Gas pressure can exert an influence on the starting pressure gradient mainly in the following ways: (1) The coal seam absorbs gas, leading to the decline in the coal seam permeability, which allows the starting pressure gradient for water injection to increase; or (2) A high gas pressure is held responsible for a low level of water saturation in pores and fractures, which subsequently leads to the decline of relative water permeability in coal seams. We hope that our research can be of great theoretical support for the improvement of anti-dust techniques and high-pressure water injection approaches for gas drainage.

The new method on gas-water two phase steady-state productivity of fractured horizontal well in tight gas reservoir

Based on a large number of tight gas exploration and development literature researches, it is found that the horizontal drilling technology and fracturing operation are usually used in the tight gas reservoir for its low permeability. Three tasks have been done in this paper. First, we described the characteristics and the flow mechanism of the tight gas reservoirs which are different from the conventional ones and gave a new definition of two phase pseudo pressure. Second, formation stress sensitivity, starting pressure gradient and the interaction of fractures are considered. Equivalent flow resistance was used to establish a model of tight gas steady flow, and a new productivity formula of fractured horizontal well in tight gas reservoir derived by the new flow model. Third, the productivity influence research has been done, which gives the influence degree of different parameters. It is signified that the productivity will increase with the addition of the permeability modulus and decrease with the increase of the water-gas volume ratio. The influence of starting pressure gradient was not very clear and the fractures parameters showed the opposite situation. Therefore optimization design of tight gas reservoir development mode can be improved by the productivity formula and research. Cited as : Li, X., Liang, J., Xu, W., et al. The new method on gas-water two phase steady-state productivity of fractured horizontal well in tight gas reservoir. Advances in Geo-Energy Research, 2017, 1(2): 105-111, doi: 10.26804/ager.2017.02.06

The experimental modeling of gas percolation mechanisms in a coal-measure tight sandstone reservoir: A case study on the coal-measure tight sandstone gas in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

Tight sandstone gas from coal-measure source rock is widespread in China, and it is represented by the Xujiahe Formation of the Sichuan Basin and the Upper Paleozoic of the Ordos Basin. It is affected by planar evaporative hydrocarbon expulsion of coal-measure source rock and the gentle structural background; hydrodynamics and buoyancy play a limited role in the gas migration-accumulation in tight sandstone. Under the conditions of low permeability and speed, non-Darcy flow is quite apparent, it gives rise to gas-water mixed gas zone. In the gas displacing water experiment, the shape of percolation flow curve is mainly influenced by core permeability. The lower the permeability, the higher the starting pressure gradient as well as the more evident the non-Darcy phenomenon will be. In the gas displacing water experiment of tight sandstone, the maximum gas saturation of the core is generally less than 50% (ranging from 30% to 40% and averaging at 38%); it is similar to the actual gas saturation of the gas zone in the subsurface core. The gas saturation and permeability of the core have a logarithm correlation with a correlation coefficient of 0.8915. In the single-phase flow of tight sandstone gas, low-velocity non-Darcy percolation is apparent; the initial flow velocity (Vd) exists due to the slippage effect of gas flow. The shape of percolation flow curve of a single-phase gas is primarily controlled by core permeability and confining pressure; the lower the permeability or the higher the confining pressure, the higher the starting pressure (0.02–0.08 MPa/cm), whereas, the higher the quasi-initial flow speed, the longer the nonlinear section and the more obvious the non-Darcy flow will be. The tight sandstone gas seepage mechanism study shows that the lower the reservoir permeability, the higher the starting pressure and the slower the flow velocity will be, this results in the low efficiency of natural gas migration and accumulation as well as low gas saturation. The laboratory modeling on gas migration accumulation mechanism in coal-measure tight sandstone can provide a theoretic foundation to reveal the tight sandstone gas enrichment regularity, evaluation of prospecting area, and the study of development mechanism.

