Core Flow Experiments Research Articles

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.

A new experimental methodology to investigate formation damage in clay-bearing reservoirs

Abstract Understanding mechanisms and performance of formation damage induced by sensitive clay minerals in reservoirs is crucial for avoiding productivity loss at any reservoir development stage. This paper proposes a new experimental methodology which organically integrates core flow experiment with nuclear magnetic resonance (NMR) (NMR T2 spectrum and NMR image) and quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN) to investigate alkali sensitivity damage mechanisms in a low-permeability reservoir. It distinguishes itself from existing techniques by providing comprehensive, quantitative information on alterations of clay and pore morphology and distribution in the damage, and directly visualizing sensitivity damage processes. Water blocking experiment (WBE) designed to research potential effect of sensitivity damage on oil well productivity was also performed. The alkali sensitivity damage mechanism of clay dispersion and migration was clearly characterized and effectively identified by the NMR T2 spectra and MR images. Further, result of QEMSCAN pinpoints that kinds of the clay triggering the damage are mainly chlorite and illite. Moreover, it was found by the QEMSCAN that the generation of silicide precipitation duo to reactivity of rock framework with hydroxide is also an important alkali sensitivity damage mechanism. Result of WBE demonstrates that alkali sensitivity damage can significantly accelerate decline of oil relative permeability and reduce residual oil saturation, both of which are detrimental for oil recovery of a reservoir. Such an experimental methodology could also be employed to research any other reservoir sensitivity damage types, such as salt sensitivity, acid sensitivity and so on.

Bentonite-Free Water-Based Drilling Fluid with High-Temperature Tolerance for Protecting Deep Reservoirs

A bentonite-free water-based drilling fluid (BFDF) with high-temperature tolerance (up to 200°C) was developed for protecting reservoirs in deep wells. The fluid is composed of heatresistant polymeric thickener and starch, sodium sulfite, etc. A series of methods including environmental scanning electron microscopy (ESEM), linear expansion and hot-rolling dispersion test, and core-flow experiments and measurements of the rheological parameter, filtrate, and biotoxicity were used to evaluate the performance of the BFDF formulation. Laboratory results indicate that the fluid has excellent high-temperature tolerance. Its yield point and plastic viscosity ratio is up to 0.38 even after aging at 200°C for 16 h with API filtrate of 9.8 mL. Its apparent viscosity, plastic viscosity, and yield point at 180°C are 30 mPa·s, 17 mPa·s, and 14.5 Pa, respectively, which show its good well-cutting carrying performance and wellbore purification capacity. The BFDF formulation exhibits a strong ability to restrain the linear expansion rate of bentonite and shale powder, to improve cutting recovery, to protect the well reservoir by cutting down water blocking and lowering permeability damage, and to minimize biotoxicity with a high EC50 value and is suitable for drilling deep wells in environmentally sensitive areas.

Mechanism Study of the Cross-Linking Reaction of Hydrolyzed Polyacrylamide/Ac3Cr in Formation Water

The mechanism of the cross-linking reaction between hydrolyzed polyacrylamide (HPAM) and chromium acetate in formation water was systematically studied by viscometry, ultraviolet-visual absorption spectrometry, and core flow experiments. The results show that the process and outcome of the cross-linking reaction between HPAM and chromium acetate is significantly affected by salinity. In formation water, chromium acetate cannot cross-link HPAM when the salinity is too low. With an increase of salinity, the cross-linking reaction occurs, and the degree of the reaction increases to a balance point. When the cross-linking reaction occurs, two different types of the reaction appear under different salinity. The intramolecular cross-linking reaction is the first to happen, whether under high salinity or under low salinity. In this stage, the cross-linking reaction is a first-order reaction and plays a greater role in the whole process of the reaction due to its higher reaction rate and higher reaction degree. Next, the intramolecular cross-linking continues to occur if the formation water is in the low salinity range, but the intermolecular cross-linking reaction occurs if the formation water is in the high salinity range. In this stage, the cross-linking reaction is a multistage reaction. Meanwhile, the experiments quantify a matching relationship between cations in the formation water and the profile control and oil displacement agent. The experimental results in this paper can provide theoretical guidance for the practical application of profile control and oil displacement using HPAM/Ac3Cr.

