Improve Displacement Efficiency Research Articles

Engineered CO2 injection: The use of surfactants for enhanced sweep efficiency

Poor CO2 displacement efficiency can exacerbate hydro-chemo-mechanically coupled phenomena in CO2 storage reservoirs, increase the area affected by CO2 in the reservoir, and negatively impact the long-term geological storage of CO2. The injection of CO2 can be engineered using surfactants to improve displacement efficiency. Pendant and sessile drop tests show that a surfonic copolymer decreases the interfacial tension γfl and increases the contact angle θ under reservoir conditions. The combined changes in surface tension and contact angle have a pronounced effect on the capillary factor γfl·cosθ. Injection tests using micro-models and pore network simulations show that a smaller capillary factor transforms the displacement pattern and enhances the pore-scale sweep efficiency of CO2, surpassing 40% in 2-D applications. Surfactant cost may offset the technical advantages identified in this study.

The distribution characteristics of additional extracted oil displaced by surfactant–polymer flooding and its genetic mechanisms

The pilot test of surfactant–polymer flooding (S–P flooding) in the western part of Gudong 7th reservoir has achieved good development effect. In this work, the distribution characteristics of additional extracted oil (AEO) displaced by S–P flooding were firstly studied using the reservoir numerical simulation method, to improve the understanding of the complicated mechanism during the S–P flooding process. Based on the performance of the components in S–P flooding system, AEO regions were distinguished into three sub-regions, including one enhancing displacement efficiency (S region), one improving sweep efficiency (P region), and one integrating the two mechanisms mentioned above (PS region). S region which had a dam-like distribution and low AEO saturation was located in layers with high permeability around the injection well. PS region that obtained higher AEO saturation was located close to the S region. P region which achieved the highest AEO saturation was located in layers with low permeability furthest away from the injection well. It was vertically distributed in the upper parts of the fining upward sequence reservoir and took on the shape of ellipse between wells. Compared with water flooding, the flux increased in some parts of the reservoir during the S–P flooding process. In order to quantitatively characterize the flux difference between water flooding and S–P flooding in the same area of the reservoir, a new characterization parameter named increased flux percentage (IFP) was defined and then IFP region in the reservoir was established. There was a very good correlation between the AEO region and the IFP region, which revealed the formation mechanisms of the three AEO sub-regions. The formation of S region was mainly due to the low interfacial tension contribution of surfactant in improving displacement efficiency. The polymer in S–P flooding system can improve the injection profile and increase the viscosity of the S–P flooding system. These mechanisms were the main reasons for the formation of P region. The formation of PS region was due to the synergistic effect between surfactant and polymer in the S–P flooding system. This synergistic effect was considered as the key mechanism to achieving good performance in the S–P flooding pilot test. Some characterization parameters were defined, including area of the sub-region, degree of the circularity and position of the centroid. Some sensitivity studies were conducted to find out the influence of surfactant and polymer concentration on the distribution characteristics of AEO and IFP. The results showed that the increased extent of PS region area reduced and the cross flow phenomenon caused by low interfacial tension of surfactant became serious when surfactant concentration was higher than 0.45%. Within a certain range, the areas of three sub-regions all increased as the polymer concentration increased. However, when the polymer concentration increased from 2000 mg/L to 2500 mg/L, the effect of increasing IFP and improving sweep efficiency was significantly decreased. Moreover, the increased extent of PS region area also reduced. • Distribution characteristic of AEO displaced by S–P flooding was first studied. • Flux calculation method was established to reveal genetic mechanisms. • Three parameters were defined to characterize the sub-regions quantitatively. • The influence of chemicals concentrations on distribution of AEO was also studied.

Visual Confirmation of the Elasticity Dependence of Unstable Secondary Polymer Floods

The viscoelasticity of polymers is known to contribute significantly toward improved displacement efficiency in polymer flood operations. But the contribution of elasticity of viscoelastic polymers...

