Sandstone Oil Reservoirs Research Articles

Controlling factors and predictions of well-connected pore-throat volumes in tight oil sandstones

Oil production from tight oil sandstone reservoirs has achieved success with the aid of hydraulic fracturing and horizontal well drilling technologies. However, approximately 90% of the oil in these reservoirs remains in place, and reservoir evaluation methods are essential for effective enhanced oil recovery. Well-connected pore throats constitute the connections between fractures and micropores in tight oil reservoirs and lead to high oil recovery levels when using enhanced oil recovery (EOR) methods. In this study, geological factors, such as reservoir quality, lithofacies, and oil charging extent, have been investigated, and their relationships with the well-connected pore-throat volume (Sapex) is discussed. Multiple linear regression and support vector machine (SVM) methods were used for Sapex predictions. The results show that the Sapex values increase as the porosity/permeability increase and then show a decrease. For the flow zone indicator (FZI), Sapex first decreases as the FZI increases and then a slight increase. High Sapex values can be present in nearly all lithofacies, except within some small-scale bedding structures. Increased oil saturations may increase the Sapex, but some rocks with no oil shows still have high Sapex values. High Sapex values are mainly present in two cases: (1) Rocks located close to source rocks with high acidic dissolution levels resulting in secondary porosity and authigenic clay contents. (2) Rocks located far from source rocks that have no oil shows and high contents of chlorite cement, which mainly indicate alkaline diagenetic environments. Predictions of Sapex using multiple linear regression and SVM methods indicate that SVM regression is a good method because of the two high Sapex rock types. The production data from wells with different Sapex values show that the Sapex has a large effect on fluid flow properties.

Effect of CO2 flooding in an oil reservoir with strong bottom-water drive in the Tahe Oilfield, Tarim Basin, Northwest China

The dissolution and diffusion of CO2 in oil and water and its displacement mechanism were investigated by laboratory experiment and numerical simulation for Block 9 in the Tahe oilfield, a sandstone oil reservoir with strong bottom-water drive in Tarim Basin, Northwest China. Such parameters were analyzed as solubility ratio of CO2 in oil, gas and water, interfacial tension, in-situ oil viscosity distribution, remaining oil saturation distribution, and oil compositions. The results show that CO2 flooding could control water coning and increase oil production. In the early stage of the injection process, CO2 expanded vertically due to gravity differentiation, and extended laterally under the action of strong bottom water in the intermediate and late stages. The CO2 got enriched and extended at the oil-water interface, forming a high interfacial tension zone, which inhibited the coning of bottom water to some extent. A miscible region with low interfacial tension formed at the gas injection front, which reduced the in-situ oil viscosity by about 50%. The numerical simulation results show that enhanced oil recovery (EOR) is estimated at 5.72% and the oil exchange ratio of CO2 is 0.17 t/t.

Micro-Scale Pore-Throat Heterogeneity of Tight Oil Sandstone Reservoirs and Its Influence on Fluid Occurrence State

Quantitatively characterizing the micro-scale heterogeneity of pore throats in tight sandstone reservoirs is the key to accurately describing the influence of pore structures on fluid occurrence characteristics. In this study, taking the Chang 6 Member of the Yanchang Formation in the Huaqing area of the Ordos Basin as an example, the pore-throat heterogeneity of tight sandstone reservoirs and its influence on the fluid occurrence state have been systematically studied using cast thin section, scanning electron microscope, X-ray diffraction, constant velocity mercury intrusion, and nuclear magnetic resonance tests. The main types of pores developed in the target layer were intergranular pores, followed by feldspar dissolution pores. The radius distribution of the intergranular pores is between 5.0 and 210 μm, with an average value of 50.27 μm. In addition, the pore combination types with the best petrophysical properties are the intergranular pore type, the intergranular-dissolution pore type, and the dissolution-intergranular pore type; the average permeability and porosity are 0.62 mD, 0.40 mD, 0.44 mD, and 12.0, 12.3, 12.3%, respectively. The target sandstones contain four typical T2 relaxation time types. The large-pore-fine-throat combination reservoir has the best petrophysical properties. The larger the pore-throat uniformity value, the more uniform the pore-throat radius, and the greater the reservoir permeability. Therefore, the uniformity of throat development controls the seepage capacity of the tight reservoirs. The movable fluid saturation of different pore types has obvious differences. The movable fluid saturations at the 0.1 and 0.5 μm pore diameters of the macro-pore-fine-throat and macro-pore-micro-throat reservoirs both show an obvious inflection point, and the movable water saturation is higher with a larger throat radius.

