Core Flow Experiments Research Articles

Low Polymer Retention Possible in Flooding of High-Salinity Carbonate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202809, “Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High-Salinity Carbonate Reservoirs,” by Arne Skauge, SPE, and Tormod Skauge, SPE, Energy Research Norway, and Shahram Pourmohamadi, Brent Asmari, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Polymer flooding has been a successful enhanced-oil-recovery method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging because of adsorption loss and polymer availability for high-temperature, high-salinity (HT/HS) reservoirs. In this study, the authors establish that HT/HS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultrahigh salinity conditions. Introduction Retention is a key factor for polymer propagation and acceleration of oil production by polymer flooding. In the complete paper, the authors consider HT/HS applications for carbonate reservoirs. Synthetic polymers such as partially hydrolyzed polyacrylamide are not thermally stable at temperatures above 60°C. The thermal stability of the synthetic polymers can be improved by incorporating monomers. To evaluate the retention of polymer in reservoir rock, dynamic retention experiments were performed in the presence and absence of oil. In homogeneous rock, the presence of residual oil typically will reduce the retention proportional to the surface covered by the oil saturation. Strongly heterogeneous rock containing fractures also may have low retention because the fluid flow mainly may be through highly permeable fractures or channels and, consequently, only part of the porous medium will contact polymer. Retention in carbonate matrix displacement (homogeneous rock) was performed on outcrop Indiana limestone for reference, but most experiments were made on reservoir rock material. The polymer used is SAV 10. Experimental Methods The easiest and, in many cases, most-accurate method for quantifying retention in dynamic coreflow experiments is by material balance. This refers to the measurement of the polymer in the effluent. The injected amount minus the backproduced amount of polymer gives the loss caused by transport through the porous medium. The retention includes both adsorption of polymer onto the rock and dynamic loss as the result of mechanical entrapment such as molecular straining and concentration blocking. In most cases, the authors used a passive tracer injected with the polymer and applied two slugs. The first slug quantifies the retention by material balance, but the difference in effluent of the second slug minus the first slug also can give an alternative measurement of the polymer retention. Comparing tracer and polymer effluent concentrations from the second polymer slug quantifies the inaccessible pore volume (IPV). The experimental setup is illustrated in Fig. 1.

Enhanced regained permeability and fluid flowback from tight sandstone and carbonate oil reservoirs with unique flowback chemistry

AbstractLarge amounts of aqueous‐based fluids used in hydraulic fracturing of tight formations are not fully recovered immediately after treatment, resulting in increased water saturation, water blockage, clay swelling, reduced relative permeability, and long‐lasting formation damage that impedes production. To enhance flowback fluid recovery, nano‐emulsion based flowback aids were developed for oil‐bearing sandstone and carbonate formations. The flowback aids were formulated using a blend of high‐temperature stable ester‐based solvents, alcohols, and surfactants to form optically clear nano‐emulsions. All the developed flowback aids demonstrated low surface tension (22–30 mN/m) and interfacial tension (<6 mN/m), which is necessary for reducing capillary pressure. The particle size of the nano‐emulsions was found to be 5–15 nm. The flowback aids were able to prevent the formation of the emulsion with crude oil. It has been found that nano‐emulsions formulated using non‐ionic and anionic surfactants worked better for sandstone, whereas non‐ionic and cationic surfactant‐based formulations worked better for carbonate. These formulations not only provide quick aqueous fluid displacement in column tests but also greatly enhance the rate of oil flow in core flow experiments conducted with broken slickwater fracturing fluids. It was determined that in the absence of a flowback aid, the regained permeability was around 40%, whereas with flowback aids it was increased to 65%–75%. The paper demonstrates the effectiveness of flowback enhancers to quickly recover the injected aqueous fracturing fluid, thereby reducing water saturation, which in turn enhances productivity, and shows the benefit of applying chemistry for low permeability oil reservoirs.