Damage mechanism and protection measures of a coalbed methane reservoir in the Zhengzhuang block

The Zhengzhuang block is an important development area in Qinshui basin in Shanxi Province, China. In this block, the amount of gas produced in many wells is not consistent with that predicted according to data concerning reservoir properties, even after fracturing (i.e., with clean fracturing fluid) or the implementation of horizontal boreholes through the reservoir. To investigate the damage mechanism, mineral composition and microstructures were analyzed using X-ray diffraction, scanning electron microscopy and thin section analysis; pore parameters were determined by a mercury intrusion test; hydration properties were tested by a dispersion and expansion experiment; the contact angle of water on reservoir cores was measured to analyze the wettability; and the sensitivities of NO. 3 coal cores were analyzed according to core flow experiments and an isothermal adsorption test. Based on the test results, the factors causing damage to the coalbed methane (CBM) reservoir in the NO. 3 coal seam included serious water blocking and stress sensitivity, followed by velocity sensitivity, water sensitivity, alkali sensitivity and acid sensitivity. To eliminate water blocking, an agent to adjust core wettability was chosen. Moreover, a new cheap inhibitor was provided to reduce core water sensitivity. Using the selected wettability adjustment agent, the inhibitor and other necessary additives, drilling fluid and fracturing liquid systems were optimized, causing considerably less damage to CBM reservoir cores, both in the wet and dry states, according to the results of core permeability tests. Compared with surface water and drilling mud applied during drilling in the gas field of the Zhengzhuang block, the optimized drilling fluid and fracturing liquid can promote methane desorption by reducing the Langmuir volume and increasing the Langmuir pressure of coal, thereby increasing gas production and recoverability of the CBM reservoir.

Visualization study on fluid distribution and end effects in core flow experiments with low-field mri method

Core flow experiment is an important means of simulation experiments to evaluate the effect of displacing agent, but conventionally the internal characteristics in the core cannot be intuitively observed, and then some important information can not be directly acquired by experiments. In this paper, a visualization method was used to detect the water-flooding process by using an improved low field nuclear magnetic resonance imaging (MRI) device, and the images describing the distribution of oil and water were collected. The experimental results show that the distribution of oil and water can be visually detected in an appropriate range of core porosity, and the end effect in many mechanics experiments is found to exist also in natural core flow test, and the influence range is about 0.004 m from the end of a 0.05752 m length natural core. The results also indicate that MRI is an effective tool to study the real time fluid distribution in natural core.

Laboratory measurement and interpretation of nonlinear gas flow in shale

Gas flow mechanisms in shale are urgent to clarify due to the complicated pore structure and low permeability. Core flow experiments were conducted under reservoir net confining stress with samples from the Longmaxi Shale to investigate the characteristics of nonlinear gas flow. Meanwhile, microstructure analyses and gas adsorption experiments are implemented. Experimental results indicate that non-Darcy flow in shale is remarkable and it has a close relationship with pore pressure. It is found that type of gas has a significant influence on permeability measurement and methane is chosen in this work to study the shale gas flow. Gas slippage effect and minimum threshold pressure gradient weaken with the increasing backpressure. It is demonstrated that gas flow regime would be either slip flow or transition flow with certain pore pressure and permeability. Experimental data computations and microstructure analyses confirm that hydraulic radius of flow tubes in shale are mostly less than 100 nm, indicating that there is no micron scale pore or throat which mainly contributes to flow. The results are significant for the study of gas flow in shale, and are beneficial for laboratory investigation of shale permeability.

Evaluation of oil-tolerant foam for enhanced oil recovery: Laboratory study of a system of oil-tolerant foaming agents

The objective of this paper is to investigate an oil-tolerant foam system as a displacing agent to improve the efficiency of oil recovery. To achieve this objective, several foaming agents are examined based on foam–oil interaction models and previous studies. By measuring the interfacial and surface tensions of surfactants, we investigate the implications of the value of spreading coefficient and the lamella number in a system of foaming agents. The foamability and foam stability of the preferred foaming agents were statically tested. At last, the oil tolerance of the foaming agent system in both static and core flow experiments was investigated. Results indicated that the oil tolerant foaming system performs best among the various surfactants tested. In static testing, both foamability and foam stability increase as concentrations of surfactant and salt increase. It was also observed that the polymer significantly increases the foam stability in the presence of oil. The oil droplets do not spread at the surface due to the properties of the oil-tolerant foam, so the foam can be stable in the presence of crude oil. The oil tolerant foaming system exhibits much greater foaming volume and longer drainage-half time than ordinary foam, either in the presence or absence of oil. The mobility reduction factor for dynamic displacement of oil-tolerant foam is much higher than those of pure foam and polymer solutions in the presence of oil. Experiments with different remaining oil saturations reveal that when the residual oil saturation is about 40%, the oil-tolerant foam can achieve the highest oil recovery.