Lower limits and controlling factors of the petrophysical properties of coal-measure sandstone oil reservoirs: A case study of the Jurassic Yan’an Formation in the Huanjiang area, Ordos Basin, China

Coal-measure sandstone oil reservoirs of the Jurassic Yan’an Formation in the Ordos Basin, China, have strong heterogeneity. Reservoir quality is the core factor that determines the large-scale accumulation of hydrocarbons. Taking the Yan’an Formation in the Huanjiang area, Ordos Basin, as an example, we have calculated the lower limits of petrophysical properties based on empirical statistics, porosity and permeability intersections, mercury injections and irreducible water analysis, oil tests, oil-bearing property analysis, and distribution functions. In addition, we have investigated the main controlling factors of effective reservoirs in the Yan’an Formation. The results demonstrate that the lower limits of petrophysical properties of the effective reservoir in the Yan’an Formation display a gradually decreasing trend as the depth increases. Furthermore, we have obtained the functions of the lower limits of the petrophysical properties and the depth. Sedimentation and diagenesis have a significant control effect on the quality of reservoirs in the Yan’an Formation. High-quality reservoirs have mainly developed in the sedimentary microfacies of point sand bar and distributary channel sand bodies. The strong compaction and cementation in the diagenesis process are the internal reasons for the poor petrophysical properties of the Yan’an Formation reservoirs. Overall, the effect of compaction on the petrophysical properties of the reservoir is stronger than that of cementation, whereas the secondary dissolution pores significantly improve the petrophysical properties of the reservoir.

Coupling relationship between current in-situ stress and natural fractures of continental tight sandstone oil reservoirs

We have integrated rock mechanics and acoustic experiments, full-wave array acoustic testing, formation microscanner image logging, and hydraulic-fracturing data to evaluate the coupling relationship between current in-situ stress and natural fractures. We used the data of the Yanchang Formation in the DL block of the western Ordos Basin, China, as an example. Our results find that the Yanchang Formation mainly develops high-angle fractures and vertical fractures. Furthermore, the in-situ stress state of the target sandstone strata satisfies [Formula: see text]. Nearly vertical and high-angle fractures are formed in the environment when [Formula: see text] is the maximum principal stress. Therefore, the current in-situ stress state of the target layer matches the induced fractures (longitudinal tensile-induced fractures) and natural fractures. As the buried depth increases, the difference between the horizontal maximum and minimum stresses ([Formula: see text]) has a tendency to first decrease and then increase, and its conversion depth is approximately 2000 m. Natural fractures are not developed in the distributary bay (the lowest horizontal stress area) and the thick sand area in the middle of the main river channel (the largest horizontal stress area). Natural fractures are mainly developed on the two wings of the main channel, and their horizontal stress is approximately 2–4 MPa lower than the central part of the main channel. We determined a correlation between fractures and sedimentary facies, and we have an important reference value for improving the drilling success rate of tight oil reservoirs. Furthermore, our study provides insights into the prediction of fractures and sweet spots for further exploration and hydraulic fracturing activities in the studied area and elsewhere in continental tight sandstone reservoirs.

