Small Pore Throats Research Articles

On the role of spatially correlated heterogeneity in determining mudrock sealing capacity for CO2 sequestration

Abstract Storing CO2 in depleted hydrocarbon reservoirs is a common practice world-wide. Mudrocks often serve as seals above these reservoirs due to their small pore throats and low permeability, but they can fail if the buoyant pressure of the trapped fluid overcomes the threshold pressure of the seal. Mudrocks are primarily made of silt-sized and clay-sized particles, and sufficiently high silt concentrations can create situations where the silt grains create a connected stress chain through the rock matrix, which preserves the large pore throats under compaction. This phenomenon, termed silt bridging, can reduce the threshold pressure of the mudrock, causing seal failure. We used grain-scale modeling to create computer-generated grain packs with and without the effect of gravity to understand the effects of deposition and compaction on the petrophysical properties like capillary pressure, tortuosity, permeability, capillary drainage curves, and spatial correlation of heterogeneities. We found that, when the fraction of silt-sized grains exceeded 40%, the percolation length (the length of the first path of the non-wetting fluid through a medium) and the tortuosity suddenly decreased. This was supported by the results from the throat size variograms, where the same type of correlations between throats were observed at greater lag distances, signifying increased intergranular distances. Our work provides an insight into the role of different grain sizes, concentrations and spatial distributions on the flow properties and sealing capacity of mudrocks.

Experimental investigation of the live oil-water relative permeability and displacement efficiency on Kingfisher waxy oil reservoir

Oil-water relative permeability is not only the basis for studying the oil-water two-phase flow characteristics, but also one of the indispensable parameters for the reservoir numerical simulation and production dynamic analysis. Waxy oil has obvious viscosity-temperature characteristics and wax precipitation phenomenon, resulting in complex and diverse factors affecting the relative permeability. Presently, no systematic investigation on the oil-water relative permeability and displacement efficiency of wax oil reservoir exists, especially using live oil as experimental oil. In this paper, the accurate wax appearance temperature (WAT) and necessary aging time of experimental oil and cores were determined using ultrasonic detection and spontaneous imbibition methods, respectively. Subsequently, the viscosity, wettability, relative permeability and displacement efficiency of live oil and crude oil were compared and analyzed at different temperatures. Finally, the influencing factors of live oil-water relative permeability and displacement efficiency, namely, solution gas, temperature, permeability, wettability, water injection parameters and wax precipitation were comprehensively analyzed and studied. Experimental results showed that the WAT, wettability and viscosity of live oil are different from those of crude oil, thereby causing the difference in relative permeability and displacement efficiency of live oil and crude oil. When the temperature is above the WAT, the dominate influencing factor is oil viscosity, while the effect of core permeability is not obvious. When the temperature drops below the WAT, the precipitated wax not only causes a sharp increase in the oil viscosity, but also forms a wax film on the surface of flow channel to transform the rock wettability from hydrophilicity to lipophilicity. Furthermore, the wax film narrows the flow channel and the wax particles block the small pore throats. All these changes caused by wax make the relative permeability and displacement efficiency before and after the wax precipitation very different. The effect of permeability becomes significantly because of the physical deposition and pore throat plugging. Similarly, the displacement efficiency of different water injection parameters is the result of the interaction of multiple mechanisms. This investigation not only provides a systematic and reliable measuring method for the oil-water relative permeability and displacement efficiency of waxy live oil reservoirs, but also improves our understanding of the multiphase flow mechanisms in waxy oil reservoir.