Flow Mechanism of Partially Cross-Linked Polyacrylamide in Porous Media

Partially cross-linked polyacrylamides (PCPAM) were prepared, and their rheological property, gel content, swelling property, and suspension property in saline solution were analyzed in laboratory. The goal of the research was to study the flow mechanism of PCPAM as a novel oil displacement agent in porous media. The migration behaviors of PCPAM were studied by single and series connection of double-tube sandpacked core flow experiments. The results showed that there was a critical pressure existing in the migration of PCPAM particles in porous media, and the migration was a dynamic process of plugging and flooding at the same time. When the pressure reached the critical pressure, the PCPAM particles would deform to pass through the pore throat and go ahead. Besides, the profile control experiments were conducted using a parallel connection of double-tube sandpacked core models, and the results revealed that PCPAM could generate “fluid diversion” and enlarge the swept volume of the lower permeable core. Moreover, micro-visualization displacement experiments were also carried out and proved that PCPAM could plug the high permeable pore throat to enlarge the swept volume, leading to an enhancement in oil recovery.

Research on the Mobility of Polymer Flooding System for Xinjiang Conglomerate Reservoirs

The conglomerate reservoir is provided with strong heterogeneity and complex pore structure. To study the matching relationship between polymer flooding system and pore throat of the conglomerate reservoir and set up the flow matching relationship plate, this paper conducted natural core flow experiments at the true flow rate of the site formation based on constant pressure flooding method, considering the shear of the borehole and the formation. And several suitable polymers for different reservoirs permeability were given. The experimental results indicated that a positive correlation between the flow properties and the viscosity of the polymer solution, but a negative correlation between the mobility and the permeability of reservoir. Such as the natural core with the permeability = 30×10-3μm2 was suitable for the viscosity≤16.0 mPa.s of the polymer solution in the formation, the natural core with the permeability = 60×10-3μm2 was suitable for the viscosity≤35.2mPa.s of the polymer solution and the natural core with the permeability = 120×10-3μm2 was suitable for the viscosity≤102.4mPa.s of the polymer solution. Using compatibility relationship, quickly and easily choose the right injection parameters of the polymer based on the reservoir permeability, providing a theoretical basis for program preparation and parameters adjustment of the polymer flooding.

Experimental Study on Sensitivity Damage of Offshore High-Porosity and High-Permeability Reservoir

Offshore high-porosity and high-permeability reservoirs, characterized by large pore throat, wide distribution of pore size and enriched sensitive minerals, are easily damaged due to improper use of drilling fluids and completion fluids during the development stage. A series of experimental studies were carried out on the sensitivity damage analysis including X-ray diffraction, scanning electron microscopy, mercury injection porosimetry and core flow experiment. According to the laboratory evaluation results, the reservoir SZLF of high-porosity and high-permeability existed strong water sensitivity and mid to strong stress sensitivity. Furthermore, shielding and temporary plugging technique applied for reservoir protection was put forward, and laboratory tests showed that it had a better effect on solid intrusion prevention.

Study on a New Polymer with Better Performance in High Salinity Reservoirs

In this paper, the variation of viscosity with time is studied under condition of different influencing factors such as shearing time, mass concentration, salinity and temperature. The applicable conditions are optimized as following: The optimum mass concentration, salinity and temperature through laboratory experiment is 3000 mg/L~4000 mg/L, 40000 mg/L~80000 mg/L with Ca2+under 5000 mg/L and 20 °C~60 °C respectively. Finally, anti-shearing and oil displacement experiment are carried out under laboratory conditions. The results show that the new polymer after being sheared also has the ability to self-assemble and the enhancement in oil recovery obtained in core flow experiment is higher than conventional polymer flooding, which suggests that it has a wide application prospects in tertiary oil recovery.