Research Progress of the Interfacial Tension in Supercritical CO2-water/oil System

Carbon dioxide (CO2) is considered as one of major greenhouse gases, which has a significant contribution to global warming and has attracted more and more attention in recent years. So it s necessary to develop more efficient technologies to reduce CO2 emission. Carbon dioxide capture and sequestration (CCS) is one promising option to reduce CO2. CO2 flooding technique can enhance the oil recovery and achieve the storage of CO2 simultaneously. Therefore it is an important technology to support common development in terms of energy and environment. Under the high pressure, the interfacial tension (IFT) can affect fluid flow during the process of CO2 flooding greatly. Accordingly, there is an important significance to research miscible slug process and improve displacement efficiency. Hence the study of the IFT on supercritical CO2-water/oil system is indispensable.In order to understand the characteristic of IFT in-depth, this paper summarizes the IFT of CO2-water/oil system from the aspect of measuring methods, influencing factors and theoretical models. Currently there are less experimental data of IFT under the high pressures because of measuring difficulties in supercritical CO2-water/oil system. As one of the most effective measurement methods, the pendant drop method is developed gradually. This paper introduces the fundamental principles of several methods including selected plane method (SP), drop shape analysis (DSA) and axisymmetric drop shape analysis (ADSA). The relationships between pressure, temperature, concentration of CO2, salinity and IFT are summarized. Generally speaking, the IFT increases with the increasing pressure and salinity, while decreases with the increasing molar fraction of CO2. The effect of temperature on IFT is controversial in different researches. At the same time, this paper also presents the theoretical models of IFT in supercritical CO2-water/oil system. The work shows clearly the basic principles and applicable scopes of the statistical thermodynamics theories including density gradient theory (DGT) and density function theory (DFT). Finally, the directions should be strengthened concerning the study of IFT as follows: In terms of experiment, it is necessary to find out a method to measure the practical density difference by tracing system; Besides, a more accurate equation of state (EOS) should be constructed to calculate IFT. Therefore the proper measurement method, accurate injection pressure and concentration of CO2, rigorous theory and reliable mathematical model can be considered as research directions in future works.

A New Hydrophobic Associating Polymer

The properties of a new hydrophobic associating polymer were evaluated in detail in this paper. The polymer enhances the effect of increasing viscosity for the assembling action of functional groups in molecular chain. Alkali and surfactant promote the association and result in the increasing of viscosity, so the concentration of polymer in ASP solution is less than that in solution without alkali and surfactant. The viscosity of polymer solution restored again when shear effect decreased or disappeared; the characteristic will make the polymer used in oilfield advantageously. The polymer has synergistic effect with surfactant, so the interfacial tension of oil and water was ultra-low in a wide range of chemical concentration; it is propitious to improve displacement efficiency. When the oil recovery is approximate, the amount of new hydrophobic associating polymer is 20% less than that of HPAM.

Analyses on the high recovery of Z37 reservoir in LFX13-1 Oilfield, Pearl River Mouth Basin

The pay zone of Z37 reservoir in LFX13-1 Oilfield of Pearl River Mouth Basin is negative sequence massive sandstone from mouth bar of delta front. The development performance was characterized as rigid water-flooding, high productivity, high recovery rate and flat water cut rising-up at middle-high water cut stage. The recovery factor of Z37 reservoir is estimated above 70%. The production performance was evaluated as a whole from water cut rise-up rate, oil recovery rate and periodical oil recovery factor. The main reasons for the high recovery factor of Z37 reservoir were demonstrated and concluded from geological features, bottom aquifer size, well-pattern completion procedure and well pattern, the advantage of negative sedimentary sequence, hidden remaining oil catching at high water-cut stage, high in-situ temperature field improving displacement efficiency and rock wettability, horizontal well developing bottom-water reservoir, high crude oil price and application of many advanced technologies. The success production experience of Z37 reservoir can provide reference for the production of similar type of reservoirs. ： 珠江口盆地LFX13-1油田Z37油藏储集层为三角洲前缘河口坝反韵律块状砂岩，油藏开采表现出明显刚性水驱特征，具有油井产能高、采油速度高、中高含水期含水上升平缓等特点，预测最终水驱采收率将超过70%。从含水上升率、采油速度和阶段采出程度等方面对Z37油藏的开发效果进行了总体评价。从油藏地质特征、水体能量大小、完善开发井网的过程及方式、反韵律沉积层序优势、特高含水后期隐蔽剩余油的挖潜、高地温场对驱油效率及岩石表面润湿性的改善、大规模采用水平井、高油价的有利因素及众多相关前沿技术的应用诸方面剖析了Z37油藏取得高采收率的主要原因。Z37油藏的成功开采经验可为同类型油藏的开发提供借鉴。图9表2参14