The numerical simulation for multistage fractured horizontal well in low-permeability reservoirs based on modified Darcy\u2019s equation

Based on the nonlinear percolation theory, a new nonlinear seepage model of low-permeability reservoir was established and an ideal three-phase and three-dimensional numerical reservoir simulation model for the multistage fractured horizontal well was built. By taking the impacts of pressure-sensitive effect and the threshold pressure gradient into consideration, the quasi-linear numerical model, Darcy numerical model and the non-Darcy numerical model were conducted. Meanwhile, the effects of parameters were fully investigated. The study shows that compared to the results of Darcy model, when taking nonlinear flow into consideration, the result shows higher energy consumption, lower pressure level, smaller liquid production, and slower water cut rising rate. When the injected fluid reaches the wellbore, the flowing bottom hole pressure increases quickly. However, the time of water front reaching the wellbore is different. Hence, when using non-Darcy flow expression, the process can be present precisely. The recovery ratio is positive with the starting pressure gradient of the water phase, but negative with the oil phase. With pressure-sensitive coefficient decreasing, recovery ratio increases quickly. If producing pressure differential is maintained at a proper value, then the effect of the pressure-sensitive coefficient on the permeability is reduced. With the threshold pressure gradient becoming smaller, the recovery ratio becomes higher.

Controlling effect of fractures on gas accumulation and production within the tight sandstone: A case study on the Jurassic Dibei gas reservoir in the eastern part of the Kuqa foreland basin, China

Using Dibei tight sandstone gas reservoir in the eastern part of the Kuqa foreland basin as an example, this paper discusses tight sandstone reservoir fractures characterization, its effect on storage space and gas flow capacity, and its contribution to gas accumulation, enrichment and production in tight sandstone reservoir by using laser scanning confocal microscope (LSCM) observation, mercury intrusion capillary pressure (MICP) testing, and gas-water two-phase relative permeability testing. The statistics of laser scanning confocal microscopy observation showed that the microstructural fractures width in the Dibei gas reservoir was mainly 8–25 μm, and the associated micro-fractures width was mainly 4–10 μm. Additionally, the throat radius was mainly 1–4 μm. The fractures width was significantly wider than the throat radius that served as the main channel of in gas flow. In addition, it illustrated that the samples with developed fractures became easier for gas to flow under equal porosity condition, because of lower expulsion pressure, higher mercury injection saturation, and increased gas relative permeability based on the physical simulation experiment of gas charging into core samples with saturated water, mercury injection and gas-water two-phase permeability experiments. Furthermore, it had been concluded that the fractures control tight gas in the following aspects: (1) Fractures play a significant role in reservoir property improvement. The isolated pores were linked by the fractures to form connective reservoir spaces, and dissolution is prone to occur along the fractures forming new pores. The fractures with bigger width are reservoir space as well. (2) Fractures increased fluid flow capacity because it decreased the starting pressure gradient, and it increased gas effective permeability. Thus, fractures improved the gas injection efficiency as well as gas production. (3) Fractures that developed in different time and spatial places have different effects on gas accumulation, enrichment, and production in tight sandstone reservoirs.

Quantitative characterization of interlayer interference and productivity prediction of directional wells in the multilayer commingled production of ordinary offshore heavy oil reservoirs

Based on the physical experiment of visible multi-tube water flooding, in combination with field production data, the interlayer interference in multilayer commingled production of ordinary offshore heavy oil reservoirs is quantitatively characterized and an appropriate productivity prediction method of directional wells is established for multilayer commingled production of ordinary heavy oil reservoirs. The dynamic relationship of interference coefficients between fluid and oil production indexes is obtained for the multilayer commingled production of ordinary heavy oil reservoirs. The Vandervlis directional well productivity equation is revised by introducing interference coefficient with consideration of starting pressure gradient and a dynamic productivity prediction equation is finally established suitable for multilayer commingled production of ordinary heavy oil reservoirs. Interlayer interference is mainly controlled by vertical reservoir permeability difference, which can be comprehensively characterized by reservoir reference permeability, permeability contrast and permeability deviation. The productivity of wells with different water-cut stages is variously affected by interlayer interference. This influence will be intensified in high water-cut situation, which needs appropriate adjustment measures. The productivity can be more accurately predicted by considering interlayer interference, and the revised directional well deliverability equation can be well applied to field production.