Performance Evaluation of Polymer Microspheres for Profile Control and Oil Displacement

In this paper, the law of hydration expansion of polymer microsphere and the plugging rate of polymer microsphere under condition of different influencing factors such as hydration time, mass concentration, and permeability are studied. The applicable conditions are optimized as following: The optimum hydration time, mass concentration, and formation permeability through laboratory experiment is 5 days 3000 mg/L~4000 mg/L, permeability under 4 um2 respectively. Finally, oil displacement experiment is carried out under laboratory conditions. The results show that the enhancement in oil recovery obtained in core flow experiment is about 7 %, which suggests that it has a wide application prospects in tertiary oil recovery.

Study on Compatibility of Polymer Hydrodynamic Size and Pore Throat Size for Honggang Reservoir

Long core flow experiment was conducted to study problems like excessive injection pressure and effective lag of oil wells during the polymer flooding in Honggang reservoir in Jilin oilfield. According to the changes in viscosity and hydrodynamic dimensions before and after polymer solution was injected into porous media, the compatibility of polymer hydrodynamic dimension and the pore throat size was studied in this experiment. On the basis of the median of radiusRof pore throats in rocks with different permeability, dynamic light scattering method (DLS) was adopted to measure the hydrodynamic size Rh of polymer solution with different molecular weights. The results state that three kinds of 1500 mg/L concentration polymer solution with 2000 × 104, 1500 × 104, and 1000 × 104molecular weight matched well with the pore throat in rocks with permeability of 300 mD, 180 mD, and 75 mD in sequence. In this case, the ratios of core pore throat radius median to the size of polymer molecular clewR/Rhare 6.16, 5.74, and 6.04. For Honggang oil reservoir in Jilin, when that ratio ranges from 5.5 to 6.0, the compatibility of polymer and the pore structure will be relatively better.

Study on the Matching Relationship between Polymer Hydrodynamic Characteristic Size and Pore Throat Radius of Target Block S Based on the Microporous Membrane Filtration Method

The concept of the hydrodynamic characteristic size of polymer was proposed in this study, to characterize the size of aggregates of many polymer molecules in the polymer percolation process. The hydrodynamic characteristic sizes of polymers used in the target block S were examined by employing microporous membrane filtration method, and the factors were studied. Natural core flow experiments were conducted in order to set up the flow matching relationship plate. According to the flow matching plate, the relationship between the hydrodynamic characteristic size of polymer and pore throat radius obtained from core mercury injection data was found. And several suitable polymers for different reservoirs permeability were given. The experimental results of microporous membrane filtration indicated that the hydrodynamic characteristic size of polymer maintained a good nonlinear relationship with polymer viscosity; the value increased as the molecular weight and concentration of the polymer increased and increased as the salinity of dilution water decreased. Additionally, the hydrodynamic characteristic size decreased as the pressure increased, so the hydrodynamic characteristic size ought to be determined based on the pressure of the target block. In the core flow studies, good matching of polymer and formation was identified as polymer flow pressure gradient lower than the fracture pressure gradient of formation. In this case, good matching that was the pore throat radius should be larger than 10 times the hydrodynamic characteristic size of polymer in this study. Using relationship, more matching relationship between the hydrodynamic characteristic sizes of polymer solutions and the pore throat radius of target block was determined.

Comblike Polyacrylamides as Flooding Agent in Enhanced Oil Recovery

The oil recovery from core material and a specifically designed flow cell using novel branched (comblike) polyacrylamides (PAM) has been investigated. The injectivity characteristics of the different branched PAMs were evaluated by filtration tests and core-flow experiments. The number of arms of the branched PAM has little to no effect on the filterability and permeation through a porous medium. The 13-arm branched PAM displayed a higher residual resistance factor (RRF) in Berea sandstone than its linear analogue and a commercial HPAM. In addition, the thickness of the layer adsorbed at the rock surface is higher for the branched PAM. Oil trapped in dead-end pores is simulated using a 2D flow cell and the effect of the number of arms on the recovery of residual oil is evaluated. In brine solutions, the branched PAMs perform equal or better than their linear analogues in terms of the solution viscosity. The oil recovery of a branched PAM with a similar molecular weight is 3 times as high as that for the commercial polymer. The recovery efficiency, evaluated using low permeable Berea as the porous medium, is significantly improved by using branched PAM instead of linear ones (5.0 compared to 1.5% of the OOIP). An improvement is also observed when high permeable Bentheim cores are used as the porous medium (9.4% compared to 6.0% of the OOIP). The higher oil recovery in the 2D flow cell might explain the improved performance of the branched PAMs. The high thickening capability and the low molecular weight of the branched PAMs makes them suitable for application in enhanced oil recovery (EOR, especially for low permeable reservoirs).