Systematic Study of Alkaline/Surfactant/Gas Injection for EOR

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124752, ’A Systematic Study of Alkaline/Surfactant/ Gas Injection as an EOR Technique,’ by Mayank Srivastava, SPE, Jieyuan Zhang, SPE, Quoc P. Nguyen, SPE, and Gary A. Pope, SPE, University of Texas at Austin, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed. Alkaline/surfactant/polymer (ASP) flooding is a popular enhanced-oil-recovery (EOR) method. However, foam can be an alternative to polymer for improving displacement efficiency. The use of foam as a mobility-control agent by coinjection or alternating injection of gas and chemical slugs is termed here an alkaline/surfactant/gas (ASG) process. Foam reduces the relative permeability of the injected chemical slug that forms a microemulsion at ultralow oil/water interfacial tension (IFT) and generates sufficient viscous pressure gradient to drive the foamed chemical slug. Introduction In the ASP process, polymer provides mobility control during ASP slug and polymer-drive injection. However, the use of polymer has disadvantages. High-molecular-weight polymers can plug rocks with very low permeability. Many of the commercially available EOR polymers can be unstable at high temperature. Some polymers can degrade mechanically from high shear stress through chokes or perforations at high flow rate. One potential alternative to polymer is foam, which can provide mobility control in chemical-EOR processes. Liquid saturation is reduced with increased gas saturation and trapped gas in the foam, resulting in lower liquid relative permeabilities. In foam, gas bubbles are trapped in thin films of fluid called lamellae. The surface tension on the individual lamella, as well as the drag force on it as it slides along the pore walls, causes it to resist movement out of the pore throats. This resistance to movement, when combined with relative permeability reduction of the displacing fluid, results in a favorable mobility ratio and improved displacement efficiency. In ASG flooding, as in conventional chemical flooding, the mechanism of residual-oil mobilization is IFT reduction. One of the main criteria for the success of the ASG process is the formation of stable foam with adequate mobility-reduction characteristics. The full-length paper details the results of experimental work studying the ASG process to evaluate its potential as a feasible EOR technique.

Laboratory and Economic Study on Saudi Oil Recovery by Alkaline Flooding

Oil displacements in Saudi sandstone and limestone cores were performed. Some runs were carried out in Berea sandstone cores at different temperatures from 22 to 60°C. Safaniya crude oil (obtained from Safaniya oil field operated by Saudi Aramco) was used in displacement tests. Economical application of the process was studied to evaluate oil/recovery. Safaniya crude was determined to be acidic. Alkaline concentration reduces brine interfacial tension with an optimum value at about 0.5 percent. Oil recovery was greater in limestone cores. Increasing temperature from 25 to 60° improved displacement efficiency. The economical feasibility study indicated that initial oil saturation in the reservoir, price of injected NaOH and oil price have an effect on the decision of applying the process of enhanced alkaline flooding.

Improved Sweep Efficiency By Selective Plugging of Highly Watered Out Zones By Alcohol Induced Precipitation