Study on the biodegradability of a chitosan‐modified hyperbranched polymer for enhanced oil recovery

AbstractThis study introduced a chitosan‐modified hyperbranched polymer (HPDACS). The biological oxygen demand, chemical oxygen demand, and biodegradability of HPDACS under different water quality were measured under static conditions, as well as the concentration changes before and after degradation. Environmental scanning electron microscopy (ESEM) was used to observe the micromorphology before and after degradation. The biodegradability, viscosity change, and molecular weight change of the polymer before and after passing through the porous medium were measured. The results were compared with the partially hydrolyzed polyacrylamide and the dendritic polymer. The results showed that in bacteria‐containing sewage, the biodegradation rate of HPDACS reached 81%. Moreover, the molecular backbone of HPDACS was completely broken after degradation. Its viscosity loss reached 84.87%, indicating its good biodegradability. HPDACS also can reduce the concentration of polymer in the produced fluid. In core flow experiments, viscosity of HPDACS is loss to 40%. The hyperbranched network structure of HPDACS can reduce the shearing action in the porous medium, thus reducing the extent of biodegradation. The presence of microorganisms resulted in a viscosity loss of HPDACS of ~2%. Therefore, HPDACS can fully exert the fluidity control effect through the porous medium and can meet the requirements of polymer flooding.

Experimental Study on the Effect of Long-Term Water Injection on Micropore Structure of Ultralow Permeability Sandstone Reservoir

During the long-term waterflooding (LTWF) in oil reservoirs, the formation is subject to permeability reduction as clay release and fine migration. At present, the mechanisms of permeability impairment in both macroscopic and microscopic pore structures in ultralow permeability reservoirs under LTWF are unclear. This statement epitomizes the main objective of this work: to understand how long-term waterflood changes porous structures and thus compromises permeability. The standard core flow experiments in conjunction with a couple of tests consisting of online nuclear magnetic resonance (NMR), high-pressure mercury intrusive penetration (HPMIP), X-ray diffraction (XRD), and scanning electron microscope (SEM) were performed to determine the mineral compositions, macrophysical properties, and micropore structures of two kinds of cores with different natures of pore distribution (i.e., unimodal and bimodal) before and after LTWF in Yan Chang field China. Results showed that the permeability decreased while the porosity increased after the LTWF. With respect to the pore size distribution, the small pores (SPs) decreased and the large pores (LPs) increased for both cores. For the unimodal core, the distribution curve shifted upwards with little change in the radius of the connected pores. For the bimodal core, the curve shifted to the right with an increasing radius of connected pores. With respect to the characteristic parameters, the average pore radius, median pore radius, structural coefficient, and tortuosity increased, while the relative sorting coefficient decreased. The relative changes of the parameters for the unimodal core were much smaller than those for the bimodal core. With respect to the clays, chlorite accounted for a majority proportion of the clays, and its content increased after LTWF. According to these changes, the mechanism of LTWF at different stages was interpreted. At the early stages, the blockage of the released clays occurred in SPs. Some of the middle pores (MPs) and LPs became larger due to the release and some of them became smaller due to the accumulation. At the middle stage, the blockage of SPs weakened. Some flow channels formed by MPs and LPs became dominant flow channels gradually. The effluxes of particles occurred, resulting in a significant increase in porosity. At the late stage, the stable flow channels have formed. The higher response of the bimodal core to LTWF could be attributed to its higher content of chlorite, which was more likely to accumulate. This study clarifies the mechanism of fine-migration-induced formation damage in microscopic pore structures and the migration pattern of clay minerals in ultralow permeability reservoirs. The work provides potential guidance for optimizing waterflood strategies in ultralow permeability reservoirs.

Isolating, identifying and evaluating of oil degradation strains for the air-assisted microbial enhanced oil recovery process.

Due to the inefficient reproduction of microorganisms in oxygen-deprived environments of the reservoir, the applications of microbial enhanced oil recovery (MEOR) are restricted. To overcome this problem, a new type of air-assisted MEOR process was investigated. Three compounding oil degradation strains were screened using biochemical experiments. Their performances in bacterial suspensions with different amounts of dissolved oxygen were evaluated. Water flooding, microbial flooding and air-assisted microbial flooding core flow experiments were carried out. Carbon distribution curve of biodegraded oil with different oxygen concentration was determined by chromatographic analysis. The long-chain alkanes are degraded by microorganisms. A simulation model was established to take into account the change in oxygen concentration in the reservoir. The results showed that the optimal dissolved oxygen concentration for microbial growth was 4.5~5.5mg/L. The main oxygen consumption in the reservoir happened in the stationary and declining phases of the microbial growth systems. In order to reduce the oxygen concentration to a safe level, the minimum radius of oxygen consumption was found to be about 145m. These results demonstrate that the air-assisted MEOR process can overcome the shortcomings of traditional microbial flooding techniques. The findings of this study can help for better understanding of microbial enhanced oil recovery and improving the efficiency of microbial oil displacement.