Comprehensive Evaluation of Rock Mechanical Properties and in-situ Stress in Tight Sandstone Oil Reservoirs

Comprehensive research on reservoir rock mechanics and in-situ stress properties combined with petrophysical experiments, logging models and numerical simulation is an important means to achieve efficient development of tight sandstone oil reservoirs. In this study, a large number of rock mechanics and acoustic experiments, full-wave train array acoustic wave tests, hydraulic fracturing data and three-dimensional finite element simulations were used to study the rock mechanical properties and in-situ stress characteristics of continental tight oil reservoirs in the Yanchang Formation. The results show that under uniaxial conditions, the tight sandstone samples mainly suffer from tensional ruptures. With the increase of confining pressure, the tight sandstone samples undergo obvious shear ruptures. When the confining pressure is loaded to 35 MPa, a typical vertical shear fracture will be formed. The hydraulic fracturing calculation results show that the in-situ stress state of the target layer satisfies σv (vertical principal stress)>σH (maximum horizontal principal stress)>σh (minimum horizontal principal stress). Based on the results of rock mechanics and acoustic tests, we have constructed the dynamic and static mechanical parameter conversion models of tight oil reservoirs and the logging interpretation model of current in-situ stress. Furthermore, the finite element method is used to simulate the three-dimensional structural stress field of the target layer. The simulations show that the horizontal principal stress distribution in the work area is consistent with the applied environmental stress. The σH of the target layer is mainly distributed in 32–50 MPa, and the σh is mainly distributed in 20–34 MPa. Both σH and σh are relatively high in the southern uplift of the work area; among them, σH is usually greater than 44 MPa, and σh is usually greater than 24 MPa. The northern part of the study area developed several grooved areas with relatively low stress values. The regions with high stress values are often distributed in bands, which may be related to the compression caused by the deformation of the strata. For shear stress, left-handed and right-handed regions usually alternate with each other. However, the extent of the left-handed area in the southern uplift area is larger than that of the right-handed area, indicating that the tight oil reservoirs in the study area are mainly affected by left-handed activities.

Water flooding of sandstone oil reservoirs: Underlying mechanisms in imbibition vs. drainage displacement

In this work the effect of wettability in waterfloods of viscous oil is investigated in a combination of experiments in sandpacks and microfluidic chips. Thirty-nine sand-pack flooding experiments were conducted to investigate the effect of core wettability, oil viscosity, and injection velocity on oil recovery to water flooding. An in-line densitometer, installed downstream of the core, was used to record the instantaneous fluid production and help understanding the mechanism of oil displacement in porous media. Additional microfluidic experiments were conducted to understand the mechanism of viscous oil displacement in imbibition vs. drainage.The effect of injection velocity on oil recovery is a strong function of core wettability and oil viscosity. In water-wet systems, below a critical viscosity (∼60 mPa s), increasing injection velocity enhances oil displacement. In more viscous oil systems, injection velocity reduction improves imbibition. This is confirmed through visualization in microfluidic tests. Post breakthrough bypassed oil is produced in the form of low viscosity oil in water emulsion. In oil-wet waterflooding, oil imbibition into the preformed water channels pinches off (snaps-off) some continuous fingers, diverting water to un-swept regions. This temporary channel closure can explain the cyclic pressure build-ups observed oil-wet core flooding experiments. casein oil-wet systems, oil is produced as a series of viscous oil slugs rather than an emulsion.A new dynamic dimensionless time is presented to quantify imbibition time to which imbibition data are well correlated. This number along with the previously presented “viscous drainage number” can quantify different mechanisms responsible for oil displacement in systems of different viscosity ratio, injection velocity, and core wettability. The proposed dimensionless numbers can be used to determine expected viscous oil recovery efficiency in different wettability systems.

Experimental Study on Oil Drop Discharge Behavior during Dynamic Imbibition in Tight Oil Sandstone with Aid of Surfactant

The pore and throat structure of tight oil reservoir cores is complex, and the resistance of oil drop to discharge from the core is very high during dynamic imbibition. Surfactant has good ability in interfacial tension reduction and wettability reversal. It can reduce oil drop discharge resistance and enhance oil recovery effectively during dynamic imbibition in tight reservoirs. Here, we first analyzed the pore throat structure and mineral composition of tight core, and then the oil drop visualization instrument was used to study the discharge behavior of oil drop during dynamic imbibition. The oil drop discharge form was analyzed, and the influence of various factors on the oil drop discharge behavior was explored, and then the dynamic imbibition performance of surfactant in tight cores was obtained. The core throat diameter was mainly distributed in 0.07–1.1 μm, and the hydrophilic mineral content in core reached 50.8%. In the case of fluid flow in fracture, the oil drop discharge from near fracture matrix was faster, and its growth rate in height and width was faster than that without external fluid flow. Within a certain range, with the increase of IFT, the rate of core imbibition increased gradually. When the IFT increased from 0.32 mN/m to 0.59 mN/m, the oil drop rapture time decreased by 66.3%. The growth rate of oil drop discharged from the top and side of the core was faster than that from the bottom surface. Furthermore, it was easier to discharge. With the core thickness reduced by half, the rapture time of oil drop was reduced by 74.7%. For tight reservoirs, hydraulic fracturing can create more fracture surfaces and reduce the size of matrix blocks, which contributes to reduce the oil drop discharge resistance during imbibition and improve the oil recovery. This study provides a basis for surfactant to improve dynamic imbibition and oil production performance of tight sandstone oil reservoir.