Abstract A new selective plugging process has been developed for improving volumetric sweep efficiency and thus, the enhancement of recovery from oil reservoirs. The new process is based on the theory of "salting out" in which a non-electrolyte is added to water to reduce the solubility of electrolytic substances. In this new process, following a concentrated brine preflush, one or more slugs of a water soluble alcohol (such as ethanol) are injected into a reservoir. The mixing of alcohol with brine will cause salt precipitation. Alcohol and concentrated brine prefer to flow through water flooded zones because of the high relative permeability to these fluids. The formation of solid precipitate can partially or completely block the high-permeability zones and divert subsequent fluid flow into lower permeability zones where oil saturations are greater. A larger volume of the reservoir is thus contacted by the injected fluid, improving the overall volumetric sweep efficiency and the oil recovery. In homogeneous sandpack flow tests, a permeability reduction of up to 70% is obtained. In heterogeneous sandpack flow tests, the permeability is reduced to 50% of original brine permeability. The experimental results show that the new selective plugging process can recover an additional 15% of original oil in place (OOIP). There are advantages to this new method over other selective permeability reduction techniques. The process can be applied to deep and shallow oil reservoirs. In addition, the plugging of more permeable zones is easy to remove by injecting brine with low salt concentration, if required. Introduction A large portion (as much as 65% average) of the original oil in place in oil reservoirs is not recoverable with conventional waterflooding technology(1). This low oil recovery is due to both low displacement efficiency and low volumetric sweep efficiency. The oil industry has been seeking enhanced oil recovery methods to improve displacement efficiency and volumetric sweep efficiency. In oil reservoirs, almost all formations are heterogeneous. Some regions have low permeability while others have high permeability. All injected fluids have the tendency to flow through the least resistant regions (having the highest permeability) bypassing the lower permeability zones. In a waterflooded reservoir, after a substantial amount of oil is recovered from high permeability areas, the recovery process may become uneconomical because the water-oil ratio is high. Therefore, if a selective permeability plugging method could be developed to block off highly water-invaded regions any subsequently injected fluids would have to pass through regions not previously invaded by water. As a result selective permeability plugging would improve volumetric sweep efficiency and increase ultimate oil recovery. Interest in plugging highly water-invaded zones in oil reservoirs for improved sweep efficiency, has increased over the past several decades. Numerous methods have been studied to plug highly water-invaded regions including foams, polymers, surfactants, and microbes(2–8). However, each of these methods has limited application because of some inherent problems. For example, polymers are degraded by shear forces as they are propagated through reservoir rock. In surfactant processes, adsorption of surfactants on minerals is a major cause of surfactant degradation and uneconomic performance.

An Experimental Study of Non-Newtonian Polymer Rheology Effects on Oil Recovery and Injectivity

Summary Pseudoplastic non-Newtonian polymer solutions were examined for their enhanced oil recovery performance. Detailed results are reported for xanthan gum (XAN), Kelzan XCD™, and a viscoelastic polyethylene oxide (PEO), Polyox OF-50™. Increases in the power-law coefficient resulted in improved displacement efficiency. Effects were also observed in the injectivity-index parameter results.

