ASP Flooding Research Articles

Experimental Study on Optimization of Polymer Preslug Viscosity of ASP Flooding in Interlayer Heterogeneous Well Group Artificial Sandstone Core

An artificial sandstone core model of large well group of positive rhythmic heterogeneous reservoir was designed and made for the simulation of ASP flooding experiment in the moderate heterogeneous reservoir. The well layout of one injection and one production was employed for the core model, to simulate the influence of polymer preslugs with different viscosity on ASP flooding effect. The experimental results show that the injectability of the polymer preslug and the effect of relieving the conflict of remaining oil production in each layer are related to the viscosity of the system. In the heterogeneous core model with the coefficient of variation of 0.65, under the constraint of the same amount of polymer agent, the ASP flooding effect of the 0.075 PV, 60 mPa·s polymer preslug was better than that of the 0.093 PV, 40 mPa·s and 0.064 PV, 80 mPa·s polymer preslugs. The change in the viscosity of the polymer preslug did not enable the ASP system to effectively exploit the low-permeability layer though. As the viscosity increased, the pressure difference between injection and production increased; the remaining oil could be exploited effectively at the bottom of the high-permeability layer and the medium-permeability layer as well as the injection end of the medium-permeability layer. If the viscosity is too small, the high-permeability area cannot be effectively blocked by the injected chemical agent, and if the viscosity is too large, the injected chemical agent cannot produce good elastic displacement relationship, which will lead to ineffective chemical agent flow. Therefore, the polymer preslug viscosity of the ASP flooding system should be moderate, and cores with different heterogeneity should have a reasonable viscosity matching range.

Towards efficient solar demulsification (I): A solar electrical role on interfacial film of emulsions

Oil/water separation has become a significant issue since emulsions are detected in many industrial wastewater and severely threaten the ecological environment. Developing separation technique driven by solar energy with high separation efficiency is quite meaningful and challenging. In this work, solar electrical role on an interfacial film of emulsions was developed for efficient oil/water separation. Emulsified oil/water droplets from the ASP flooding were chosen to characterize the influence of solar electrical role on demulsification. Droplet size distribution, zeta potential, interfacial tension, viscosity, microscope image, and rheological properties were systematically studied to explore the mechanism of electrical role on the instability of oil droplets. Experimental results indicate solar electrical role on the oil-water interface can change the properties of the interface, help the oil-water emulsion instability, and promote oil-water separation. The instability mechanism of the emulsion can be summarized as the following. Firstly, the charged oil/water droplets interfere with the original electric field, which generates a force along with the droplet's tangential direction. Secondly, the force drives charged groups to radially migrate away from the electrode, which causes the entangled polymer to loosen, expand, and rearrange interface charges, resulting in decreasing in the rigidity and zeta potential. Thirdly, the force also promotes the electrohydrodynamic flow of oil/water droplets. The adjacent oil/water droplets mutually entrained in electrohydrodynamic fluid flow, resulting in coalescence. Furthermore, the interface-active components can be electrochemically oxidized to small molecular. The in-depth research of solar electrical role on interfacial film provides theoretical support for coupling of solar photo effect and thermal effect, to obtain highly efficient solar demulsification.

Polyamidoamine grafted with magnetic material (M-G n -PAMAM): an efficient demulsifier for oil-contaminated industrial wastewater

A magnetic demulsifier, denoted M-G n -PAMAM (n = 1, 2, 3), was synthesized by reacting polyamidoamine (PAMAM) dendrimers with Fe3O4@SiO2. The characteristics of magnetic nano-polymer were investigated via using XRD analysis, FT-IR, TEM, and VSM methods. The as-prepared M-G n -PAMAM was highly effective at removing oil from wastewater produced from ASP flooding, with a maximum oil removal rate of 94% at 60 °C. Furthermore, the regeneration experiments illustrated that M-G n -PAMAM could be readily recovered by an external magnetic field and it could be recycled up to 9 times without a significant loss in demulsification efficiency. In conclusion, the magnetic demulsifier synthesized in this study could be a promising nanomaterial for use in emulsified oil-water separation.