Influence of micro‐pore structure in tight sandstone reservoir on the seepage and water‐drive producing mechanism—a case study from Chang 6 reservoir in Huaqing area of Ordos basin

AbstractTo study the influence of pore structure on the seepage and water‐drive producing mechanisms, various methods were combined to describe the micro‐pore structure in the Chang 6 tight sandstone reservoir in the Huaqing area, Ordos Basin, China. Nuclear magnetic resonance (NMR) was combined with displacement experiments to determine the distribution of oil and water in pores of different scales before and after water flooding. There are few micro pores in the reservoir. As permeability increases, the distribution of nano pores decreases, while sub‐micro pores increase. Also, sub‐micro pores are the main pathway within the reservoir. There is a negative power function correlation between the minimum starting pressure gradient of the oil (Swc) and maximum throat radius. Also, with a decrease of permeability, smaller pore throats become more abundant and the nonlinear section of the flow velocity‐differential pressure curves increase. There is a large amount of crude oil gathering in the nano pores. As permeability increases, the main sources of movable oil are from the nano pores (kg < 0.4 × 10−3 μm2), sub‐micro pores (kg ≈ 0.4 × 10−3 μm2‐1.0 × 10−3 μm2), and micro pores (kg > 1.0 × 10−3 μm2). Displacement efficiency is always the highest in sub‐micro pores.

Pore structure and multi-fractal analysis of tight sandstone using MIP, NMR and NMRC methods: A case study from the Kuqa depression, China

The pore structure and fractal characteristic of tight gas sandstone from Cretaceous Bashijiqike Formation in Kuqa depression were investigated, using thin section, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR) and NMR cryoporometry (NMRC) measurements. The pores of tight sandstone samples mainly contain residual primary intergranular pores, intergranular and intragranular dissolved pores, micropores related to clay aggregates and microfractures. The MIP, NMR and NMRC analyses show that the pore structure of tight sandstone is complex and heterogeneous at different pore scales, displaying as a multi-fractal feature. Fractal dimension Dg-s (with respect to small pore throats) from MIP and Dn-l (long T2 relaxation time, representing large pores and fractures or movable-fluid pores) are negatively correlated with porosity, permeability, median pore throat radius and skewness, and have inverse relationships with bound water saturation (Sbnd). Fractal dimension Dg-b (>3.0, with respect to larger pore throats) and Dn-s (<2.0, short T2 relaxation time, representing small pores or bound-water pores) from NMR don't present clear relationships with most of pore structure parameters. Fractal dimension Dc-1 and Dc-2 from NMRC show more complex or inconspicuous relationships with pore structure parameters, in the pore diameter size <500 nm. Hence, Dg-s from MIP and Dn-l from NMR can be considered as effective parameters for pore structure and fluid properties characterization of tight sandstone. Fractal dimension Dg-b (>3.0) and Dn-s (<2.0) have no practical significance to characterize the pore structure of tight sandstone. The formation of residual primary intergranular pores and intergranular dissolution pores can reduce the fractal dimension which could be an important sign of effective reservoirs in the study area.

EOR solvent-oil interaction in clay-hosted pores: Insights from molecular dynamics simulations

Our understanding of EOR processes in shales, especially in organic or kerogen pore systems, has grown rapidly over the last few years. While clays are ubiquitous in shales and may make-up over 50% by volume of the shale matrix, there has been little to no focus on solvent-oil interactions in these pore systems. While hydrocarbon storage is likely to happen predominantly in the organics, the inorganic material might serve as conduits for fluid transfer from the organics to the fracture systems. This work uses molecular dynamics and numerical simulations to investigate the mechanisms governing EOR in clay-hosted pores to address this knowledge gap.Because illite is the most common clay mineral in shales, we use a slit-pore model of illite to simulate oil and oil-solvent mixtures in clay pores to quantify the extent of miscibility, diffusion, viscosity reduction and oil swelling of the oil under illite confinement. Temperature and the presence of water is expected to also control the rate of diffusion, viscosity, oil swelling and the degree of confinement. To account for these effects, our simulations span a wide range of temperatures and concentrations of water. Finally, the findings from molecular dynamics simulations are utilized in reservoir-scale EOR models to demonstrate their impact.Our results confirm that oil swelling, diffusion and viscosity reduction are a few of the dominant pore-scale mechanisms governing EOR. However, our findings also demonstrate that bulk fluid properties can cause overly optimistic predictions of the efficacy of EOR. Confinement in illite is shown to negatively impact miscibility for methane-rich solvents. Secondly the self-diffusion of fluids under illite confinement are only 30% of their values in the bulk. Most significantly, oil-solvent mixture viscosities under illite confinement are about two orders of magnitude higher compared to their bulk values. The presence of water exacerbates all of these effects and in fact compromises the solubility of the injected solvent.Commercially available reservoir simulators accommodate a whole host of reservoir and well architectures, but the transport equations are derived using bulk fluid properties. However, our work underscores the need for rigorous small-scale experiments and modeling studies to properly account for the effects of confinement that can have significantly compromise EOR efficacy in plays where a high percentage of the pore volume is contained in sub-20 nm pores. A model that does not take in to account nonporous confinement can be overly optimistic and compromise project economics, especially if connectivity is driven by the smaller pore throats.