A robust numerical approach for prediction of turbofan engine noise

Noise from the aircraft jet engines is still the dominant source in takeoff condition. Government regulations of community noise are getting more stringent, creating significant challenges for aircraft manufacturers to meet these requirements. Expensive nature of experiments as well as accessing to powerful computers have provided new impetus for computational studies. In this paper, an efficient and robust numerical scheme, namely the Lattice Boltzmann Method was used to simulate the sound created by typical internal mixing nozzles with forced mixers. The simulation includes capturing the time-resolved flow characteristics and large scale turbulent structures. The sub grid scales were modeled using the renormalization group (RNG) forms of the standard k-ε equations. Several test cases including cold and hot core flow experiments conducted by NASA were selected for computational setup and validation purposes. The far field sound was predicted using a surface integral method. The near-field simulation results such as the jet centerline velocity decay and turbulence intensities as well as far-field sound were qualitatively in agreement with experimental results. The far-field sound analysis suggested significant low-frequency noise reduction for the lobed mixers, as well as significant reduction in overall sound pressure level (OASPL) in comparison with the simple confluent nozzle configurations.

Dissolution-Driven Permeability Reduction of a Fractured Carbonate Caprock

Geochemical reactions may alter the permeability of leakage pathways in caprocks, which serve a critical role in confining CO2 in geologic carbon sequestration. A caprock specimen from a carbonate formation in the Michigan sedimentary Basin was fractured and studied in a high-pressure core flow experiment. Inflowing brine was saturated with CO2 at 40°C and 10 MPa, resulting in an initial pH of 4.6, and had a calcite saturation index of -0.8. Fracture permeability decreased during the experiment, but subsequent analyses did not reveal calcite precipitation. Instead, experimental observations indicate that calcite dissolution along the fracture pathway led to mobilization of less soluble mineral particles that clogged the flow path. Analyses of core sections via electron microscopy, synchrotron-based X-ray diffraction imaging, and the first application of microbeam Ca K-edge X-ray absorption near edge structure, provided evidence that these occlusions were fragments from the host rock rather than secondary precipitates. X-ray computed tomography showed a significant loss of rock mass within preferential flow paths, suggesting that dissolution also removed critical asperities and caused mechanical closure of the fracture. The decrease in fracture permeability despite a net removal of material along the fracture pathway demonstrates a nonintuitive, inverse relationship between dissolution and permeability evolution in a fractured carbonate caprock.

Sensitive Parameter Predicting Steady-State Pressure Difference of Partially Crosslinked Polyacrylamide Suspension in Core Flow Experiments

Using artificial cores, six different partially crosslinked polyacrylamide (PCPAM) suspensions were used for sandpacked core flow experiments; the results indicated that the migration of the PCPAM particles through porous media was a process of plugging and flooding at the same time. A theoretical model was proposed and the sensitive parameter, G′, was determined by rheological oscillation measurements with a 200 μm plate gap. In addition, the validity of the proposed theoretical model was verified by the results of the core flow experiments and a fitting equation of ΔP 1 with G′ was obtained which can be used for quantifying the steady-state pressure of PCPAM suspensions flowing through porous media in the core flow experiments.

Studies on a Foam System of Ultralow Interfacial Tension Applied in Daqing Oilfield after Polymer Flooding

In order to study the effects of oil displacement by a foam system of ultralow interfacial tension, the interfacial activities and foam properties of a nonionic gemini surfactant (DWS) were investigated under Daqing Oilfield reservoir conditions. Injection methods and alternate cycle of the foam system were discussed here on the basis of results from core flow experiments. It was obtained that the surface tension of DWS was approximately 25 mN/m, and ultralow interfacial tension was reached between oil and DWS with a surfactant concentration between 0.05wt% and 0.4wt%. The binary system showed splendid foam performances, and the preferential surfactant concentration was 0.3wt% with a polymer concentration of 0.2wt%. When gas and liquid were injected simultaneously, flow control capability of the foam reached its peak at the gas‐liquid ratio of 3 : 1. Enhanced oil recovery factor of the binary foam system exceeded 10% in a parallel natural cores displacement after polymer flooding.