Examination of literature on colloidal dispersion gels for oil recovery

This paper examines literature that claims, suggests, or implies that floods with “colloidal dispersion gels” (CDGs) are superior to polymer floods for oil recovery. The motivation for this report is simple. If CDGs can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker, then CDGs should be used in place of polymer solutions for most/all polymer, surfactant, and ASP floods. In contrast, if the claims are not valid, (1) money spent on crosslinker in the CDG formulations was wasted, (2) the mobility reduction/mobility control for CDG field projects was under-designed, and (3) reservoir performance could have been damaged by excessive loss of polymer, face-plugging by gels, and/or excessive fracture extension. From this review, the clear answer is that there is no credible evidence that colloidal dispersion gels can propagate deep into the porous rock of a reservoir, and at the same time, provide resistance factors or residual resistance factors that are greater than those for the same polymer formulation without the crosslinker. CDGs have been sold using a number of misleading and invalid arguments. Very commonly, Hall plots are claimed to demonstrate that CDGs provide higher resistance factors and/or residual resistance factors than normal polymer solutions. However, because Hall plots only monitor injection pressures at the wellbore, they reflect the composite of face plugging/formation damage, in-situ mobility changes, and fracture extension. Hall plots cannot distinguish between these effects—so they cannot quantify in situ resistance factors or residual resistance factors. Laboratory studies—where CDG gelants were forced through short cores during 2–3 h—have incorrectly been cited as proof that CDGs will propagate deep (hundreds of feet) into the porous rock of a reservoir over the course of months. In contrast, most legitimate laboratory studies reveal that the gelation time for CDGs is a day or less and that CDGs will not propagate through porous rock after gelation. A few cases were noted where highly depleted Al and/or HPAM fluids passed through cores after one week of aging. Details about these particular formulations/experiments were sparse and questions remain about their reproducibility. No credible evidence indicates that the CDG can propagate deep into a reservoir (over the course of weeks or months) and still provide a greater effect than that from the polymer alone. With one exception, aluminum from the CDG was never reported to be produced in a field application. In the exception, Chang reported producing 1–20% of the injected aluminum concentration. The available evidence suggests that some free (unreacted) HPAM and aluminum that was associated with the original CDG can propagate through porous media. However, there is no evidence that this HPAM or aluminum provides mobility reduction greater than that for the polymer formulation without crosslinker.

Capillary Desaturation Tendency of Hybrid Engineered Water-Based Chemical Enhanced Oil Recovery Methods

Several studies have shown the synergetic benefits of combining various chemical enhanced oil recovery (CEOR) methods with engineered waterflooding (EWF) in both sandstones and carbonate formations. This paper compares the capillary desaturation tendency of various hybrid combinations of engineered water (EW) and CEOR methods with their conventional counterparts. Several coreflood experiments were conducted, including EW-surfactant flooding (EWSF), EW-polymer flooding (EWPF), EW-alkali-surfactant flooding (EWASF), EW-surfactant-polymer flooding (EWSPF), and EW-alkali-surfactant-polymer flooding (EWASP). Capillary numbers (Nc) and corresponding residual oil saturation (Sor) for each scenario are compared with capillary desaturation curves (CDC) of conventional CEOR methods from the literature. The results indicate that hybrid EW–CEOR methods have higher capillary desaturation tendency compared to conventional methods. The capillary numbers obtained by standalone polymer flooding (PF) are usually in the range from 10−6 to 10−5, which are not sufficient to cause a significant reduction in Sor. However, the hybrid EW-polymer flooding approach considerably reduced the Sor for the same Nc values, proving the effectiveness of the investigated method. The hybrid EWASP flooding caused the highest reduction in Sor (23%) against Nc values of 8 × 10−2, while conventional ASP flooding reduced the Sor for relatively higher Nc values (3 × 10−3 to 8 × 10−1). Overall, the hybrid methods are 30–70% more efficient in terms of recovering residual oil, compared to standalone EWF and CEOR methods. This can be attributed to the combination of different mechanisms such as wettability modification by EW, ultralow interfacial tension by alkali and surfactant, reduced surfactant adsorption by alkali addition, and favorable mobility ratio by polymer. Based on the promising results, these hybrid techniques can be effectively implemented to carbonate formations with harsh reservoir conditions such as high salinity and high temperature.