Synthesis of new PPG and study of heterogeneous combination flooding systems

For the problem wherein a reservoir demonstrates strong heterogeneity after polymer flooding and the conventional oil displacement method cannot effectively displace the oil in the low-permeability layer, preformed particle gel (PPG) is synthesized and forms a heterogeneous composite oil displacement system with a weak-base alkali–surfactant–polymer (ASP) system. The core flow and oil displacement experiments were conducted to test the PPG performance. The injection parameters of the heterogeneous system were optimized, and the oil displacement effect was evaluated. Results show that the best synthesis parameters of PPG are as follows – 25% acrylamide, 25% degree of hydrolysis, 1.5 × 10–3 g of cross-linking agent, and 2.25 × 10–2 g of initiator. PPG can swell slowly and has good salt and temperature resistance; the particles with different particle sizes have good elasticity and strength after complete expansion, and they have good compatibility with cores having different permeability values. Compared with the weak-base ASP system, the heterogeneous system can maintain interfacial tension on the order of 10–3mN/m when the concentrations of the alkali and the surfactant are low. The heterogeneous system can (i) achieve adaptive sealing of the formation owing to its good deformation recovery ability, (ii) play the role of liquid flow steering, (iii) adjust the water absorption profile, and (iv) improve heterogeneity. The optimal component concentration of the heterogeneous system is 500 mg/L PPG, 1400 mg/L polymer, 0.3% petroleum sulfonate, and 1.2% sodium carbonate, the best injection method being one wherein a heterogeneous system and a weak-base ASP system are injected alternately.

Development of Selective Acidizing Technology for an Oil Field in the Zechstein Main Dolomite

This paper presents laboratory studies based on which a stimulation technology for an oil field located in the Zechstein Main Dolomite was investigated. A large number of oil wells in the Main Dolomite produce significant amounts of reservoir water. Matrix acidizing using conventional acid solutions in such wells has caused a significant increase in water cut, because of their affinity for water. The purpose of this cooperation between the Oil and Gas Institute–NRI and the Brenntag Polska was to develop an acid treatment technology that would not increase the water cut after acidizing treatment in wells where oil production is accompanied by the production of reservoir water. Therefore, a series of tests were performed, including the selection of a suitable viscoelastic surfactant that was sensitive to crude oil. The contact of the gel of the viscoelastic surfactant fluid with crude oil resulted in the reduction of its viscosity The tests described herein include dissolution/dispersion tests, rheological tests, acid sludge tests, compatibility tests, core flow experiments, and corrosion tests, which allowed recipes to be developed for the preflush, diverter, and acidizing liquid. Then, recommendations were established for using these liquids in matrix acid treatment. A series of treatments performed according to this technology allowed the removal of near-wellbore damage without increasing the water cut.

Cause analysis and solutions of water blocking damage in cracked/non-cracked tight sandstone gas reservoirs

After hydraulic fracturing treatment, a reduction in permeability caused by the invasion of fracturing fluids is an inevitable problem, which is called water blocking damage. Therefore, it is important to mitigate and eliminate water blocking damage to improve the flow capacities of formation fluids and flowback rates of the fracturing fluid. However, the steady-state core flow method cannot quickly and accurately evaluate the effects of chemical agents in enhancing the fluid flow capacities in tight reservoirs. This paper introduces a time-saving and accurate method, pressure transmission test (PTT), which can quickly and quantitatively evaluate the liquid flow capacities and gas-drive flowback rates of a new nanoemulsion. Furthermore, scanning electron microscopy (SEM) was used to analyze the damage mechanism of different fluids and the adsorption of chemical agents on the rock surface. Parallel core flow experiments were used to evaluate the effects of the nanoemulsion on enhancing flowback rates in heterogeneous tight reservoirs. Experimental results show that the water blocking damage mechanisms differ in matrices and fractures. The main channels for gas channeling are fractures in cracked cores and pores in non-cracked cores. Cracked cores suffer less damage from water blocking than non-cracked cores, but have a lower potential to reduce water saturation. The PTT and SEM results show that the permeability reduction in tight sandstones caused by invasion of external fluids can be list as guar gum fracturing fluid > slickwater > brine. Parallel core flow experiments show that for low-permeability heterogenous sandstone reservoirs with a certain permeability ratio, the nanoemulsion can not only reduce reverse gas channeling degree, but also increase the flowback rate of the fracturing fluid. The nanoemulsion system provides a new solution to mitigate and eliminate water blocking damage caused by fracturing fluids in tight sandstone gas reservoirs.