Enhanced Alkaline Flooding

Micellar/polymer technology tops the list of the many EOR projects labeledtechnical successes but economic failures. Although this process can becustom-designed for a specific rock/oil/water system. the cost of thesurfactant used is prohibitive. which was true even when oil prices exceeded$30/bbl [$189/m3]. One very promising modification of micellar/polymer technology is thesubstitution of cost-efficient materials, such as alkaline agents, for themajority of the surfactant. With alkaline agents, such as sodium carbonate, sodium hydroxide, andvarious silicates, surfactant concentrations as low as 0.1 wt% can be used. This concentration is less than 5 % of the concentration used in the micellarsolutions of the micellar/polymer technology. Another cost-saving modificationis the replacement of costly cosurfactants used for viscosity control in amicellar solution with water-soluble polymers. Also, the alkaline agent reactswith the rock, thus reducing the chemical adsorption of the surfactant andpolymer and allowing the chemical system to displace oil effectively. Although the alkaline flooding literature has identified numerous mechanismsfor oil displacement. the principal mechanism by which alkaline flooding worksis through reducing the oil/water interfacial tension (IFT). The chemicalreaction between the injected alkali and the in-place crude oil forms asurfactant that reduces the IFT. The level of IFT reduction is dependent on thetype and concentration of alkali and on the chemical makeup of the crudeoil. There is an optimum alkali concentration that must be identified to designthe system properly. As with classic micellar flooding, properly. As withclassic micellar flooding, the salinity of the system dramatically affects theIFT response. If the salinity is too low, surfactant concentrates in theaqueous phase; if it is too high, surfactant is driven primarily into the oilphase. The ideal situation is to have the surfactant concentrated at the oil/water interface, which may occur only over a very narrow range ofsalinities. In alkaline flooding, the added alkali is not only a surfactant precursor, but also, by nature, a salt. Therefore, as the alkali concentration isincreased, the salt level increases beyond optimum and the IFT increases. Amajor problem with some of the early flood designs was that the alkaliconcentration yielding the minimum IFT in the laboratory was translateddirectly to the field. In some cases this "optimum" alkaliconcentration was very low-often less than 0.1 wt%. Laboratory and fieldstudies have shown that alkali concentrations this low cannot survive very farfrom the injection wellbore. Alkali consumption caused by the many reservoirsystem interactions generally requires that alkali concentrations be higherthan those indicated by the laboratory IFT tests. To accommodate these higher alkali levels without sacrificing the low IFTvalues, a low concentration of surfactant can be added to the system to shiftthe optimal salinity window effectively to a higher level. Laboratory workdemonstrated that this combination of alkali and surfactant can be synergistic, even in cases where initial crude-oil/alkali testing is not encouraging. Table 1 illustrates the synergistic effect of the combinedalkaline/surfactant mixture for a 26 degrees API [0.9-g/cm3] -gravitycrude. Although the IFT between the solutions and the oil is very important in thedesign of an "enhanced alkaline system," it is also necessary that thislow IFT be maintained between the fluids moving through the reservoir rock orthe chemical system will be ineffective in displacing sufficient oil forprofitable operations. The chemical makeup profitable operations. The chemicalmakeup of the rock, including clays, and the fluids will determine whether aparticular reservoir is a viable prospect. Another important consideration in the design of an enhanced alkaline systemis mobbility control. If the oil mobilized by reducing the IFT, is displaced bywater alone, the water will probably bypass the oil and leave the mobilized oilin the reservoir. For this reason, it may be necessary to add polymer toimprove displacement efficiency. polymer to improve displacement efficiency. The design of the total chemical system should include displacement studies todetermine which chemical combinations offer the greatest economicpotential.

Study of the Effects of Various Waters on Reservoir Rocks During Waterflooding, Using Scanning Electron Microscope

Abstract Injection of plain or modified water is one of the methods used to enhance the recovery of oil. A prior knowledge of the effects of injection fluids on the reservoir rock minerals and interstitial fluids is essential for designing a proper enhanced recovery program. A Scanning Electron Microscope (SEM) can be used to evaluate qualitatively the physicochemical changes that are taking place during waterflooding. Studies have been carried out by the writers on cores from an oil field situated in Gujarat State, India. This sandstone reservoir has medium-viscosity crude oil, with favorable acid number, low concentration of Ca⊃++ ⊃ and Mg⊃++ ⊃ cations in formation water, small quantity of water-sensitive clays, and relatively poorly cemented fines. Plain water (economy considerations), polymer solutions (for mobility control), and dilute caustic solutions (for improving displacement efficiency and for mobility control) were used as injection fluids in a large number of laboratory experiments in order to select the optimum parameters, such as concentration and slug size. The results were studied by examining micrographs of rock samples flooded for different time intervals, at low and high magnifications. Movement of fines during waterflooding, emulsification of oil on using caustic soda, and sticking of polymer and fines (partially removable)during polymer flooding has been observed. The SEM technique has helped in visualizing the actual phenomena taking place inside the reservoir cores during various stages of flooding, and supplements the results of flow studies for selecting and designing an enhanced recovery program.