Shale gas transport in rock matrix: Diffusion in the presence of surface adsorption and capillary condensation

One characteristic of unconventional shale rock is the abundance of nanoscale pores and pore throats. For many shale reservoirs, these are the dominant factors controlling the total reserve, production rate, and overall production. Accordingly, many new phenomenon related to nanopore physics need to be considered for shale reservoir. A key mechanism controlling hydrocarbon gas transport from pores to fractures in shale reservoirs is molecular diffusion. As a result, the diffusion coefficient of light hydrocarbon becomes an important parameter in reservoir simulation to estimate production rate, especially for the long-term or late time production. The diffusion coefficient is also a key parameter in nuclear magnetic resonance (NMR) logging for fluid typing in determining hydrocarbon-in-place.Diffusion in nanopore systems is complicated by two important factors. First, the gas molecules collide more with pore surfaces than with each other; therefore, simple diffusion theory based on gas molecule collision is not applicable. Second, the occurrence of capillary condensation in small pores or pore throats and the adsorption to the pore surface makes the hydrocarbon transport a mixed process of liquid diffusion and gas diffusion in the reservoir.We derived a theoretical model for mixed phase diffusion under fast exchange for shale gas reservoirs. We obtained that the effective diffusion coefficient of mixed fluid is a fractional average of the liquid and gas diffusivity. We verified this model using NMR to measure n-hexane diffusion in a well-characterized hierarchical carbon with both nanometer pores and micrometer pores so that both gas and liquid can be prepared to exist in the sample simultaneously. We found that the diffusion coefficient of hexane in these hydrophobic nanopores is approximately one magnitude of order larger than the bulk liquid value. The effective diffusion coefficient in this study can be used in reservoir simulation and interpretation of NMR logs for shale gas reservoirs.

Lessons learned from IOR pilots in Bakken formation by using numerical simulation

Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5–10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated.The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1–2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.

Study and Application of Novel Cellulose Fracturing Fluid in Ordos Basin

Due to low gas saturation, less than 10% porosity, around 0.05 mD permeability and below 0.85 pressure coefficient, stimulation treatments are necessary in order to get economic production. Development speed of this block had been seriously affected because of significantly lower single well production than other parts of the Sulige Gas Field. Low concentration crossed-linked guar fracturing fluid is now commonly used in this area. As small size pore throat, high clay content and water lock, this gas deposit is sensitive to treatment fluid, thus the flowback time of fractured well is very long and production is generally low. In this paper we introduce a new fracturing fluid which can be crossed-linked in acidic water-based fluids. This fluid contains a kind of cellulose, which is completely soluble with no residue. Cellulose was used as additive agent in drilling and completion fluid twenty years ago, therefore, its application was greatly limited as poor stability of performance. New cross-linked agent and additives could solve this problem. Because of being compatible well with the reservoir fluids, the damage of fracturing fluid is relatively low. Proppant carrying capacity of this new fluid can be compared with low concentration crossed-linked guar fracturing fluid. The new fluid has been used in 6 vertical wells, with 100% treatment success-rate and 8.6×104m3/d average production rate. Compared with the nearby wells which had the same pay formation and were fractured with the similar fracture treatment scale by low concentration guar fracturing fluid, the flowback time was shortened by 53% and gas production was doubled. In conclusion, this new fracture fluid can reduce treatment time and cost, but increase gas production.