Gelation studies of high molecular weight polymeric nanoparticles for application in fractured oil reservoirs with harsh conditions

ABSTRACT Nanostructured polymers (NSPs) due to the high water absorption, suitable dispersing in water, low initial viscosity, and deep penetration into the reservoir are potential alternative for common polymers in water shut-off processes. In this study, gelation kinetic of high molecular weight NSPs including copolymer of acrylamide (AAm) and 2-acrylamido-2-methyl-propanosulfonic acid (AMPS) in combination with chromium (III) acetate was studied by bottle test and rheology measurements. Finally, the potential of the NSPs gel to block harsh condition fractures was investigated by performing core flow experiments. The gelation time of 82 h was observed for a gel system containing 5500 ppm of poly(AAm-co-AMPS) nanoparticle and copolymer/cross-linker ratio (CCR) of 20 under aging at 90°C and 87,000 ppm salinity. The results of core flow experiments showed that the NSPs gel has strong blocking capacity to reduce fracture permeability by two orders of magnitude. Furthermore, gel blocking efficiency was found to be depended on both the fracture opening and salinity difference between gel solvent and produced water.

Development of a fast EoS based compositional model for three-phase core flooding

Compositional simulators are of great importance to model core flow experiments and enhanced oil recovery processes. In the present study, a semi-implicit, three dimensional EoS-based formulation is developed for modeling and simulation of core-flooding process. The model treats three-phase flow in cylindrical coordinates with no need to use an iterative numerical method. Overall composition, pressure and water saturation are calculated implicitly for each grid block. Using this approach, a linear set of equations with constant coefficients would be solved at each time step. It is assumed that there is no mass transfer between hydrocarbon phases and water phase. In addition, a new technique has been suggested to calculate transmissibility coefficients in each direction, which is a major problem in compositional modeling. Each transmissibility coefficient is divided into two general parts which are treated differently. The first part is constant and the second part is time-dependent. This model yields a robust and fast calculation procedure, which is validated using Eclipse simulation results. Simulation of several miscible flooding processes were performed using Eclipse core-flood models in order to compare the results with the developed in-house model. Results are matched reasonably while the computing time is considerably decreased using the in-house model. It is shown that using second Stone’s relative permeability model and Advanced Peng–Robinson Equation of State, best results are achieved with an average absolute relative deviation of 7.7% from Eclipse results for ultimate recovery factor. In addition, sensitivity analysis has been performed on several input data including time-step size and block number. Results show that in a reasonable range of these parameters, convergence problems are not encountered. We have developed an in-house simulator based on our model, which can be a basis for other compositional simulation purposes. In addition to decreasing computing time, convergence problems encountered in most implicit techniques would be avoided as well.

Carbonate acidizing: A mechanistic model for wormhole growth in linear and radial flow

Highly conductive fluid flow paths, known as wormholes, are formed when acids are injected in carbonate reservoirs during a stimulation treatment. In matrix acidizing treatments, these wormholes are desired whereas in acid fracturing treatments, they are undesirable because they reduce efficiency of the process. Two main types of models are available in the literature for wormhole growth. Semi-empirical models are computationally fast; however, they do not scale well to core dimensions or to radial flow. Numerical simulation models represent the physics of the individual processes well; however, they are computationally intensive and impractical to use on a field scale.To address the shortcomings of these models, a computationally fast mechanistic model is developed for wormhole growth. The model scales well with flow rate and core dimensions. It hence allows scale-up from linear laboratory core flow experiments to field scenarios of radial flow. Accurate scaling with core dimension and with injection rate in linear flow is a necessary precondition for a model to be considered for scale-up to radial flow where both cross-sectional area to flow and the fluid Darcy velocity change as the wormholes grow. Previous computationally fast models did not satisfy this precondition and therefore are not suitable for scaleup to radial flow.The model is validated against more than 50 published and internal sets of linear core-flood experiments on limestone and dolomite cores treated with HCl and emulsified acids. The validation dataset covers a wide range of acid concentrations, temperatures, rock types and core dimensions. The modeling equations extend to radial flow based on the change in the domain area with wormhole progression. The radial model was tested against 10 published radial flow experiments and a reasonable match was obtained. The model predictions were also tested against field results and again a good match was obtained.