Micellar/Polymer Flooding An Overview

This paper presents an overview of the continuing development of low-tension surfactant and micellar (or microemulsion) flooding. Current technology is considered from the standpoint of DOE and other projects undertaken in industry. Commercial application and projects undertaken in industry. Commercial application and economics also are considered. Introduction Surfactant flooding is one enhanced oil recovery (EOR) method being developed to increase the U.S. energy supply. Other methods include thermal techniques, CO, flooding, polymer flooding, and the use of caustic solutions. Micellar systems are injected to improve displacement efficiency in the reservoir. These solutions have been shown to reduce residual oil saturations in the laboratory and field far below those values obtained with a waterflood. Polymer solutions are injected next to propagate the expensive micellar system efficiently propagate the expensive micellar system efficiently through the reservoir. The polymer solutions improve the over-all reservoir conformance by providing mobility control. Finally, water is injected after the polymer solution.Surfactant use to improve oil recovery began in the late 1920's and early 1930's. Essentially, two different concepts have developed for using surfactants. One concept uses a large pore volume of a low-concentration surfactant solution. The use of low-concentration surfactant solutions has led to low-tension waterflood processes. The second concept uses a small pore volume of a processes. The second concept uses a small pore volume of a high-concentration surfactant dispersion. Dispersions containing high-surfactant concentration sometimes are called micellar solutions. Certain subclasses are referred to as microemulsions, swollen micelles, fine emulsions, or soluble oils. The use of small pore volumes of highly concentrated surfactant dispersions has led to a miscible-type recovery process known as Maraflood, TM a soluble oil recovery process known as Uniflood, TM and other patented processes. patented processes. This paper presents an overview of the continuing development of low-tension surfactant flooding and micellar, or microemulsion, flooding. Current technology is considered from the standpoint of DOE and other projects undertaken in industry. Some recent projects projects undertaken in industry. Some recent projects have shown an expanding technology. Based on the number of new tests, field activity is continuing at a high level. This paper also discusses commercial application in terms of lead time and expenditures. The potential for commercial application is considered in view of the Lewin and Assocs., Inc., National Petroleum Council (NPC), and Office of Technology Assessment (OTA) reports. Improvements needed for further technological development are presented. Timing for large-scale applications is reviewed in terms of supply and demand and competition from other liquid hydrocarbon fuels. Specific economic cases based on Marathon Oil Co.'s experience in Illinois are compared using 1975 and 1978 costs. High-Surfactant vs Low-Surfactant Projects Three sources were assumed to represent the current status of surfactant or micellar methods. Table 1 shows micellar/polymer field projects funded, either in part or entirely, by DOE. Other projects listed in the NPC report that began after 1973 are shown in Table 2. These tests are funded entirely by industry. Projects given in Tables 1 and 2 do not represent a complete list. JPT P. 1089

Polymer Flooding Technology Yesterday, Today, and Tomorrow

Polymer flooding, an augmented waterflooding method, has been evaluated Polymer flooding, an augmented waterflooding method, has been evaluated comprehensively in the laboratory and extensively field tested. This paper reviews past industrial experience, appraises current technology, paper reviews past industrial experience, appraises current technology, defines screening guidelines for field use, and discusses the future of the process. Introduction The petroleum industry recognized the problem of inefficient oil recovery by conventional (primary and secondary) recovery methods in the early 1900's. Since then, extensive research has been conducted on improvement of displacement and sweep efficiency in petroleum recovery. Many different processes have been designed to improve displacement efficiency by reducing residual oil saturation. However, polymer flooding was designed to improve sweep efficiency by improving the mobility ratio. Muskat first pointed out that fluid mobilities would affect waterflood performance. In 1949-50, Stiles used permeability and capacity distribution in waterflood permeability and capacity distribution in waterflood calculations and Dykstra and Parsons showed the effect of permeability variation and mobility ratio on recovery. permeability variation and mobility ratio on recovery. Aronofsky and Ramey discussed the mobility ratio and its influence on flood patterns during water encroachment in 1952 and on injection and production histories in a five-spot waterflood in 1956. In 1954, Dyes et al. presented studies of the influence of mobility ratio on oil presented studies of the influence of mobility ratio on oil production after breakthrough. Later, Caudle and Witt production after breakthrough. Later, Caudle and Witt (1959) and Barnes (1962) suggested improving waterflood sweep efficiency by increasing water viscosity. However, it was not until 1964 that Pye and Sandiford established that the mobility of water (or brine) used in waterflooding can be reduced efficiently by adding small amounts of a water soluble polymer. Since then, significant laboratory studies have appeared sustaining and extending this information. Recently, several additional important properties the inaccessible pore volume, shear degradation in porous media, and polymer retention have been observed. In addition to the laboratory findings, field test results also have appeared in the literature. Detailed summaries of these field reports were given by Jewett and Schurtz, Sloat, Agnew, and Herbeck et al. This paper reviews the process development, discusses current status, and assesses the future potential of polymer-flooding technology. polymer-flooding technology. Process Description Process Description Polymer flooding is an enhanced oil-recovery process Polymer flooding is an enhanced oil-recovery process that uses polymeric additives at concentrations of 250 to 1,500 ppm in the flood water. The polymer solution improves the water-oil mobility ratio; this results in the reservoir being swept more completely than if flooded with water not containing additives to reduce mobility. Currently, two types of polymers are used (1) a synthetic polymer classified as a polyacrylamide (partially polymer classified as a polyacrylamide (partially hydrolyzed), and a biologically produced polymer known as xanthan gum. In addition to increasing viscosity, polyacrylamides alter the permeability of the reservoir rock; this also lowers the effective mobility of the injected water. When the permeability of reservoir rock is reduced, a lower polymer concentration can be used to gain equivalent polymer concentration can be used to gain equivalent mobility control.