Fine Logging Evaluation of Fractures in Continental Tight Oil Sandstone Reservoirs of Yanchang Formation in the Ordos Basin

Fractures are the main seepage channels in tight reservoirs, and they affect the distribution of high-quality reservoirs and the enrichment of hydrocarbons. Fine logging identification of fractures in the strongly heterogeneous continental tight oil reservoirs of the Upper Triassic Yanchang Formation in the Ordos Basin is a hot and difficult point in the field of petroleum geology. In this paper, taking the Yanchang Formation as an example, a fractal model was constructed to identify fractures in tight oil reservoirs using a large number of cores, conventional and micro-resistivity imaging logging data. The results show that high-angle, vertical and bedding fractures are mainly developed in the Yanchang Formation tight sandstones. There is a negative correlation between sand body thickness and fracture development degree. The fracture sensitivity parameters were used to construct a coupled fractal fracture index. The fractal model incorporates logging information from natural gamma, acoustic wave time difference, rock density, and shallow lateral resistivity. In addition, the constructed fracture fractal index realizes the functions of multi-conventional logging information fusion, which can effectively identify fracture development segments in sandstone. According to the statistics, the fracture identification rate is 83.3%. The study also found that with the increase of sandstone brittleness index, the fracture index has a “S” shape increasing trend. Therefore, the content of brittle mineral components in sandstone is an important factor affecting the development degree of natural fractures, and fractures are more likely to occur in high brittle, thin sand bodies. The highly brittle framework minerals have strong stress-supporting capacity, which can keep fractures open by resisting high overlying loads.

Investigation on the microscopic damage mechanism of fracturing fluids to low-permeability sandstone oil reservoir by nuclear magnetic resonance

Hydraulic fracturing has become an essential stimulation treatment for improving the development efficiency of low-permeability oil reservoirs. However, fracturing fluid inevitably causes reservoir damage. This study proposed a combined method of microscopic and macroscopic experiments to investigate the nature of formation damage of fracturing fluid by quantifying its influence on porosity, permeability, and pore structure. Nuclear magnetic resonance technology combined with core flooding test and parallel sample comparison method was applied to quantitatively evaluate the damage degree and identify the main damage types of hydroxypropyl guar (HPG) fracturing fluid and slickwater fracturing fluid. The microscopic damage mechanisms of these fracturing fluids were analyzed by thin section petrography, X-ray diffraction, rate-controlled mercury intrusion, scanning electron microscopy, and wettability tests. The results show that the total permeability damage degree of HPG fracturing fluid filtrate is 30.43%, of which water sensitivity, water lock, and macromolecule adsorption account for 6.06%, 23.26%, and 1.11%, respectively. Water lock is the major damage factor. Regarding the damage of slickwater fracturing fluid filtrate, water sensitivity causes the severest damage, corresponding to 39.08% of core permeability loss, whereas macromolecule adsorption and water lock contribute 13.21% and 0.97%, respectively. Water sensitivity damage causes reduced porosity, decreased permeability, and narrower pores, resulting from hydration, swelling, dispersion and migration of clay minerals. Water lock damage increases the movable pore volume, decreases the permeability, increases the pore radius, decreases the throat radius, and increases the pore throat ratio, which increases the flow resistance to the oil phase. The magnitude of water lock damage is closely related to the surfactant content and performance, rock wettability, and pore throat radius ratio. Macromolecule adsorption damage leads to a decrease in permeability, a reduction in the number of large pores, an increase in the number of small throats, and an increase in the pore throat radius ratio due to the absorption and retention of macromolecules on the surfaces of the pores and throats. Increasing the flowback volume of slickwater fracturing fluid can recover part of the macromolecule absorption damage. This research can provide a reliable reference for the optimization of fracturing fluid performance, enhancement of the fracturing effect and reservoir protection of low-permeability reservoirs.