Classification of microscopic pore-throats and the grading evaluation on shale oil reservoirs

Abstract On the basis of the characterization of microscopic pore-throats in shale oil reservoirs by high-pressure mercury intrusion technique, a grading evaluation standard of shale oil reservoirs and a lower limit for reservoir formation were established. Simultaneously, a new method for the classification of shale oil flow units based on logging data was established. A new classification scheme for shale oil reservoirs was proposed according to the inflection points and fractal features of mercury injection curves: microscopic pore-throats (less than 25 nm), small pore-throats (25−100 nm), medium pore-throats (100−1 000 nm) and big pore-throats (greater than 1 000 nm). Correspondingly, the shale reservoirs are divided into four classes, I, II, III and IV according to the number of microscopic pores they contain, and the average pore-throat radii corresponding to the dividing points are 150 nm, 70 nm and 10 nm respectively. By using the correlation between permeability and pore-throat radius, the permeability thresholds for the reservoir classification are determined at 1.00× 10−3 μm2, 0.40×10−3 μm2 and 0.05×10−3 μm2 respectively. By using the exponential relationship between porosity and permeability of the same hydrodynamic flow unit, a new method was set up to evaluate the reservoir flow belt index and to identify shale oil flow units with logging data. The application in the Dongying sag shows that the standard proposed is suitable for grading evaluation of shale oil reservoirs.

Microstructure characterization of mullite foam by image analysis, mercury porosimetry and X-ray computed microtomography

It is well known that the effective properties of porous ceramics and ceramic foams depend strongly on the microstructure. That means, the prediction of effective properties of real materials generally requires quantitative values of well-defined microstructural descriptors as input parameters. The present contribution shows that ceramic foams with hierarchical microstructure require a complex microstructural characterization procedure based on a combination of different complementary techniques. Taking a light-weight mullite foam – an important and versatile ceramic material (e.g. for furnace linings, kiln furniture and high-temperature filters) – as a paradigmatic example, a systematic methodology is proposed for extracting relevant microstructural information. The microstructure of mullite foam with hierarchical microstructure has been characterized by stereology-based image analysis, mercury porosimetry and computed microtomography (X-ray µCT). Three metric descriptors (porosity, surface density, mean curvature integral density) and a topological descriptor (Euler characteristic density) have been determined, the latter being 192.4 ± 17.7·10−9 µm−3. SEM micrographs taken at different magnification allow to distinguish the porosity attributable to pore cavities (62.3–63.0%) and matrix (47.8–49.5%). Mean chord lengths and Jeffries sizes of the pores are 159–164 µm and 164–180 µm, respectively, for the pore cavities and 4.6–5.1 µm and 4.9–5.1 µm, respectively, for the matrix pores. Different types of pore size distributions have been determined, and it is found that in this specific case the size distribution of pore cavity sizes obeys a Rayleigh distribution. Mercury porosimetry covers small and medium-sized pore throats (median 76 µm), whereas image analysis captures pore cavities (median 234–247 µm) and X-ray µCT combines information on both pore throats and cavities, resulting in an intermediate median of 206 µm. The procedure proposed is very general and systematic and can be applied to porous materials with a wide range of microstructures.

Pore throat characteristics of tight sandstone of Yanchang Formation in eastern Gansu, Ordos Basin

An important factor to evaluate reservoir quality is the pore-throat size. However, the strong heterogeneity makes it difficult to characterize the pore-throat distribution in tight reservoirs. The field emission scanning electron microscope (FESEM), high pressure mercury injection and rate-controlled mercury injection are used to investigate the pore-throat size distribution in tight sandstone reservoirs of Member 7 of the Yanchang Formation in eastern Gansu, Ordos Basin, and studies of the pore throat size controlling on physical property of the tight sandstone reservoirs are also carried out. The result shows that the pore type is mainly dominated by the residual intergranular pore, dissolution pore, micropore and a few micro-fractures; the high-pressure mercury injection experiment indicates that the pore-throat size ranges from 0.0148 μm to 40 μm, the pore throat more than 1 μm is less; the rate-controlled mercury injection experiment reveals that for samples with different physical properties, the pore radius mainly varies from 80 μm to 350 μm; the throat radius exhibits the strong heterogeneity, and is from 0.12 μm to 30 μm; the pore-throat size can be effectively characterized by combination of high-pressure and rate-controlled mercury injections, and it varies from 0.0148 μm to 350 μm. The permeability is mainly controlled by the large pore throat (>R50) which accounts for a small proportion; in the tight sandstone with the permeability greater than 0.1 mD, the permeability is mainly controlled by the micropore and mesopore; in the tight sandstone with the permeability smaller than 0.1 mD, the permeability is mainly controlled by the nanopore and micropore; the proportion of small pore throat increases with reduction of permeability, it is important that the small pore throat influences the reservoir storage property though its effect on permeability are small.