Investigation on the Influence of Water-Shale Interaction on Stress Sensitivity of Organic-Rich Shale

Shale reservoirs are characterized by low permeability and natural fractures. In the process of reservoir development, the working fluid enters the reservoir. This may result in the formation of new fractures or expansion of natural fractures. When shale reservoirs are exploited, the fluid pressure in the fracture or pore is reduced. This destroys the stress balance of the reservoir, produces stress sensitivity damage, and reduces the reservoir permeability. Organic-rich shale from the Yanchang Formation, Chang 7 Member of the Ordos Basin, was selected for core flow experiment with helium. The effects of the type of brine, salinity, and soaking time on the stress sensitivity of an organic-rich shale reservoir were investigated. The acoustic characteristics were also investigated to study the effect of interactions between water and shale on stress sensitivity. The experimental results demonstrate that the interactions of water and shale increase the permeability of shale and reduce its stress sensitivity. Furthermore, when the permeability of the shale is excessively low, the stress sensitivity is high. In the acoustic studies, a higher attenuation coefficient of the acoustic wave corresponds to a larger variation in the shale structure and thus a larger permeability of the shale and smaller stress sensitivity coefficient. Whereas there is no apparent effect of the salt water type on the stress sensitivity, higher salinity levels cause higher stress sensitivity. After reacting with 15000 mg/L brine, the stress sensitivity coefficient of shale did not decrease significantly compared with that before action, all of which were above 0.97. However, after reacting with distilled water or 5000 mg/L brine, the stress sensitivity coefficient of shale decreased significantly, and all of them decreased to less than 0.9. Longer water exposures, corresponding to an increased duration of water-shale interactions, result in higher impacts on the stress sensitivity of shale. After 6 hours of shale-brine interaction, the stress sensitivity coefficient of shale is as high as 0.93, while after 48 hours of shale-brine interaction, the stress sensitivity coefficient of shale is reduced to 0.88. This study provides a highly effective reference with regard to the influence of the working fluid on the reservoir during drilling operations and the study of reservoir characteristics after fracturing.

Representation of a new physics-based non-Darcy equation for low-velocity flow in tight reservoirs

There has been a growing interest in the study of low-velocity non-Darcy flow in tight reservoirs. Most existing non-Darcy equations, however, are flawed in model assumption, equation derivation or field practicability. For another, current non-Darcy simulations are based on the traditional methods, which are incapable of describing the fracture-rich feature of tight reservoir geology. In light of this, this paper introduces a new physics-based non-Darcy equation for low-velocity flow from four aspects: equation derivation, experimental validation, flow simulation and flow analysis. The rigorous derivations of the new equation are presented with a modified Buckingham-Reiner equation in which the boundary layer effect and the Bingham fluid behavior are described. The non-Darcy coefficient controlled by the boundary layer parameter and threshold pressure gradient (TPG) is incorporated into Darcy's equation. The equation validations are performed by liquid column experiment and core flow experiment, which yields good matching relationship between modeled values and observed values. The non-Darcy flow simulation is based on the triangle-gridded discrete fracture-matrix model (DFM) which can model arbitrary fractures. The upstream weighting scheme for computing the non-Darcy transmissibility is proposed to improve numerical robustness. Then the scheme is implemented by constructing non-Darcy operators, consisting of half-face upstream weighting operator and gradient operator, and further setting up the Automatic Differentiation (AD)-style discrete equations. The studies on non-Darcy flow in matrix coupled with Darcy flow in fracture are performed by modeling two types of fractured reservoirs. Detailed analyses are illustrated with pressure transient, long-term well bottom pressure and pressure map.