Study of fine tapping potential of poor reservoirs in late stage of high water cut

At present, the oilfield development has entered the late stage of high water cut, and the exploitation objects have been changed to the second and third types of oil layers. The distribution of remaining oil is highly fragmented and complex, and the exploitation difficulty is gradually increasing. In view of a series of geological characteristics of Development Zone A, such as “numerous layers, complex reservoirs, severe phase transition and high viscosity”, the potential tapping technologies of Class II and Class III reservoirs, such as combination of two and three and ASP flooding, have been carried out one after another. In order to further enhance oil recovery and increase recoverable reserves, a large number of fracturing measures have been implemented to increase oil production. In view of the fact that it is more and more difficult to select wells and layers by this measure, we combine the results of fine reservoir description with dynamic data, take Block B as the investigation object, establish the potential pool of sedimentary unit-level measures, recognize the potential distribution of 82 different sedimentary units, clarify the target units of potential tapping measures, and finally explore relatively perfect ways and means to optimize fracturing well layers, and strive to achieve targeted adjustment and accurately tap potential. At present, in the early stage of fracturing in this area, the average daily oil increase of a single well is 7.9 tons, and the above practices also provide empirical reference and guidance for other similar blocks.

Application of Chemical Flooding in Increasing Yield of Tertiary Oil Recovery

This paper mainly explores the application measures of chemical flooding in increasing yield of tertiary oil recovery to. In the research process, taking the overview of tertiary oil recovery as the starting point, analyze that oil extraction can be divided into three stages, tertiary oil recovery as the last link, and the crude oil recovery rate needs to be improved. On the basis of this research, the application mechanisms of polymer flooding, alkaline flooding, surfactant flooding, and ASP flooding are proposed, make actual application measures are clear, so as to provide references for related workers.

Weak alkali ASP flooding in the second type reservoir in the A OilfieldProfile control technology and effect

Profile control technology refers to the operation of plugging high permeability layers from injection wells, which can adjust the suction profile of injection layers and improve the ultimate recovery. In this paper, the heterogeneity of the weak alkali ternary compound block of the second kind of oil layer in the A area of the some Second Division is strong, the injection conditions between well groups are different, the injection pressure level of some wells is low, the suction conditions of each sedimentary unit are different, and the comprehensive water cut of the block is high. In order to alleviate the contradiction between in formation and in plane, improve the utilization rate of chemical agents, and improve the ultimate recovery rate of the block, the deep profile control is carried out according to the characteristics of the oil layer development of the well group. Ten profile control wells were selected to adopt the profile control system of one and two polymer gel, which is a water shutoff agent for oil production. The polymer solution was used to carry particles for deep profile control. In this paper, the characteristics of profile control technology and the method of well and layer selection are studied, and the change law of dynamic index after profile control is analyzed in detail.

Analysis of Reservoir Plugging in Later Development Stage of ASP Flooding in Block X

In the ASP flooding block X, there are some phenomena such as the abnormal law of agent concentration and the acceleration of water cut rise in some well groups. Analysis shows that it is mainly affected by the factors such as serious reservoir plugging and reservoir production situation decline. In this paper, injection wells in this block are divided into three categories: stimulation wells, non-stimulation wells and profile control wells and blocking condition and cause are analyzed. Based on this, the corresponding countermeasures are given for various wells. It can effectively improve the injection status of block X, so as to improve the development status of the block.

Discussion on comprehensive adjustment technology of weak alkali ASP flooding in stage development of second-class reservoir

The application of ASP flooding development by stages and comprehensive adjustment technology plays a very important role in the development of the second-class reservoir, which is directly related to the development effect of the second-class reservoir and also improves the development effect of the reservoir to a certain extent. In this paper, the author analyzes and studies the comprehensive adjustment technology of ASP flooding in different stages. Taking SD block as an example, the development of the second-class reservoir is expounded, and the weak alkali ASP flooding technology is applied in different stages of the development of the second-class reservoir in SD block.

Application and Evaluation of Ternary System Deep Profile Control Technology

The development process of ASP flooding is strong in stages, and the contradictions in each injection stage are prominent. In the profile adjustment stage, there are still some wells and layers with poor plugging control effect, and the injection system is inefficient and ineffective, which not only causes the waste of high-cost injection system, but also can not effectively displace the remaining oil, which affects the expansion of swept volume and enhanced oil recovery. Therefore, deep profile control technology should be adopted to further assist profile control adjustment, but conventional profile control agents are not applicable due to the existence of alkali in ternary injection system. In this paper, the type of profile control agent suitable for ternary injection system is optimized by laboratory test, and the principle of well and layer selection is optimized. The profile control opportunity is summarized by comparing the profile control effects of four ternary industrial blocks. Through deep profile control technology, the inter-layer and intra-layer contradictions in an industrial block of ASP flooding were alleviated, and the utilization ratio of ASP system in reservoir production degree was effectively improved, and the development effect was improved.