Experimental study on the oil-water relative permeability relationship for tight sandstone considering the nonlinear seepage characteristics

Oil-water relative permeability is an important parameter to describe the oil-water two-phase flow in oil reservoirs. The permeability rules for oil-water flow in tight sandstone reservoirs do not exactly follow the Darcy law due to its tight lithology and small pore-throat. In addition, the relative permeability curve obtained from traditional processing methods cannot accurately describe the seepage characteristics for this type of oil reservoirs, and therefore, may lead to unreasonable evaluation and prediction of productivity. In this work, the reservoir conditions are simulated and the test for oil (Swc) flow of tight sandstone has been carried out. Additionally, the relative permeability curve of water-oil displacement in unsteady state has also been obtained. When the oil (Swc) gets through the tight sandstone sample, the relationship between the flow velocity and the pressure gradient is not a straight line. In addition, the flow velocity and pressure gradient satisfy the equation of v=kμo∇P(1−1a+b∇P). The traditional JBN method is improved considering the nonlinear seepage characteristics, and the data processing method of oil-water relative permeability for tight sandstone reservoirs is established. Compared with the traditional JBN method, the oil-phase relative permeability, as calculated using the JBN method with the consideration of nonlinearity, is found to be higher. The results also show that the equal permeability point of has moved towards the right.

Physical Simulation of Colayer Water Flooding in Low Permeability Carbonate Reservoir in Middle East

To study the flow mechanism under different displacement modes of low permeability carbonate reservoir in the Middle East and to improve the utilization of various types of reservoirs, the physical simulation experiments of water flooding by different displacement methods were carried out. Selecting two types of rock samples with different permeability levels, two-layer coinjection and separated production experiments by samples I and III and conventional water flooding experiments by samples II and IV were carried out. In addition, by using low magnetic field nuclear magnetic resonance, the development effect of microscopic pore structure under the different injection-production models was analyzed. Results show that, compared with the coinjection, the recovery rate of sample I was higher than II, 19.30%; sample III was lower than IV, 23.22%; and the comprehensive recovery degree reduced by 3.92%. NMR data also show that the crude oil is mainly distributed in the large pore throat; after water flooding, the displacement is also within the large pore throat, whereas the small pore throat is mainly obtained by the effect of infiltration absorption. The above studies provide a laboratory basis and foundation for the further development of low permeability carbonate reservoir in different Middle East strata.

Slip Velocity of Methane Flow in Nanopores With Kerogen and Quartz Surfaces

Summary Slip phenomenon is one of the major characteristics of gas flow through porous media—in particular, in unconventional gas reservoirs with small pore throats, such as tight sands, coal seams, and shale formations. Consequently, a permeability correction needs to be considered to evaluate the gas-flow ability in these reservoirs. Various analytically derived and empirical correction models exist for engineering applications. However, it is not well-understood which one should be implemented in real-shale-reservoir problems. In this paper, slip velocity and permeability for gas flow in nanopores are studied by molecular-dynamics (MD) simulations. For simplicity, the system considered is methane gas flow in a parallel-plate channel of quartz and kerogen. The fluid flow is characterized by the Knudsen number (Kn), which is defined as the ratio between the mean free path and the representative length of the pores. Studies with various Knudsen numbers were conducted by changing (1) the methane density (the mean free path) or (2) the plate-spacing (pore size). Simulation results show that the relationships between slip velocity and Knudsen number and between the permeability-correction factors and Knudsen number agree well with the Beskok and Karniadakis (1994) analytical solution (BK model) for large nanopores (12–34 nm) in both quartz and kerogen cases. This model considered rarefaction and compressibility effects on gas microflows, and was tested experimentally with characteristic dimensions of one-micrometer order. Our simulation results indicate that this model can be extended to nanoflows existing in unconventional reservoirs. Under temperature and pressure conditions that we studied, deviation from the BK model is noted for small nanopores (&amp;lt;12 nm), but for a pore size smaller than 6 nm, it converges to a constant value in the quartz slit pore. In contrast, a radical increase of slip velocity is observed in the kerogen pore. The deviation from the BK model for a pore size smaller than 12 nm is ascribed to the fact that the overall fluid is no longer homogeneous (i.e., the fluid at the interface region plays a crucial role in the overall flow behavior). An adsorption structure is observed in the proximity of the solid walls because of the interaction from the wall molecules. Moreover, it is found that the effect of roughness becomes significant in an extremely small kerogen nanopore.