Analysis of transient flow and starting pressure gradient of power-law fluid in fractal porous media

A transient flow model for power-law fluid in fractal porous media is derived by combining transient flow theory with the fractal properties of tortuous capillaries. Pressure changes of transient flow for power-law fluid in fractal porous media are related to pore fractal dimension, tortuosity fractal dimension and the power-law index. Additionally, the starting pressure gradient model of power-law fluid in fractal porous media is established. Good agreement between the predictions of the present model and that of the traditional empirical model is obtained, the sensitive parameters that influence the starting pressure gradient are specified and their effects on the starting pressure gradient are discussed.

致密砂岩储层启动压力与微观孔隙结构关系实验研究

致密砂岩储层是指储层致密(一般渗透率 The tight sandstone reservoir refers to the reservoir density (generally permeability under 0.1 × 10−3 μm2), which can only get sandstone reservoir of economic output after fracturing modification. It is one of the main types of unconventional reservoir formed. Compared with the conventional sandstone reservoir, the flow of the fluid follows the law of non-Darcy flow at low speed. Based on the existence of different starting pressure gradients, a large number of experiments show that tight sandstone reservoir starting pressure gradient increases sharply with the decrease of the permeability. The microscopic analysis accordingly shows that tight sandstone pore throat reduces sharply. Giving priority to nanometer scale pore throat ratio, it shows that tight sandstone reservoir percolation characteristics are controlled by the complex microscopic pore structure.

Forecast of fractured horizontal well productivity in dual permeability layers in volcanic gas reservoirs

Abstract In view of the flow particularity of fractured horizontal wells in dual permeability layers in volcanic gas reservoirs, based on the equivalent flowing resistance method and superposition principle, a new productivity forecasting method for fractured open-hole horizontal wells with multi-transverse fractures in volcanic gas reservoirs is established using a new pseudo-pressure function, with the comprehensive effect of gas slippage effect, starting pressure gradient, stress sensitivity effect and turbulence effect in fractures taken into consideration. The simulation results show that in the production process of fractured open-hole horizontal wells, and the starting pressure gradient has the most remarkable impact on gas well productivity, followed by pressure-sensitive effect and turbulence effect. The slippage effect has the lowest influence. Production pressure difference in gas reservoirs with strong pressure-sensitive effect should be reduced. Gas well production increases as the fracture half-length increases. With the increase of fracture number, the increase of gas production slows down, there exists an optimal number of cracks. The factor affecting gas well production most significantly is fracture conductivity capacity. Different gas reservoirs have different optimal fracture conductivity capacity.

The Non-Darcy Flow Mathematic Model with Fluid-Solid Coupled of Fractured Vertical Well Pattern in Thin Inter-Bedded Reservoirs

Thin inter-bedded low permeability reservoir is sand layer alternating with mud layer and seriously longitudinal heterogeneous. Fluid flowing in this reservoir presents non-linear seepage characteristics. The dynamic models of porosity and permeability were deduced by the concept of bulk strain. Based on flow field partition principle, oil flow field of overall fractured cross-row well pattern could be divided into four units. Each unit could be divided into three regions with different flow mechanisms. Considering non-Darcy flow and fluid-solid coupled, a mathematical model was established for overall-fractured well pattern in thin inter-bedded reservoirs. The results show that production of well pattern with fluid-solid coupled effect is less than that without. Production of thin inter-bedded reservoir grows with the increase of the ratio of net pay thickness to gross thickness (NTG). With increasing semi-length of hydraulic fracture, production of overall fractured well pattern increases with decreasing increment. The more starting pressure gradient, the smaller production of well pattern in thin inter-bedded low permeability. When the starting pressure gradient exceeds 0.01MPa/m, it influences the production remarkably.

Optimization of Black Oil Model-CO2 Flooding in Low Permeability Reservoir

This paper mainly studied the influence of starting pressure gradient in CO2flooding. The capillary pressure of low permeability reservoir is much larger than the ordinary reservoir, so that the influence of starting pressure gradient can not be ignored. Since CO2flooding will be widely used in the development of low permeability reservoirs, it is necessary to study the influence of starting pressure gradient. This paper mainly used Runge Kutta Fehlberg Method and Adams Fourth-order Predictor-Corrector to solve the black oil model, which was founded to study the process of CO2flooding. These two methods considered the starting pressure gradient during the CO2flooding, and the influence of reservoir permeability and crude oil density were studied by founding black oil model and use these two methods to solve the model. We have compared the production rate with staring pressure gradient and without starting pressure gradient.