Identification of distinctions of immiscible CO2 huff and puff performance in Chang-7 tight sandstone oil reservoir by applying NMR, microscope and reservoir simulation

CO 2 huff and puff (HNP) is one of the most effective methods to improve tight oil recovery after the primary depletion process. The seepage mechanisms between CO 2 and crude oil are complicated in porous media during CO 2 HNP process. Therefore, in this paper, the CO 2 HNP process of Chang-7 tight oil reservoir, Ordos Basin, China, was studied by nuclear magnetic resonance (NMR) technology, microscopic observation and numerical simulation. Experimentally, using NMR technology and microscopy methods, the distribution characteristics of residual oil during CO 2 HNP process were measured intuitively. Numerically, a group of core-scale and field-scale simulations considering molecular diffusion and asphaltene precipitation were established to further verify and elongate the experimental results. The results show that at the initial state, the crude oil in the tight core was mainly distributed in nanopores, sub-micro-nanopores and sub-micropores, where the oil content exceeded at least 73% in these pores. During CO 2 HNP process, the oil recovery was more pronounced for the 1st and 2nd rounds than for 3rd to 5th rounds. Notably, even if the cores with more nano-pores were more favorable for the 4–5th CO 2 HNP rounds, the oil molecules in nanopores were still difficult to be available. Moreover, the CO 2 sweep scope could be divided into displacement affected region and diffusion affected region. CO 2 could effectively drive the crude oil in the displacement affected region. While the oil could be successfully displaced by dissolved gas flooding in the diffusion affected region only under the appropriate conditions. Meanwhile, the core-scale numerical models confirmed that it was necessary to consider molecular diffusion and asphaltene precipitation factors, which would make the simulation results in line with the experiment. In terms of the ultimate oil recovery, the field-scale model only considering the diffusion (2.456%) > the model both considering the diffusion and asphaltene (2.436%) > the model without considering the diffusion and asphaltene deposition (2.412%) > the model only considering the asphaltene deposition (2.388%). • The oil were difficult to be available in nanopores due to the nano-constraint effect. • The CO2 displacement area was associated with diffusion and asphaltene precipitation. • SP-T2 spectrum and microscopic image were applied to obtain CO2 sweep scope. • A group of simulations were established to analyse the effect of CO2 sweep scope.

Adsorption Behavior of Asphaltene on Clay Minerals and Quartz in a Heavy Oil Sandstone Reservoir with Thermal Damage

AbstractDifferences in the properties of clay minerals cause formation damage under the condition of thermal production in heavy-oil reservoirs; asphaltenes adsorbed on clay minerals exacerbate the formation damage. The purpose of the present study was to reveal the variation in clay minerals and the adsorption behavior of asphaltenes on clay mineral surfaces under thermal recovery conditions. Volume changes and transformations of typical clay minerals were studied under various conditions (80 and 180°C, pH 9 and 11, aqueous and oven-dry conditions). On this basis, the adsorption behavior and mechanism of asphaltenes on the surfaces of clay minerals in various simulated conditions were investigated. The adsorption mechanism was revealed using kinetics and isothermal adsorption models. The results showed that the volume of montmorillonite expanded by up to 159.13% after water–rock interaction at 180°C with pH 11; meanwhile, the conversion rates of kaolinite and illite to montmorillonite were 6.6 and 7.8%, respectively. The water–rock interaction intensified the volume changes and transformations of clay minerals under thermal conditions. The amounts of asphaltene adsorbed on clay minerals at 180°C were greater than those at 80°C. The adsorption process of asphaltenes was inhibited under aqueous conditions. The abilities of the constituent minerals to bind asphaltenes was in order: montmorillonite > chlorite > kaolinite > illite > quartz sand. The adsorption process of asphaltenes yielded high coefficients of regression with both the Freundlich and Langmuir models under oven-dry (>0.99) and aqueous (>0.98) conditions. At 180°C under aqueous conditions, the water film significantly inhibited the adsorption of asphaltene on the clay minerals. The adsorption process of asphaltenes, therefore, could be regarded as the adsorption occurring at lower concentrations under oven-dry conditions.