Gas permeability measurement of shales using the quasi steady-state technique

The decline in reserves from conventional reservoirs, paired with the technological advances made in the drilling, stimulation and production areas over the last two decades have placed unconventional reservoirs in the limelight. Shale plays, in particular, have become increasingly attractive prospects and production from these reservoirs has increased significantly during this period. Most of the petrophysical characterisation techniques routinely used in the laboratory were originally developed for rocks with relatively high porosity and permeability, making some of them unsuitable for tight rocks. Gas permeability measurements in shales can be particularly challenging due to their small pore and pore throat sizes, and even the validity of Darcy’s law under these conditions needs to be evaluated. The steady-state technique is generally unsuitable for measuring gas permeability in shales due to technical limitations of the instruments required, so the quasi steady-state method is proposed as an alternative. This paper presents the results of gas permeability measurements conducted on two shale core plugs using the quasi steady-state technique. Although the effect of variations in ambient conditions is not usually significant for tests performed on cores from conventional reservoirs, our results indicate that it should not be overlooked when experiments are conducted on shale samples. Furthermore, the length of the core plugs should be minimised to reduce the time required to measure gas permeability.

Experimental study on the micro alkali sensitivity damage mechanism in low-permeability reservoirs using QEMSCAN

Low permeability reservoirs are extremely sensitive to injected fluids because of small pore throat sizes and complex connections. Alkali sensitivity damage is the primary damage mechanism in low permeability reservoirs and strongly influences rock permeability. Therefore, it is significant to study alkali sensitivity damage mechanism to prevent capacity attenuation. In this paper, we propose a method combines macroscopic core flow experiments and microscopic mineral analysis to study alkali sensitivity damage mechanism. Core flow experiments are designed to evaluate the alkali sensitivity damage degree. QEMSCAN technique is introduced to quantitatively compare changes of porosity, mineral contents and distribution forms at inlet and outlet sides before and after alkali sensitivity damage. The results indicate that pore and throat plugging is the root cause of core alkali sensitivity damage. Big pores are plugged and segmented into significantly narrow flowing channels. The inlet side is plugged mainly by precipitates generated by the reaction of hydroxide and matrix minerals including dolomite, muscovite, and K-feldspar as well as dispersion of clay minerals in alkali environments including illite and chlorite. Meanwhile, the outlet side is mainly plugged by the dispersion and migration of clay minerals.Micro minerals are selected as the research object to study the alkali sensitivity damage at both inlet and outlet sides in low permeability reservoirs. This provides references for alkali sensitivity analysis in reservoirs with similar mineral compositions. Moreover, alkali sensitivity damage mechanisms are clarified at both inlet and outlet sides in the core flow experiment, which can be correlated to actual reservoirs near and far away from wells. Then specific measures corresponding to different types of reservoirs in terms of distances to wells can be taken to restore the damage and thus achieve the recovery of reservoir capacity. The method proposed in this paper is also applicable to other reservoir sensitivity damage, such as salt and acid sensitivity damage.