Application and Study on Nonlinear Percolation Area Distribution Range Calculation Method in the Low Permeability Reservoir

Based on the minimum start-up pressure gradient have been obtained from experiment, and the relationship between the minimum starting pressure gradient with maximum starting pressure gradient and the throat radius, first put forward the calculating the limit shear stress, then calculating the maximum starting pressure gradient method. Non-linear seepage corresponding to the pressure gradient range are obtained by regression analysis, nonlinear seepage flow in low permeability reservoir distribution area can be derived. Two well group examples of the Bei301 block of Hailaer oilfield, shows that calculating the method of nonlinear seepage flow area is available, and the results can reflect the symmetry oil well production performance, this method has application value. The On the basis of the formula of pressure gradient between oil wells and injection wells, New method to calculate the limit injection production well spacing is proposed. It is of importance for injection production well spacing in oilfield development plan.

Research on Starting Pressure Gradient of Low Permeability Reservoir

Due to the presence of starting pressure of low permeability reservoir, so researching on starting pressure gradient of low permeability reservoir is necessary. while starting pressure gradient is relevant to permeability and porosity, it can be obtained through laboratory experiments¡¢well testing interpretation method¡¢theory derivation combined with practical application method . The result of a large number of laboratory experiments shows: starting pressure is related to permeability .The greater the permeability is, the smaller the starting pressure is. They both present the similar hyperbolic relationship; the greater the viscosity of the oil is, the greater the starting pressure is. In this paper, we get the starting pressure gradient formula through the method of theory derivation combined with practical application, meanwhile we put forward the relationship between starting pressure gradient and permeability, porosity¡¢viscosity .

The Optimal Selection of the Conditions on Testing Starting Pressure Gradient for Tight Sandstone Oil Fields

In order to optimize select the best experimental conditions on testing tight sandstone starting pressure gradient in the laboratory, the advanced equipment of ASF300TMUsed to do experiments of constant pressure injection and constant flow injection under the conditions of two modes: constant confining pressure and constant net confining pressure, the data obtained was analysed in the form of linear regression fitting, obtained four different starting pressure gradient values under the different conditions. The experimental results and test methods were careful analysed and comprehensive evaluated according to each different experimental conditions and combined with the existing theory. The experimental results indicate that constant flow experiment is not suitable for large-scale use in the laboratory because of its longer time consuming under the condition of constant confining pressure mode, and the starting pressure gradient values are often larger, net confining pressure can be controlled more than 11 MPa to reduce experimental error. Under the condition of constant net confining pressure mode, the result is reliable, but it takes time longer too. On the contrary, the experiment of constant pressure injection takes time shorter, and the results are accurate under the mode of constant net confining pressure. But under the mode of constant confining pressure the value is on the high side. Based on the above, the best condition of testing starting pressure gradient for tight sandstone is net confining pressure mode and the fluid injected in the form of constant pressure.

Physical simulation on gas percolation in tight sandstones

Abstract Capillary pressure was tested on 40 matrix cores (in situ permeability: 0.002×10−3–100 ×10−3 μm2) in the Sulige gas field and the pore structure features of different type sands were described finely. Based on the research on the pore structure features, gas percolation experiments were designed under the conditions of homogeneous cores with different permeability, heterogeneous cores and different water saturation, to research the gas percolation laws in tight sand. Nanometer pore throats and microscopic capillary pore throats are the main flow channels for gas in tight sand. Percolation resistance of gas or gas-water in tight sand is far greater than that in conventional sand or medium-high permeability sand. Depletion experiments show that gas percolation resistance is bigger when permeability of dry sandstone is lower than 0.1×10−3 μm2 or permeability of water sand is lower than 1×10−3 μm2, so the starting pressure gradient exists. Water saturation has great effect on gas percolation in sandstones. When water saturation is higher, producing reserves are lower. The starting pressure gradient, calculated by monitoring the pressure values of all test points in depletion experiments of long cores, would be scientific and helpful for forecasting the oil drain radius and evaluating producing reserves.