Synergism of polyvinyl alcohol fiber to hydrogel for profile modification

Water production is getting worse along with the continuous water injection in the reservoir with fracture, but common hydrogels cannot be successfully applied for water shutoff due to its poor resident ability in fracture. In this work, an interpenetrating network hydrogel has been developed innovatively by polyvinyl alcohol (PVA) fiber and common polyacrylamide (PAM) hydrogel. Plugging ability, long-term thermal stability and the interaction between PVA fiber and hydrogel were detailedly studied. Results show that PVA fiber is beneficial to the stability of the PAM hydrogel, and the syneresis rate can be decreased from 30% to 3% on the 120th day. PVA fiber accelerates the hydrogel gelation, and the high concentration of fiber leads to good hydrogel strength. PVA fiber increases the amount of the bound water in hydrogel, leading the hydrophilcity increase of hydrogel. An interpenetrating network is formed on the micrometer level, resulting from the three-group crosslinking among polymer, cross-linker and fiber. Compared with common PAM hydrogel, the interpenetrating network hydrogel has better water shutoff effect and EOR performance. Core flow experiment and micromodel test show that the interpenetrating network hydrogel forms an effective bridge in fracture, and it is hard to be moved due to the water washing. The introduction of fiber to hydrogel is an innovative research, which not only improves the water shutoff effect of hydrogel in fracture, but also provides reference to increase the performance of drilling fluid, fracturing solution and EOR polymer utilized in petroleum engineering.

Research on heterogeneous compound flooding system based on dispersed particle gel

Aiming at the problem that the heterogeneity of the reservoir became strong, the remaining oil distributed universally after polymer flooding and the existing chemical compound flooding systems had limited application, a heterogeneous compound flooding system based on gel dispersion particles (DPG) was proposed as a substitution technology for further enhanced recovery of reservoirs after polymer flooding. This paper has carried out the design and characterization of heterogeneous compound flooding system, influencing factors, and application performance. With the system viscosity and oil-water interfacial tension as evaluation indicators, the application performance of the optimized heterogeneous polymer flooding system based on DPG was examined. The results showed that the system viscosity was 12.1 to 17.3 mPa•s while the interfacial tension was maintained at 10 -3 mN/m magnitude. At 80 °C, with 60 days aging, the viscosity retention ratio of the system is over 83.5%, and the interfacial tension between oil and water was still maintained at 10 -3 mN/m. The core flow experiment shows that, the heterogeneous compound flooding system has good injection performance, moving characteristics of plugging, breakthrough migration and re-plugging. After high-temperature aging, subsequent water flooding still maintained at a high pressure with good resistance to erosion. Through the selective high and low permeability layers, the water absorption profile was improved, and finally enhanced oil recovery to 20.61% after polymer flooding. Cited as : Li, H., Wang, K., Han, X., Zheng, J. Research on heterogeneous compound flooding system based on dispersed particle gel. Advances in Geo-Energy Research, 2019, 3(2): 156-164, doi: 10.26804/ager.2019.02.05

Effect of surfactant concentration on foam texture and flow characteristics in porous media

Foam has been widely used for profile control, water plugging, and gas channeling control in enhanced oil recovery (EOR). Because of absorption, the surfactant concentration in foam decreases along the flow direction. In this study, the effects of surfactant concentration on the foam texture, foam seepage characteristics, and gas saturation were evaluated by core-flow experiments using a high-pressure visualization device. The results show that the surface tension of gas and liquid decreases, the flow resistance in core increases, and the foam takes a longer time to reach stability with the increase in concentration of foaming agent. The blocking capability of foam in porous media is closely related to foam texture. With the increase in surfactant concentration, the average diameter of bubbles in porous media decreases, and the bubbles are more uniform. Moreover, the diameter of bubbles is closer to the average pore diameter of core. Clearly, the diameter matching degree of the maximum distribution frequency of bubbles and the average pore diameter of core increase. Therefore, the blocking capability of foam becomes stronger. With the increase in surfactant concentration, the proportion of trapped gas in porous media increases, the gas saturation in core increases, and the flow resistance of foam increases. However, when the surfactant concentration reaches the critical value, the increasing amplitude of gas saturation decreases. Under an injected foam quality of 50%, the gas saturation is more than 80%. The research results can help to analyze the change along the channel of foam flow in formation and are of great significance to improve the effect of foam application.

Development of a High-Temperature-Resistant Polymer-Gel System for Conformance Control in Jidong Oil Field

Summary The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.

Stability, seepage and displacement characteristics of heterogeneous branched-preformed particle gels for enhanced oil recovery.