Research and Countermeasures of interlayer interference in main reservoir of ASP flooding

According to the recognition of the industrial production of ternary compound flooding in a development zone, it is believed that the development mode of ASP flooding can expand the sweep efficiency, improve the development effect of a class of oil layers and further improve the recovery. However, the contradiction between A I 33 and upper A I 1-32 layers is prominent, which leads to uneven oil production, rapid rise of water cut in the production wells, short time of low value period and so on. In order to reduce the interlayer contradiction, the interlayer contradiction coefficient is introduced to study the interlayer interference law in different development stages of ASP flooding in combination with reservoir type and vertical heterogeneity of an oilfield, and the technical countermeasures for layered system development are put forward. The straight joint development technology is adopted in some potential areas of an l test area to exploit A I 3 reservoir, and the ideal development effect is achieved. The production degree of the reservoir is 88.3%, and the enhanced oil recovery is 26.23%.

Analysis on the Effective Characteristic of Different Displacement Ways of Tertiary Oil Recovery in the Class II Reservoir of Sazhong Development Zone

The first industrial tertiary oil recovery of the class II reservoir in the Sazhong Development Zone was the polymer flooding carried out in Block X at the end of 2002, and achieved noticeable effect. As the class II reservoir blocks were exploited one after another, by combining different geological structures and reservoir characteristics with distribution characteristics of remaining oil, the displacement modes successively went through polymer flooding, strong alkali ASP flooding, weak alkali ASP flooding, and salt-resistant polymer flooding, etc. Considering there are big differences in the geological structure, reservoir characteristics and layer combination of different class II reservoir blocks in the Sazhong Development Zone, and the development effects of different displacement modes are different as well; therefore, it is necessary to learn from the phased results achieved in typical blocks and leading pilot, on this basis, further conduct in-depth comparative study of the characteristics of effective rule and the changes of injection-production parameters of the class II reservoir blocks that have carried out tertiary oil recovery under different displacement modes, provide technical support and selection basis for betting modes up and down of the class II reservoir in the future, and it is of great practical significance to the realization of quality and efficiency improvement and sustainable development of the oilfield.

Production of Biodegradable Sulfonated Methyl Ester by a Falling Film Reactor for ASP Flooding in EOR

Petroleum production can be improved through enhanced oil recovery (EOR) methods such as chemical injection. This study focused on sulfonation of methyl ester using SO3 dissolved in oleum compounds (H2SO4.SO3) in a mini-pilot falling film reactor at 70 °C and its application for chemical EOR with ASP flooding. The reactor was equipped with cooling water to facilitate heat transfer in view of the highly exothermic reaction. Biodegradable methyl ester sulfonate, a biosurfactant, was produced from esterification of vegetable oils, palm kernel oil, and coconut oil. The MES products were characterized by Fourier transform infrared testing, which showed S=O and -OH groups peaks, indicating that sulfonation had occurred. The IFT test data showed that the MES from CNO produced the lowest IFT values for light oil and heavy oil, equal to 11.4 mN/m and 10.3 mN/m, respectively. The effect of the MES concentration on the phase behavior was an increase of the IFT value before being applied in ASP flooding, and a decrease after reaching the optimum condition. The EOR core flooding test with the formulated ASP resulted in original oil in place (OOIP) percentages in the range of 12 to 23.5%. The highest acquisition was 23.53% OOIP for an ASP composition of 200 ppm, 0.5%wt, 2800 ppm, respectively.

Effects of secondary emulsification of ASP flooding produced fluid during surface processes on its oil/water separation performances

Effects of secondary emulsification of field ASP flooding produced fluid by centrifugal pumps and electrostatic field on its oil/water separation performances were evaluated. Secondary emulsification of certain ASP flooding produced fluid with high surfactant content by centrifugal pumps drastically downgraded its oil/water separation performances, increasing the residual water-cuts after 24h static settling at 60 °C respectively by 70% for original o/w emulsion and 1080% for w/o emulsion. Certain w/o emulsion produced by ASP flooding with high surfactant content was susceptible to secondary emulsification in high strength electrostatic field with up to 660% increase of residual water-cut after 24h static settling at 60 °C. Mechanisms governing the effects of secondary emulsification on the oil/water separation performances of ASP flooding produced fluid were discussed. In comparison with produced fluid by water flooding and polymer flooding, the oil/water interfacial tension in ASP flooding produced fluid is much lower, making oil droplets in water and water droplets in oil significantly more sensitive to shear and high strength electrostatic field. Energy dissipation rate, surfactant content and the volume ratio of dispersed phase in the emulsion were identified to be the most important factors affecting the secondary emulsification of ASP flooding produced fluid in turbulent flow. Water in oil emulsion extracted from high water-cut o/w or w/o/w ASP flooding produced fluid was found to have significantly higher water phase surfactant content than the original crude oil emulsion and is much more susceptible to secondary emulsification in turbulent flow than the original reverse emulsion. Surfactant content, content of dual wettability micron and submicron sized particles and the strength of electrostatic field were found to be major factors affecting the secondary emulsification of ASP flooding produced w/o emulsion in AC electrostatic field. As interfacial tension between oil and water in w/o emulsion produced by ASP flooding can be 1 to 2 orders lower than that in the w/o emulsion produced by water flooding and polymer flooding, strength of electrostatic field in electrostatic treaters has to be optimized as per the surfactant content in the ASP flooding produced w/o crude oil emulsion they treat.

Study on Influencing Factors of Throat-like Residual Oil

The microscopic visualization model is used to carry out oil displacement experiments, to test the interfacial tension of the ASP system, and to study the effect of different conditions on the throat-like residual oil by recording dynamic images of the residual oil during the displacement process. The results show that: when the concentration of polymer and alkali is unchanged, the higher the concentration of surfactant, the lower the interfacial tension of the ASP system; the water-wet attribute model is more conducive to the oil displacement system's use of residual oil. The lower the interfacial tension of the ASP system, the better the effect on the throat-like residual oil. when the interfacial tension reaches 10-2, the effect is obvious; after water flooding, the pore-throat ratio and the maximum diameter of the pores have little effect on the residual oil distribution. It has an effect on the residual oil distribution of the minimum diameter of the pores. After the ASP flooding, the large pore-to-throat ratio, the small minimum diameter, and the small maximum diameter have a greater impact on pores with different wettability.

三元复合驱采出污水回注驱油处理方法探讨

三元复合驱采出污水回注驱油处理方法探讨

Design and Exploration of the Interfacial Rheological Properties of Lipopeptide Composite Weak Base ASP Flooding in Experimental Teaching

Design and Exploration of the Interfacial Rheological Properties of Lipopeptide Composite Weak Base ASP Flooding in Experimental Teaching

Development of a compositional reservoir simulator for chemical enhanced oil recovery processes

To make decisions and ensure successful field development, oil companies use numerical simulation tools, including hydrodynamic simulators. This work is devoted to the development of a reservoir simulator based on a new formulation of partial differential equations of the chemical compositional model, as well as its testing by comparing the results of traditional and ASP flooding simulation with similar results of well-known simulators.

Evaluation Method of Antiscaling Performance of Downhole Tools for ASP Flooding in Daqing Oilfield

At present, the technology of ASP flooding in Daqing Oilfield has entered the stage of industrialization and popularization. The total number of injection wells of ASP flooding has reached more than 4000. At present, the main problem of ASP flooding layered injection wells is that after injection of ASP compound solution for a certain period of time, the displacement effect is poor due to the sticking of scale and micelle in the partial hole and throttling element of injector A series of influences, such as the increase of the workload and the shortening of the period of measurement and adjustment, etc. However, the existing anti scaling technology mainly deals with the parts that are easy to scale, which has the advantages of high lubrication, low friction and non viscosity. However, due to the variety and different performance, it is necessary to compare and evaluate the anti scaling performance. However, the conventional coating evaluation method mainly judges the advantages and disadvantages of the coating technology through the conventional inspection indexes such as appearance size, roughness and smoothness There is no practical significance for the evaluation of the anti scaling performance of the special environment of ternary injection. Based on the field test, this paper forms a set of evaluation method for the scale prevention performance of ASP flooding, realizes the evaluation and optimization of the scale prevention performance of ASP flooding, and effectively prolongs the testing and adjusting period