Steam Distillation Drive-Brea Field, California

This process has been field tested in a steeply dipping reservoir containing 24 degrees API oil at a depth of 4,600 feet. The very stable steam drive showed little tendency for early heat breakthrough to downdip wells. Residual oil saturations of 8 percent were achieved and the produced oil gravity was increased by light components distilled from the produced oil gravity was increased by light components distilled from the oil remaining in the steam zone. Introduction Most thermal recovery methods have been applied in high-viscosity reservoirs with the objective of increasing, oil production by reducing oil viscosity. The primary objective of a steam distillation drive is not to reduce oil viscosity but to reduce the residual oil saturation below that obtainable by ordinary waterflooding. In addition to its improved displacement efficiency, steam drive yields high sweep efficiency when steam is injected updip in steeply dipping sands. The objective of the Brea steam drive was to test the feasibility of driving a relatively light (24 degrees API), low-viscosity (6 cp), volatile oil from updip injectors to down structure producers. Process Process In reservoirs containing volatile oils, very low residual oil can be obtained by a combination of steam displacement and steam distillation. In a steam distillation process (see Fig. 1), hydrocarbons are more readily vaporized because of a lowering of their partial pressures in the presence of steam vapor. partial pressures in the presence of steam vapor. The light components are distilled from the residual oil and transported to the steam front where they recondense and mix with the oil bank to form a solvent slug. As the steam zone advances, this solvent slug. is displaced and redistilled to further increase oil recovery. Residual oil saturations below those obtainable by steam driving nondistillable oils are possible. Other mechanisms attendant with this process possible. Other mechanisms attendant with this process that account for the recovery of additional oil beyond what is possible with waterflooding are: reduction in oil viscosity, which improves oil mobility; thermal expansion of the oil; and gas drive from the steam vapor phase. In addition to in capacity to reduce oil saturation, steam driving is a relatively stable displacement process in light oil reservoirs (i.e., little oil is process in light oil reservoirs (i.e., little oil is by-passed). This stability is enhanced by both fluid convection and thermal conduction effects. The first stabilizing influence is the higher volumetric vapor flow rates in the steam zone compared with the liquid flow rates ahead of the steam front. Application of Darcy's law to both sides of the condensation zone in a situation where the pressures are generally less than 1,000 psi and the oil has a low viscosity shows that the pressure gradient is higher on the steam side than on the liquid side. Except for irregularities in permeability, steam fingers have little tendency to permeability, steam fingers have little tendency to form. The second stabilizing effect, thermal conduction, tends to collapse irregularities at the front of the steam zone because of heat losses normal to the direction of fluid flow. Laboratory Experiments The mechanisms involved in the steam distillation process were studied in unconsolidated tubular process were studied in unconsolidated tubular sandpacks. The apparatus used in the high-pressure (2,000 psi) experiments is illustrated in Fig. 2. JPT P. 899