Development Characteristics and Finite Element Simulation of Fractures in Tight Oil Sandstone Reservoirs of Yanchang Formation in Western Ordos Basin

Structural fractures have a significant control effect on the large-scale accumulation of hydrocarbons in the Yanchang Formation. Previous studies have affirmed the important role of fractures in hydrocarbon accumulations in strongly deformed zones. However, for low-amplitude structural areas, the degree of fracture development is relatively low, and their control on sweet spots of hydrocarbons has not yet formed a unified understanding. In this paper, taking the Upper Triassic Yanchang Formation in the western Ordos Basin as an example, the development characteristics, prediction method, and the distribution of fractures in tight sandstone reservoirs in low-amplitude structural areas have been systematically studied using a large number of cores, thin sections, paleomagnetism, FMI logging, acoustic emission, productivity data, and finite element method. The research results showed that the Yanchang Formation in the study area mainly develop high-angle and vertical fractures, which were formed by regional tectonic shearing. Fractures are mainly developed in the fine-grained and ultra-fine-grained sandstones of the distributary channel and estuary bar microfacies, while the fractures in the medium-grained sandstones of the distributary channel and the mudstones of the distributary bay are relatively underdeveloped. The core fractures and micro-fractures of the Yanchang Formation all have the regional distribution characteristics, and the fracture strikes are mainly between NE50° and NE 70°. Moreover, the finite element method was used to predict the fractures in the target layer, and the prediction results are consistent with the actual distribution results of the fractures. The coupling analysis of fractures and tight oil sandstone distribution showed that the existence of fractures provided conditions for the accumulation of hydrocarbons in the Yanchang Formation. The confluence and turning areas of the river channels were repeatedly scoured by river water, and the rocks were brittle and easy to form fractures. The thickness of the fractured sandstone in these areas is usually greater than 0.4 m. Moderately developed fracture zones are prone to form hydrocarbon accumulation “sweet spots,” and the fracture indexes of these areas are usually distributed between 0.8 and 1.2. However, when the fracture index exceeds 1.2, over-developed fractures are unfavorable for the accumulation of hydrocarbons.

3-D numerical simulation of sandstone matrix acidizing by non-Newtonian fluid

Matrix acidizing is a common technique to increase oil recovery in sandstone oil reservoirs. In the matrix acidizing process, reactive fluids are injected into the reservoir with the scope of dissolving and dispersing the rocks near the wellbore.In this study, the matrix acidizing of sandstone wells by a hydrochloric acid/hydrofluoric acid/additives mixture is described through mathematical modeling using the two-scale continuum model.The model developed in this study indicates the reactions and transport phenomena at pore and Darcy scales in 3-D radial flow. Due to using several additives during the acid injection process, the fluid phase has non-Newtonian behavior (shear-thinning). The effect of non-Newtonian fluid in porous media was investigated using a modified continuum model due to importance calculations in field scale. The Carreau-Yasuda constitutive equation has been used to modify the continuum model to consider the non-Newtonian fluid effects. In the proposed model, partial differential equations of reaction and diffusion at pore-scale, and simultaneously convection and dispersion phenomena at Darcy scale are solved using numerical methods. The finite volume and tri-diagonal matrix algorithm (TDMA) techniques were employed to gain a precise solution for the model and observe the dissolution pattern in different acidizing regimes and rheological properties. The effect of acid injection rate, dissolution rate constant and different reservoir properties, including permeability, porosity and heterogeneity on dissolution patterns, was investigated by considering non-Newtonian fluid effects, and concluded that acid having high shear-thinning behaviour (i. e., acid having low power-law index) seemed more promising for field operations because of deep penetration. The reservoir heterogeneity was defined by selecting a random local porosity distribution.It should be noted that the presented model can reproduce different types of acid/rock system (carbonate or sandstone reservoirs). Finally, the skin factor would be calculated to study the acidizing performance in the damaged zone. To solve the porosity evolution equation, couple pore and Darcy scales, and update the pore-scale parameters at each time step, the program was developed in FORTRAN by Parallel Processing and consisting of functions and routines. • Simultaneous numerical solution of Darcy, mass and pore equations in 3-dimension. • 3-D modeling of sandstone matrix acidizing by non-Newtonian fluid. • Pore volume to breakthrough and injection rate calculations in various conditions. • Consideration of power-law index (n) and viscosity effects in dissolution patterns. • Consideration of skin factor variation during the matrix acidizing.