Investigation on Preparation and Profile Control Mechanisms of the Dispersed Particle Gels (DPG) Formed from Phenol–Formaldehyde Cross-linked Polymer Gel

To achieve in-depth profile control and further improve oil recovery, a new profile control agent, termed a dispersed particle gel (DPG), has been developed and reported. In this paper, the DPG particles with sizes ranging from submicrometer to micrometer are prepared successfully from phenol–formaldehyde cross-linked polymer gel by the high speed shearing method. The preparation method is convenient and easy to scale up for the field application. The microscopic characteristics of the DPG have been investigated by transmission electron microscopy (TEM) and dynamic light scattering (DLS). Parallel sandpack tests and microscopic visualization tests have been conducted to gain insights into the profile control mechanism. Additionally, scanning electron microscope (SEM) has been used to study the distribution of DPG particles in porous media. The results show that the DPG particles can block the high permeability layers by accumulating in large pore spaces or by directly plugging small pore throats. Meanwhil...

An Experimental Study on the Slippage Effect of Gas Flow in a Compact Rock

Gas flow in small pore throats in compact rocks is usually affected by the gas slippage effect due to the dense structure and low porosity of the rocks. In this study, permeability and porosity of two granitic gneiss specimens under different pore and confining pressures are measured. Petrographic studies are also performed using X-ray diffraction, optical microscopy, and scanning electron microscopy coupled with an energy-dispersive spectrometer. Test data indicate that the gas flow in the compact rock does not follow Darcy’s law due to the effect of gas slippage, and the measured permeability needs to be corrected by the gas slippage effect. The test results show that the gas slippage effect increases subsequently when the pore pressure is low, which leads to the measured permeability higher than the absolute permeability. The influence of confining pressure on the impact rate of the slippage effect appears to approach an upper limit symptomatically. It is found that a power law describes well the relationship between the absolute permeability and the effective porosity. A correlation of the slippage factor and the absolute permeability is provided. When the confining pressure is high and the pore pressure is low, the flows are slip flow and transitional flow and traditional fluid dynamics N–S equations are not applicable and Knudsen’s diffusion equations should be used.

Determination of consolidation behaviour of clay slurries

The main objective of this study was to determine the consolidation behaviour of clay slurries. A fine-grained clay with high consistency limits (wL=180%, wP=120%) was investigated using conventional oedometer and bench-top centrifuge tests. Results indicated that the slurry had an apparent preconsolidation (due to initial conditions, electrochemical interactions, tortuous drainage, and thixotropic strength) from e=5.7 to e=5.5 followed by virgin compression. Likewise, the low hydraulic conductivity (10−10–10−12m/s) was due to low porosity (small pore throats) and high tortuosity (long flow paths). Unlike consolidation of soils, the cv and mv decreased with increasing σ′ but increased with increasing e and k. The data from the two tests correlated well in the range of σ′=10–65kPa, e=5.5–3.86, k=1.7×10−10–5×10−11m/s, Fc=1–40MN. New equations were developed to correlate the consolidation parameters (e, σ′, k) with Fc. The deviation of k beyond 40MN (e=4.65) was due to deviation from the initial straight line portion of the settlement curve in the centrifuge test.

Macroscopic Profile Modification and Microscopic Displacement Mechanism of Weak Gel Flowing in Porous Media

In this paper, the flowing mechanism and function on the macroscopic and microscopic scale in the porous media of a widely used weak gel of an acrylamide based polymer crosslinked with chromium(III) were studied. Innovative microscopic plane visualization model was designed for microscopic scale experiment and sand pack physical model for macroscopic scale. The microscopic displacing experiments indicate that weak gel mainly intrudes into big pores rather than small ones, which can improve the conformance horizontally and increase the sweep efficiency benefiting from fluid diversion. Additionally, due to good viscoelasticity of weak gel, the negative pressure effect was formed enhancing oil recovery flow from small pore throats. Results of macroscopic physical sand pack flow experiment indicate positive influence of weak gel on vertical conformance control. Although the high permeable layer was not completely blocked, the oil recovery improved as a result of weak gel movement by continuous water flooding. Experiments results lead to conclusion, the primary function of weak gel is oil displacement, profile modification is secondary, and its effect is temporary.