Inspired by the viscoelastic displacement theory and the advantages of preformed particle gels, we develop an innovative product called branched-preformed particle gel (B-PPG) for enhanced oil recovery. Due to its excellent viscoelastic properties, B-PPG can be used both in profile control and to improve sweep efficiency in heterogeneous reservoirs. Laboratory experiments indicate that B-PPG shows improved stability and long-term aging resistance under high temperature and salinity when compared with HPAM. The migration and displacement behaviors of B-PPG are studied by a series of sandpack core flow experiments. The results show that the B-PPG particles can migrate through the porous media, and the migration is a dynamic process of plugging and flooding. Besides, B-PPG can significantly create fluid diversion and increase the swept volume in low permeability zones. Moreover, micro visualization and oil displacement experiments are also carried out and prove that B-PPG can displace residual oil in small channels, leading to a high swept volume and enhanced displacement efficiency.

The damage mechanism of oil-based drilling fluid for tight sandstone gas reservoir and its optimization

The B block is a typical tight sandstone gas reservoir in Tarim basin in the Xinjiang Uygur Autonomous Region, China. In this block, the skin factors of each well drilled by oil-based drilling fluids were high and the reservoir damage was serious. The permeability recovery rates of two kinds of oil-based drilling fluids used in site were both less than 60%. To investigate the damage mechanism, the particle size distribution was tested to analyze solids damage incorporating the pore throat radius and micro-fracture width in this block. The contact angles of deionized water on reservoir cores before and after polluted by oil-based filtrate were measured to analyze the wettability alteration. Core flow experiment was applied to evaluate oil phase trapping, and the emulsion droplets formed by mixing oil-based filtrate with formation water were observed to analyze emulsion plugging damage. Based on the test results, the factors causing damage to the tight sandstone gas reservoir included solid phase invasion to fractures, wettability alteration, oil phase trapping and emulsion plugging.Therefore, the oil-based drilling fluids were optimized from aspects of reduction of the filtration loss, improvement of the sealing ability of the micro-fractures and reduction of the oil-water interfacial tension. A temporary plugging agent was compounded by using the Ideal Packing Theory, which could effectively plug the micro-fractures. The surfactant was optimized, and it could destroy the oil-based filtrate cake effectively and break emulsion in a short time. The permeability recovery rate of optimized oil-based drilling fluids was evaluated and the results showed that permeability recovery rate was 87.40% and 86.74%. Furthermore, cores early contaminated by oil-based drilling fluid were treated by optimized surfactant, and the tested permeability recovery rate reached more than 100%.

Compositional modeling of nanoparticle-reduced-fine-migration

During waterflooding, formation fines migration is a recognized reason for well injectivity and productivity reduction in sandstone reservoirs. Permeability decrease due to fines migration is one of the major issues in the application of low salinity enhanced oil recovery techniques. Recently, nanoparticles injection is found to reduce the fines release in sandstone cores through adsorption on the pore surface. In this research, a numerical model is developed to explore the coupling processes of nanoparticle transport, fine attachment and release, aqueous species reactive transport, and multiphase flow.Components including oil, water, salt, fine particles and nanoparticles are considered in this model. Both fluid dynamics and physical interactions are integrated in the coupled simulation approach. The nanoparticles exist in aqueous phase during injection, and can be attached to the solid surfaces to decrease surface energy. The formation fines can be suspended in aqueous phase, or retained by pore throats that decrease the permeability. The fines retention is modeled as a dynamic process where the retention rate is a function of salinity, nanoparticle adsorption, and flow velocity. The wettability alteration due to nanoparticle and low salinity is also included. A compositional simulator is developed based on implicit pressure explicit composition to include the detailed mathematical description of the complex processes.This paper provides detailed procedures of building a nanoparticle and fines transport and interaction model. To calibrate the diffusion/dispersion and adsorption isotherm constants, lab core flow experiments with nanoparticle injection are simulated. The fines migration experiments are simulated with and without nanoparticle injection at varying salinity. Simulation results demonstrate that the nanoparticle injection can effectively reduce the fine release and prevent permeability decrease at different salinity. In addition, the heterogeneous field scale simulation was performed. The oil recoveries with and without nanoparticle injection are compared for low salinity water injection. The simulation results indicate that using nanoparticles in low salinity waterflooding can improve oil recovery with mitigated formation damage.This work demonstrates a compositional model that can be used to simulate nanoparticle technology enhancing waterflooding performance. It is believed to be the first numerical model that explicitly includes the nanoparticle transport and its effect on fines migration. This paper will improve the understanding of geochemical conditions and spatial distribution of fines retention and whether the sweep efficiency will be improved.