Occurrence characteristics and relation to oil and gas distribution of bedding fractures in tight sandstone

The existence of bedding fractures has a very important influence on the formation and distribution of tight sandstone oil and gas reservoirs. In this paper, the occurrence characteristics of bedding fractures and their influence on oil and gas distribution were preliminarily studied. The results show that bedding fractures are generally developed in high energy hydrodynamic environments such as river channel, sea (lake) bank and beach, in which parallel bedding is the main type. The existence of dark minerals leads to weak laminar adhesion. Beddings weak the bond force of laminae due to the existing of dark minerals. The pore development condition of bedding fractures is better than that of the upper and lower sandstone laminae. Influenced by these, bedding fractures become important channels for hydrocarbon migration. [Received: April 23, 2021; Accepted: January 2, 2022]

Technical Analysis of Enhanced Oil Recovery by Polymer Flooding

Polymer flooding is one of the effective technologies to improve oil recovery. This paper briefly introduces the mechanism of polymer flooding, and describes the application advantages of polymer flooding in heavy oil sandstone reservoirs in China. Combined with the application practice of polymer flooding EOR technology, the scheme of polymer flooding EOR technology is further explored from the aspects of polymer flooding oil supply, polymer flooding oil injection mode and polymer solution mass concentration, hoping to provide some references for the improvement of reservoir recovery.

Testing origin of reservoir quality difference of tight sandstones in the Yanchang Formation, Ordos Basin, China

The Chang 7 and Chang 8 members of the Upper Triassic Yanchang formation are high-yielding tight sandstone oil reservoirs deposited in different sedimentary environments in the Ordos Basin. Lacustrine sediments are dominant in Chang 7 members, while delta front sediments are dominant in Chang 8 members. The causes of reservoir quality differences in the different sedimentary environments are not clear, which renders tight-oil exploration and development difficult. In this study, X-ray diffraction analysis (XRD), optical microscopy, scanning electron microscope (SEM), mercury injection tests and oil-water relative permeability tests were used to study the origin of reservoir quality differences between the Chang 7 and 8 reservoirs. The results show the following: 1) the Chang 8 and Chang 7 reservoirs are dominated by primary intergranular pores and dissolution pores, respectively. 2) Grain-coating chlorite is present in the Chang 8 reservoir, which is known to enhance the ability of reservoirs to resist compaction and prevent the growth of quartz. However, the reservoir pore space could be preserved only when the abundance of grain-coating chlorite is below the threshold of 4 vol%. 3) Carbonate cementation occurs pore-throat spaces, and the porosity of the reservoir tends to improve with carbonate content increase in the range of 0–10 vol%. This phenomenon is caused by carbonate minerals formed in different times. 4) The strong heterogeneity of pore sizes is the reason for rapid rise of capillary force of pore mercury saturation curve in Chang 8 reservoir. The throat volume controls the mercury saturation of the pore throats. The Chang 8 reservoir exhibit larger throat volume and higher permeability than Chang 7 reservoir. 5) The Chang 7 reservoir has small pore radius and poor connectivity. Therefore, it is difficult for water to displace the oil phase. As a result, the water phase permeability increases rapidly, the residual oil saturation is high, and the water productivity of the reservoir increases rapidly. In conclusion, the reservoir quality of Chang 8 Member is better than that of Chang 7 Member, and this can be attributed to the following factors: i) Chang 8 reservoirs have larger grain sizes and more abundant grain-coating chlorite, ii) the low content of illite and carbonate cement reduces reservoir cementation capacity and iii) the pore connectivity is better, because the throat radius and effective throat volume are larger. The results provide guidance for the efficient development of tight oil in these reservoirs.

