An Analytical Model for Brine-Induced Oil Recovery

An analytical model for field application of improved waterflooding through brine concentration is presented. Based on several laboratory studies, many researchers suggested that changing the brine concentration during waterflooding offered viable options for improved oil recovery. In this regard, particularly in cyclic waterflooding, these studies have confirmed the effectiveness of such an approach. Generally, however, they are limited to laboratory studies without much field application. Most laboratory results do not present a clearly defined approach for practical application. This article analyses laboratory results and proffers a concise approach for field application. To this end, based on the reinterpretation of the Civan and Knapp model, an oil recovery model is developed for cyclic waterflooding. This model monitors waterflood performance based on the impact of brine injection for increased oil recovery.     

Development of a Statistical Predictive Model for Solvent-Aided Waterflooding

Abstract

Various studies have shown that miscible displacement by alternating the injection of hydrocarbon solvent and water recovers more residual oil than either solvent injection or waterflooding alone. However, economic considerations have limited the amount of solvent that could be injected during the miscible displacement process and has constrained its application for maximum oil recovery. Statistical modeling techniques were used to analyze various field and laboratory studies in which miscible displacement by hydrocarbon solvent and injected water were implemented. This provided an avenue to describe the performance of solvent-aided-waterflooding displacement and effect of various parameters on this process. The amount of hydrocarbon solvent, ratio of injected water to solvent and formation thickness were incorporated in the model to establish their relationship with incremental oil recovery. Multiple regression analysis was used to develop the model and the result indicated that future performance of the solvent-aided-waterflooding displacement process could be predicted effectively.     

WETTABILITY ALTERATION AND IMPROVED CRUDE OIL RECOVERY WITH ACETONE

Abstract

Laboratory studies are presented in this work wherein oil recovery can be substantially increased by injecting a low volume fraction of acetone along with brine during waterflooding. 10% of acetone used in flooding water could displace 13.2% of the original oil in place from a sand pack as compared to only 3.0% by brine without acetone. This volume fraction of acetone lowered the contact angle from 90^° to 42^°. Salinity was observed to have only slight effect on displacement efficiency.     

An Experimental Investigation of Parameters Affecting Oil Recovery Efficiency Alteration during a Microbially Aided Water Flooding Process

Abstract

In order to evaluate the potential of microbial recovery in the Iranian Maroon oilfield, laboratory core flood tests were designed and conducted. The effect of biosurfactant production on the recovery of crude oil during waterflooding and the effect of bioproducts on wettability alteration of the cores was investigated. Three different kinds of microbes in two different kinds of growth media as nutrient media were studied. The results showed that the oil recovery was affected by adjustment time, source of carbon, type of microorganism, phosphorus and nitrogen quantity, and salt concentration. In addition, it was found that there are optimum values of adjustment time, phosphorus and nitrogen quantity, and salt concentration that maximize the oil recovery factor. The results of this work can be helpful for designing and developing successful microbial-enhanced oil recovery (MEOR) operations.     

A Microbial-enhanced Oil Recovery Trial in Huabei Oilfield in China

This study discusses microbial-enhanced oil recovery (MEOR) application in Unit Jian-12 in Huabei Oilfield, China. The pilot field was a heavy oil reservoir (50°C, 204 mP.s) with high temperature (75.6°C). Unit Jian-12 was undergoing a waterflooding pattern; however, ordinary waterflooding no longer recovered residual oil efficiently that the MEOR method was strongly recommended in the stripper wells in the unit. A series of laboratory studies was conducted prior to the pilot test. The selected microbial consortia exhibited a positive effect on enhanced oil recovery and potential for application. A two-cycle trial was conducted and the production performance of the unit was monitored. The characteristics of crude oil were modified by biodegradation and the fluidity was improved. The residual oil in the formation was stimulated by the metabolic activities and metabolites, which greatly enhanced the displacement efficiency. In addition, an injection profile improvement was also observed in one injector (J 12–14) after the trial, indicating that the MEOR method could improve the heterogeneity of the reservoir and enhance the sweep efficiency. The results in this study were of academic and theoretic significance to microbial-enhanced oil recovery applications in heavy oil reservoirs.     

The Characterization of Natural Surfactant and Polymer and Their Use in Enhanced Recovery of Oil

Abstract

Studies have been done to examine the applicability of natural surfactant and polymer for enhanced oil recovery. A detailed investigation has been made on interfacial and rheological properties of natural guar gum polymer and surfactant obtained from extracted soapnut shell. Based on the physicochemical properties of the surfactant and polymer solutions, optimum compositions were designed for flooding experiments. Three sets of experiments were performed to study enhanced oil recovery by injecting the same pore volume of polymer, surfactant–polymer, and alkaline–surfactant–polymer slug after brine flooding. Significantly higher additional recovery (~24% original oil in place) was obtained by alkaline–surfactant–polymer flooding compared to the other two methods over waterflooding (~50% original oil in place).     

特低渗油藏非稳态周期注水机理及应用

为了充分发挥储层裂缝与基质之间的渗吸作用,增大注水波及体积,提高水驱采收率,以延长X区块长6油藏为研究对象,利用室内静态渗吸实验分析逆向渗吸影响因素,并采用考虑渗吸作用的数值模拟技术对X区块周期注水进行参数优化。结果表明,X区块渗吸方式主要为逆向渗吸,且储层渗透率、孔隙度的增大可以提高渗吸驱油效率;随着含水饱和度的增加,渗吸驱油效率降低;界面张力与渗吸驱油效率在一定范围内呈反比关系;X区块注水生产时,优选非稳态的周期注水方式,其优化工作制度为注20 d停30 d、注采比1.0~1.2、注水量8~12 m3/d。通过矿场现场实施,区块产油量小幅增加,含水率明显降低,较连续性注水开发方式可提高采收率2.5~3.5百分点,为特低渗油藏非稳态周期注水开发提供了有效的理论基础及现场应用依据。     

Asphaltene aggregation onset during high-salinity waterflooding of reservoirs (a molecular dynamic study)

Abstract

The primary objective of this study is to establish an understanding of the role of high-salinity brine on the intensity of asphaltene aggregation onset during waterflooding of petroleum reservoirs. We already have shown that asphaltenes have a high tendency to form aggregates during waterflooding process when pure- and low salinity-water are injected into reservoirs. To fulfill the present objective, molecular dynamic simulations are performed on asphaltenic-oil/aqueous systems at 550 K-200?bar. The oil phase consists of asphaltenes (10?wt.%) and ortho-xylene, in which asphaltene molecules are completely soluble. Our simulations results reveal that the “salt-in effect” of high-salinity brine (25 wt.% NaCl) on seven different model asphaltenic oils causes a significant reduction of the onset of asphaltene aggregation as compared with pure-water. Such “salt-in effect” is primarily due to a considerable reduction of water miscibility in the oil phase at high pressure and temperature.     

Effect of brine composition on recovery of Moutray crude oil by waterflooding

The effect of brine composition on oil recovery by waterflooding is under investigation. Wettability states of cores used in this study were achieved by aging with Moutray crude oil. Two brine compositions were tested, 4% NaCl + 0.5% CaCl₂ and 2% CaCl₂; they are referred to as Brine 1 and Brine 2, respectively. Tests in which the same brine was used throughout are referred to as standard waterfloods and standard imbibition tests. Those in which the brine composition is changed one or more times during the test are referred to as mixed-brine tests.In standard waterfloods, Brine 2 gave 5.5% higher waterflood recovery than Brine 1. Imbibition rate tests showed that Brine 2 gave less water-wet conditions than Brine 1. For mixed-brine waterfloods, Berea Sandstone gave waterflood recoveries of Moutray crude oil ranging from 59–72% of original oil-in-place (OOIP), according to the choice of initial and injected brine compositions and initial water saturation.Changes in brine composition can be favorable to recovery as compared to standard waterfloods. For Moutray/brine/Berea systems, waterflood recoveries were improved significantly if the core was initially equilibrated with Brine 2 and subsequently flooded first with Brine 1 and then with Brine 2. The effects of brine composition are highly specific to the crude oil and aging conditions. Standard waterfloods with Brine 1 and Brine 2 gave a difference of 15% OOIP for an Alaskan crude oil, but with Brine 1 giving the higher recovery and less water-wet conditions than Brine 2.     

Development of a Statistical Predictive Model for Solvent-Aided Waterflooding

Various studies have shown that miscible displacement by alternating the injection of hydrocarbon solvent and water recovers more residual oil than either solvent injection or waterflooding alone. However, economic considerations have limited the amount of solvent that could be injected during the miscible displacement process and has constrained its application for maximum oil recovery. Statistical modeling techniques were used to analyze various field and laboratory studies in which miscible displacement by hydrocarbon solvent and injected water were implemented. This provided an avenue to describe the performance of solvent-aided-waterflooding displacement and effect of various parameters on this process. The amount of hydrocarbon solvent, ratio of injected water to solvent and formation thickness were incorporated in the model to establish their relationship with incremental oil recovery. Multiple regression analysis was used to develop the model and the result indicated that future performance of the solvent-aided-waterflooding displacement process could be predicted effectively.     

Laboratory study of in-situ self-generating carbon dioxide huff-and-puff technology

Self-generating CO₂ huff-and-puff technology involves injection of reagents into formations that react with each other to generate carbon dioxide. We demonstrate the feasibility of applying this technology in the late stage of Jiangsu oilfield development by flooding. We have studied the factors affecting oil recovery by the self-generating CO₂ huff-and-puff (cyclic) approach and we have studied the mechanism for enhanced oil recovery. We show that the self-generating CO₂ huff-and-puff technology followed by waterflooding is more efficient than waterflooding followed by self-generating CO₂ huff-and-puff. Self-generating CO₂ huff-and-puff is more effective in low-permeability reservoirs.     

应用数值模拟技术研究周期注水

在层间、层内渗透率差异较大的情况下,利用周期注水来形成不稳定压力场,可以提高该类油藏的开发效果。应用油藏数值模拟技术,结合室内研究成果,对周期注水机理进行研究分析,结果表明,渗透率和毛管力是影响周期注水效果的主要因素,不同工作制度、合理周期注水、注水量变化幅度对其效果也有一定影响。在此基础上,对黄骅坳陷王官屯油田官80断块开展矿场试验,结果证实:在保持地层能量和注采平衡的基础上,多层均质油藏采用周期注水可以提高注入水的波及体积和最终采收率;应最大限度提高注水量变化幅度,当层间矛盾突出时,可实施分层系周期注水;在弥补水量和保持地层压力方面,不对称型周期注水工作制度优于对称型。图2表4参1(闻国峰摘)     

大庆长垣外围特低渗透扶余油层CO2驱油试验研究

大庆长垣外围特低渗透的扶余油层有3.7×10⁸t储量在常规注水开发条件下不能经济有效动用。以探索适合扶余油层地质特点的经济有效开采方式和提高单井产量、采收率为目标，采用室内实验和数值模拟的综合方法进行了CO₂驱油问题的研究。通过实验测定了扶余油层CO₂驱替的相关参数，对几种驱替方式进行了比较；根据相关参数，利用数值模拟方法，对扶余油层CO₂驱油矿场试验方案进行了优化，制定了矿场实验的注入方案。室内实验结果和矿场试验生产动态综合分析表明，CO₂非混相驱油适应于大庆长垣外围特低渗透扶余油层，但由于试验区油藏的非均质性导致气窜严重。因此，抑制气窜，提高波及效率是扶余油层改善CO₂驱替效果的关键。     

OPTIMUM STEAM INJECTION STRATEGIES FOR NATURALLY FRACTURED RESERVOIRS

ABSTRACT

This study aims to identify the effective parameters on matrix oil recovery and the efficiency of this process while there is a continuous flow of steam in fracture. Single matrix system is studied first. The critical injection rate is defined for laboratory scale simulation for different matrix properties. It is observed that there is a critical injection rate optimizing the process and the critical injection rate for an efficient matrix oil recovery is defined for different matrix sizes and matrix heat transfer coefficients.

In the second part of the study, similar analysis is performed to investigate the effect of injection rate on the oil recovery for field scale. Critical rate concept is evaluated for different number of horizontal fractures and steam qualities. Finally, the economics of steam injection in the field scale is studied. The optimum injection strategies determined by the adjustment of injection rates are discussed based on the fracture properties such as density and permeability. The approach and results can be used in further studies to analyze the efficiency of thermal applications and to obtain correlations for steam injection performances in naturally fractured reservoirs.     

WETTABILITY ALTERATION AND IMPROVED CRUDE OIL RECOVERY WITH ACETONE

Laboratory studies are presented in this work wherein oil recovery can be substantially increased by injecting a low volume fraction of acetone along with brine during waterflooding. 10% of acetone used in flooding water could displace 13.2% of the original oil in place from a sand pack as compared to only 3.0% by brine without acetone. This volume fraction of acetone lowered the contact angle from 90^° to 42^°. Salinity was observed to have only slight effect on displacement efficiency.     

EFFECT OF BRINE COMPOSITION ON OIL RECOVERY BY WATERFLOODING

In this study, the effect of brine composition on oil recovery by waterflooding was experimentally studied. Different compositions of brine were injected in to packed one-dimensional unconsolidated limestone with Garzan crude oil (26° API) and distilled water. Ten different brine compositions, three brine mixtures are prepared and distilled water was used for injection throughout the study. The highest recovery 18.8% higher than distilled water injection) considering all the experiments was obtained by the injection of 2% KCl + 2% NaCl brine mixture.     

EFFECT OF BRINE COMPOSITION ON OIL RECOVERY BY WATERFLOODING

In this study, the effect of brine composition on oil recovery by waterflooding was experimentally studied. Different compositions of brine were injected in to packed one-dimensional unconsolidated limestone with Garzan crude oil (26° API) and distilled water. Ten different brine compositions, three brine mixtures are prepared and distilled water was used for injection throughout the study. The highest recovery 18.8% higher than distilled water injection) considering all the experiments was obtained by the injection of 2% KCl + 2% NaCl brine mixture.     

Scaled 3-D model studies of immiscible CO2 flooding using horizontal wells

In this study, a comprehensive laboratory investigation was conducted for the recovery of heavy oil from a scaled three-dimensional (3-D) physical model, packed with 18° API gravity crude oil, brine and crushed limestone. A total of 20 experiments were conducted using the scaled 3-D physical model with 30×30×6 cm³ dimensions. Basically, four different immiscible CO₂–water displacement processes were used for recovering heavy oil: (i) continuous CO₂ injection, (ii) waterflooding, (iii) simultaneous injection of CO₂ and water, and (iv) water alternating gas (WAG) process. Three groups of well configurations were mainly used: (1) vertical injection and vertical production wells, (2) vertical injection and horizontal production wells, and (3) horizontal injection and horizontal production wells. Base experiments were run with water only and carbon dioxide alone and optimum rates for WAG and simultaneous water–CO₂ injection were determined. In continuous CO₂ injection, highest recovery was obtained by vertical injection–horizontal production (VI–HP), followed by vertical injection–vertical production (VI–VP) and the least by horizontal injection–horizontal production (HI–HP). In VI–HP configuration, the best recovery was obtained as 15.1% OOIP. Higher oil recovery was obtained with a VI–HP wells than with a pair of vertical wells and horizontal wells. The WAG 1:5 ratio yielded a final recovery of 34.5% OOIP with VI–VP well configuration and 17.0% OOIP of additional recovery over waterflooding. In turn, the WAG 1:10 ratio was the best with a final recovery of 20.9% of OOIP with VI–HP well configuration. Oil production from WAG injection is higher than that obtained from the injection of continuous CO₂ or waterflooding alone.     

污水配制延缓交联聚合物体系实验研究

国内外油田已普遍把聚合物用于三次采油，但大多使用淡水体系。该文介绍了延缓交联聚合物驱油机理，对污水配制延缓交联聚合物体系进行了可行性实验研究，确定了体系的组份。实验表明聚合物的选取应遵循中等分子量、中低水解度的原则。并研究了体系各组分浓度、流变性、地层中化学剂及温度、水质矿化度等因素对体系粘度的影响。通过岩心驱油模拟实验发现，污水配制延缓交联聚合物体系驱油，可提高原油采收率５．５％，进一步拓宽了聚合物驱油技术的应用领域。