The occurrence of tight oil in the Chang 8 lacustrine sandstone of the Huaqing area, Ordos Basin, China: Insights into the content of adsorbed oil and its controlling factors

Tight oil is a great potential resource for unconventional oil exploration and development. Determining the content of adsorbed tight oil in sandstone reservoirs and the factors controlling its content is crucial for the evaluation and development of tight oil resources. Using fluorescence petrography, environmental scanning electron microscopy, porosity as well as permeability analyses, high-pressure mercury intrusion, and nuclear magnetic resonance imaging, the present study analyzed the occurrence form, location, and relative content of free and adsorbed tight oils and effect of controlling factors on the content of adsorbed tight oil in sandstone reservoirs of the Chang 8 member in the Huaqing area of the Ordos Basin. The free tight oil mainly exists in residual intergranular, intergranular dissolved, intragranular dissolved, and dissolution-enlarged pores as well as some throats in the form of flakes with various areas and slender strips. The adsorbed tight oil mainly occurs on the surfaces of the mineral particles and mica fragments as well as in fractures, some throats or the intragranular as well as intergranular dissolved pores in the form of films with variable thicknesses and long strips. The lower limit of the pore radius at which free tight oil occurs in sandstone is approximately 0.1 μm and the adsorbed tight oil occurs on the surface of mineral particles and in spaces with pore radii of 0.02–0.3 μm. The contribution of free tight oil to total tight oil in the present study has highest and lowest content of 60.95% and 32.48%, respectively, with an average content of 50.14%. The contribution of adsorbed tight oil to total tight oil has highest and lowest content of 67.52% and 39.05%, respectively, with an average content of 49.86%. The content of adsorbed tight oil is generally proportional to the median pressure and inversely proportional to the porosity as well as permeability of the reservoir; particularly, porosity is relevant. The content of adsorbed tight oil is inversely proportional to the quartz content and directly proportional to the feldspar, carbonate cement, and clay mineral content of the sandstone.

Application of a non-ionic bio-surfactant instead of chemical additives for prevention of the permeability impairment of a swelling sandstone oil reservoir

Formation damage is a general term, which refers to any process that reduces the production or injectivity of an oil well. Clay swelling formation damage, due to incompatible fluid invasion, is a common problem in the petroleum industry. In this research, the effect of Acanthophyllum root extract (ACRE), a bio-based surfactant, on the reduction in reservoir permeability impairment has been studied. Some static tests were applied to investigate the chemical interaction between the surfactant and montmorillonite (Mt), including Mt sedimentation test, Free swelling index (FSI) test, Zeta potential tests, particle size measurement, and scanning electron microscopy (SEM). Experiments were followed by coreflood and micromodel tests to verify their effect on preventing permeability reduction and pore plugging in porous media. According to the results, Mt dispersion is unstable in the presence of ACRE solution. ACRE can reduce the FSI from 233.3 (totally hydrated Mt) to 94.3%, representing the reduction in hydration potential. The zeta potential of Mt in ACRE aqueous solution moves toward the lowest magnitude, implying that the water molecules surrounding the Mt particles are unstable. Particle size measurement and SEM analysis proved simultaneously that ACRE solution sustains Mt particles flocculated and prevents delamination. The thermal stability of the ACRE was evaluated by thermogravimetric analysis (TGA), and it showed a suitable resistance to the temperature rise. Eventually, coreflood and micromodel tests revealed that ACRE has a high performance in lowering the permeability impairment and pore plugging. All in all, ACRE showed high potential in preventing Mt swelling and, therefore, formation damage in clay-bearing sandstones.

Effects of pore structure on the moveable oil saturation in water-driven tight oil sandstone reservoirs

Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), high-pressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (Sapex), the ratio of the maximum pore-throat radius and the medium pore-throat radius (Rmax/R50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock.