Core Displacement Tests Research Articles

Cross-linked polyacrylamide gel as loss circulation materials for combating lost circulation in high temperature well drilling operation

Cross-linked polymer gel has been broadly used to plug severe lost circulation and to improve the strength of the near-wellbore in natural fracture or carbonate cave strata. Gelation time and gel strength are the key factors for gel plugging. In this study, a cross-linked polymer gel with controlled gelation time and high gel strength was fabricated at high temperature, named HTCMG. It was prepared from an acrylamide monomer, crosslinking agent and initiator by free radical polymerization. To extend gelation time at high temperature, colophony was used here to encapsulate the initiator. This complex was characterized under the Fourier transform infrared spectroscopy (FT-IR), by thermogravimetric analysis (TGA) and under the scanning electronic microscopy (SEM). The effects of pH, temperature, monomer concentration and salt concentration on gelation time were assessed. To examine the viscoelastic property and tensile strength of HTCM, HAKKE Mars 40 and uniaxial compression apparatus were employed, respectively. The plugging property of HTCMG was tested by the core displacement test and high-temperature and high-pressure (HTHP) fracture plugging test. According to the results, HTCMG can form gel in temperature range of 80–150 °C, and the gelation time can be practically adjustable. The results of the core displacement test revealed that the bearing capacity of HTCMG can reach a peak of 9.8 MPa at 150 °C, and it can effectively plug 3 mm-width slot. HTCMG is characterized by a lower plugging time, a higher successful plugging ratio and lower economic cost than normal loss circulation materials, suggesting that HTCM is useful for addressing the lost circulation of high-temperature well, and it is of huge significance to engineering application.

Investigation into the migration of polymer microspheres (PMs) in porous media: Implications for profile control and oil displacement

To reduce the unwanted water and further enhance oil recovery, a profile control agent, named polymer microspheres (PMs), was synthesized by inverse emulsion polymerization and its physical properties including morphology, particle size distribution, dispersibility strength and hydration swelling property were thoroughly examined. The main goal of this paper was to investigate the migration behaviors of the PMs in porous media using visual micromodel, nuclear magnetic resonance (NMR) and core displacement tests. The visual images indicated the PMs could plug the high permeability area and divert the subsequently injected fluid to lower permeability area. Moreover, the PMs could re-migrate in the high permeability area and displace residual oil due to elastic deformation. The NMR results revealed that the PMs with low expansion rate and high elasticity generated higher swept volume and displacement efficiency, thus leading to higher oil recovery, compared to those having high expansion rate and low elasticity. It can be observed from oil-water relative permeability curves that compared with water flooding (WF), the oil-water isotonic point was shifted into higher water saturation and disproportionate permeability reduction (DPR) occurred during PMs flooding (PMF). Finally, the profile control and displacement mechanisms of PMs were proposed based on the experimental observations.

Carbonated water injection under reservoir conditions; in-situ WAG-type EOR

Enriching injection water with CO2 has demonstrated promising results as a method for improving the oil recovery and securely storing CO2 in oil reservoirs. However, mutual interactions taking place between carbonated water and reservoir oil at elevated reservoir conditions are not fully understood. Herein, we present the results of a thorough and direct investigation of the interactions between live-oil/CO2/aqueous-phase leading to additional oil recovery and enhanced CO2 storage in pore-scale and core-scale.CO2 transfer from carbonated water to live oils can trigger liberation of light components in form of a new gaseous phase. This unique phenomenon would bring about higher degrees of oil swelling, and it can also create a three phase flow regime, which leads to effective reduction of residual oil saturation. The observations confirm that the performance of carbonated water injection (CWI) should be investigated under reservoir conditions using multi-components live oil and reservoir cores. From the core displacement tests, it was observed that secondary CWI could recover a significant amount of additional oil, which was 26% compared to conventional seawater injection. When CO2 content of injected CW (carbonated water) was halved, the oil recovery dropped by 1/3 Using live oils, it was found out that CO2 would be trapped in the new phase, which brings about an enhanced CO2 trapping mechanism. Under realistic reservoir conditions where complex mass transfer of CO2 from aqueous phase to oil and gas phases takes place, an “in-situ WAG-type” three-phase flow is generated with more effective sweep efficiency and pore-scale advantages.

Gelation mechanism and rheological properties of polyacrylamide crosslinking with polyethyleneimine and its plugging performance in air‐foam displacement

ABSTRACTGels based on polyacrylamide crosslinking with polyethyleneimine have attracted attention because of their resulting high strength and good thermal stability. This study investigated the gelation mechanism of the polymeric gel and its plugging performance in air‐foam flooding. An optic microrheology analyzer was used to monitor the gelation process. The crosslinking reaction occurred in two steps, as determined from the elasticity factor curves, and the polymeric gels adopted a semisolid state from solution, as determined from the solid liquid balance curves. The elastic modulus values were higher than the viscous modulus values, indicating that mature gels were elastic‐based materials. The yield stress increased gradually with increasing polymer dosage, which was consistent with the breakthrough pressure and the trend of displacement pressure. The mature gels showed significant thixotropy. In the core displacement test, the preferred injection volume of the gel was 0.1 pore volume, and the stable pressure of the foam flooding was increased by about three times after the core was plugged. The blocking effect for cores with small original permeability was better than that with large permeability. The best blocking resulted from simultaneous treatment of both ends of the cores, followed by front‐end treatment and rear‐end treatment. © 2017 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018, 135, 45778.

Enhanced Oil Recovery of Low-Permeability Cores by SiO2 Nanofluid

This study investigated the mechanisms and performance of SiO2 nanofluid for enhanced oil recovery (EOR) in low-permeability cores. Three-phase contact angles for quartz/oil/brine systems were measured, and the microscopic imbibition characteristics of nanofluids in a capillary were observed through visualization experiments. In addition, the effects of the adsorption of the nanoparticles on the oil–water relative permeability was studied using core displacement tests. Furthermore, a total of 11 core flooding tests were performed, and the effects of injection parameters, such as nanoparticle concentration, injection rate, and injection scheme, on the oil recovery were investigated. Wettability alterations were observed among quartz/oil/brine systems that contributed to higher displacement efficiencies in microscopic imbibition tests. Relative permeability measurements showed that, upon the adsorption of the nanoparticles, the irreducible water saturation and oil-phase relative permeability increased where...

Experimental assessment of a lysine derivative surfactant for enhanced oil recovery in carbonate rocks: Mechanistic and core displacement analysis

Abstract Enhanced oil recovery (EOR) from carbonate reservoirs is of great challenge due to the complex geology that originated from high rock heterogeneity and viscous fingering phenomenon during a displacement process. One of the highly applicable EOR approaches is the utilization of surfactant especially for the aims of foam generation, wettability alteration, emulsion stability and well stimulation in petroleum industry. The dominant mechanisms of surfactant for increasing oil production are wettability alteration of reservoir rock and interfacial tension (IFT) reduction of oil-water system resulting in higher sweep efficiency by diminishing the adverse capillary forces existing in the porous media and easier flow of the residual oil toward the producing wells. In the present study, (S) 2-amino-6-dodecanamidohexanoic acid as an amino acid-based surfactant, is proposed in order to evaluate an EOR application. Firstly, the pH, density and viscosity of the surfactant solutions were measured regarding the impact of salt concentration. Afterwards, IFT and wettability tests were conducted by means of pendent drop and sessile drop methods, respectively. The impact of salt concentration was also examined on the IFT behavior. Moreover, the recovery potential of the proposed amino acid-based surfactant via core displacement test was compared with a traditional brine injection process. Consequently, it is found out that increasing salt concentration has an increasing effect on both IFT trend and the values of critical micelle concentration. Additionally, change in carbonate rock wettability from oil-wet to neutral-wet was also observed. Finally, it is proved that surfactant flooding can improve the oil recovery factor more than the time at which water injection is used.

Multifunctional Evaluation of a New Supramolecular Complex in Enhanced Oil Recovery, Removal/Control of Organic Damage, and Heavy Crude Oil Viscosity Reduction

The development of new technologies based in the design and application of new molecules to solve problems related to the removal and control of formation damage by organic deposition and viscosity reduction of heavy crude oils as well as to increase the oil recovery factor is an important challenge in the oil industry. This experimental study reports the influence of a novel supramolecular complex on the removal/control of organic deposition and enhanced oil recovery processes through core displacement tests at reservoir pressure and temperature conditions. In addition, its capabilities as viscosity reducers for heavy crude oils are also reported. Three different Mexican brine/rock/crude oil systems were used to evaluate the multifunctional properties of the novel supramolecular complex. Results showed a good performance of the capabilities of the supramolecular complex tested to reduce the viscosity, to remediate organic damage, and to enhance the oil recovery factor. In order to explain the results obt...

Wettability Alteration of Reservoir Rocks from Liquid Wetting to Gas Wetting Using Nanofluid

Well productivity in gas condensate reservoirs is reduced by condensate banking when the bottom hole flowing pressure drops below the dew point pressure. Among the several methods which have been proposed for condensate removal, wettability alteration of reservoir rock to intermediate gas wetting in the near wellbore region appears to be one of the most promising techniques. In this work, we report use of a nanofluid to change the wettability of the carbonate and sandstone rocks to intermediate gas wetting. Application of nanofluid in the wettability alteration of carbonate and sandstone rocks to gas wetting has not been reported previously and is still an ongoing subject. Static and dynamic contact angle measurements, along with imbibition tests, have been performed to investigate the wettability of carbonate and sandstone rocks in presence of nanofluid. It was found that the nanofluid used in this work can considerably change the wettability of both surfaces to preferentially gas wetting in just one day of ageing time. We also report the effect of initial oil saturation and ageing time on the nanofluid capability for wettability change. Initial oil saturation reduces the impact of the nanofluid on wettability change, and hence, a pre-treatment before using nanofluid is necessary. In addition to these small slab-scale experiments, applicability of nanofluid in wettability alteration of sandstone rocks to gas wetting is also investigated in core scale. The results of core displacement tests confirm the ability of nanofluid to change the rock wettability from liquid wetting to gas wetting in core samples. They also show the effectiveness of chemical treatment in subsurface conditions.

Characteristics of ethoxylated fatty amine emulsion: Effects on the wettability and permeability of silicate formation under various pH conditions

Abstract The effects of ethoxylated fatty amine emulsion on the wettability and permeability of silicate rock under various pH conditions, as well as the adsorption behavior of ethoxylated fatty amine on the silicate rock surface, were investigated using core displacement test, contact angle test and infrared spectroscopy. A new knowledge about the characteristic and mechanism of formation damage from reversible invert emulsion drilling fluids and a new method for the completion and cementing of a well drilled by reversible invert emulsion drilling fluids were proposed. Under pH of 4 to 8, exthoxylated fatty amine can adsorb on the rock surface to various degrees, resulting in the strong oil-wet condition of rock which does a serious harm to the permeability of the formation. Under pH of 10, no exthoxylated fatty amine adsorbs in the rock, resulting in the water-wet condition of the rock surface which is benefit to mitigating the damage of mud to the permeability of the formation. It is suggested removing the reversible invert emulsion drilling fluid using acidic fluids followed by basic fluids or using acidic fluids combined with wettability alteration agents.

Experimental investigation of heavy oil recovery by continuous/WAG injection of CO<SUB align="right">2 saturated with silica nanoparticles

In this work, application of CO2 saturated with silica nanoparticles in continuous/water alternating gas (WAG) injection for heavy oil recovery was investigated which has been rarely attended in the available literature. Core displacement tests were conducted to monitor heavy oil recovery in both continuous and WAG injection schemes. It has been observed that for continuous nano-saturated CO2 injection, the oil recovery is higher than pure CO2 injection. This observation might be explained by alteration of rock wettability to a more water-wet condition. In WAG injection scheme, water breakthrough happened later in nano-saturated CO2 than pure CO2 injection. This delayed water breakthrough can be caused by nano-stabilised oil in water emulsions. These oil emulsions hindered the oil recovery before breakthrough. However, recovery factor of WAG injection of nano-saturated CO2 exceeded that of pure CO2 as those stabilised oil emulsion were produced along with water after breakthrough. The results of this work reveal that saturation of CO2 with silica nanoparticles can improve the microscopic efficiency of continuous CO2 injection, while in CO2 WAG injection this hampers oil recovery before water breakthrough.

Wettability Alteration in Carbonate Rocks by Implementing New Derived Natural Surfactant: Enhanced Oil Recovery Applications

One of the robust and high-performance EOR methods which use chemical agents is chemical flooding. Environmental impacts, surfactant cost, and oil price are the three main parameters that affect on the robustness of the surfactant flooding in oil reservoirs. Interfacial tension reduction and wettability alteration of the reservoir rocks are the two main mechanisms of the oil recovery via employing surfactant flooding. The preliminary study about adsorption and environmental impacts of the new natural-based surfactant which derived from roots of Glycyrrhiza Glabra was investigated systematically by the authors and proved the ability of the aforementioned surfactant for EOR goals. Thanks to this point that throughout the current study, core displacement tests and qualitative and quantitative wettability experiments were carried out to specify performance of the above-mentioned natural surfactant in oil recovery. For wettability alteration measurements, contact angle measurement as a quantitative method, and floatation and two-phase separation experiments as qualitative methods were utilized. In addition, three commonly industrial surfactants were implemented throughout the wettability alteration experiments to contrast performance of the used surfactants. Thanks to the outcomes obtained from qualitative and quantitative wettability alteration experiments, and the surfactant suggested in this study could change wettability of carbonate rock from strongly oil-wet toward water-wet state. In addition, based on the core displacement experiments, it is robust, cheap, and high performance in comparison with other conventional industrial surfactants for surfactant flooding purposes. There is a hypothesis that the addressed raw surfactant can be utilized in chemical flooding of oil reservoirs owing to very low cost and availability around the world compared to other currently implemented surfactants.

Application of Electromagnetic Waves and Dielectric Nanoparticles in Enhanced Oil Recovery

Enhanced oil recovery (EOR) refers to the recovery of oil that is left behind in a reservoir after primary and secondary recovery methods, either due to exhaustion or no longer economical, through application of thermal, chemical or miscible gas processes. Most conventional methods are not applicable in recovering oil from reservoirs with high temperature and high pressure (HTHP) due to the degradation of the chemicals in the environment. As an alternative, electromagnetic (EM) energy has been used as a thermal method to reduce the viscosity of the oil in a reservoir which increased the production of the oil. Application of nanotechnology in EOR has also been investigated. In this study, a non-invasive method of injecting dielectric nanofluids into the oil reservoir simultaneously with electromagnetic irradiation, with the intention to create disturbance at oil-water interfaces and increase oil production was investigated. During the core displacement tests, it has been demonstrated that in the absence of EM irradiation, both ZnO and Al2O3 nanofluids recovered higher residual oil volumes in comparison with commercial surfactant sodium dodecyl sulfate (SDS). When subjected to EM irradiation, an even higher residual oil was recovered in comparison to the case when no irradiation is present. It was also demonstrated that a change in the viscosity of dielectric nanofluids when irradiated with EM wave will improve sweep efficiency and hence, gives a higher oil recovery.

Nonlinear percolation mechanisms in different storage-percolation modes in volcanic gas reservoirs

Abstract The non-linear seepage mechanisms in volcanic gas reservoirs were studied using experiment results of rate-controlled Hg penetration, nuclear magnetic resonance, and core displacement tests. According to types of storage space and throats, combined with dynamic production characteristics, the volcanic gas reservoirs were classified into four storage-seepage modes, pore type, inter-granular pore type, micro-pore type and fracture-dissolution pore type. Slippage effect and stress sensitivity influence the seepage characteristics of volcanic gas reservoirs. Slippage effect is obvious in micro-pore type reservoirs, medium in pore type reservoirs, and insignificant in inter-granular pore type reservoirs. Stress sensitivities vary greatly in different storage-seepage modes. Fracture-dissolution pore type reservoirs have the strongest stress sensitivity, pore type reservoirs come second, and inter-granular pore type reservoirs have the weaker. In combination of dynamic production data, a relay gas supply mechanism model of multi-media volcanic gas reservoirs was established. In the high and stable yield period, when differential pressure dominates, gas is supplied from large pores and large fractures, and the single well production is high. In the yield decline period, when compaction plays a leading role, gas is supplied from medium pores and small fractures. In the low and stable yield period, when imbibition and diffusion are the main driving force, gas is supplied from small pores and micro-fractures.

Interaction between Cationic Nano Microsphere and HPAM

This paper intends to deal with one novel profile control agent formed by combination of HPAM and cationic microspheres with different cationic density (CD) by the method of micro-emulsion polymerization. Profile control is of great importance in well stimulation for current oilfield with high water cut. The main profile control agents now are polymer or polymer microspheres. Each of these agents has its own performance advantages. The novel profile control agent is equipped with the advantages of both the agents mentioned above. Analyzed by transmission scan electron microscope (TSEM) and laser particle sizer, the particle size of the original synthesized microsphere and the swelled microsphere in water are 50-100nm and 1-3μm respectively. Analyzed by micro-electrophoresis, the surface potential arrives at its highest value at 30% of the cationic density; aggregation happens when CD is low and the electrostatic force is insufficient to keep the system stable. Due to electrostatic interaction, the synthesized system flocculates at a concentration of 0.02% separately. Measured at varied shear rates, the viscosity of the system can be significantly enhanced by electrostatic interaction. However, this enhancement is not obvious when the salinity is higher than 3%, which indicates that the increasing of viscosity is closely related to the salinity of solution. Moreover, by increasing hydrolysis degree of HPAM, the viscosity of the system can be improved by 20% additionally. Through core displacement test, the synthesized system is proved to have relatively good profile control performance.

Effect of polymer solution structure on displacement efficiency

In this paper, a series of experiments, including atomic force microscope (AFM), environmental scanning electron microscope (ESEM), and core displacement tests were conducted to investigate the effect of polymer solution structure on solution properties and oil displacement efficiency. The results show that in the HPAM solution polymer coils were formed and then aggregated into a loose structure, while the HAP2010 solution formed a strong network structure, which would significantly improve the solution viscosity and flow resistance so as to upgrade the capacity of piston-like oil displacement in highly permeable porous media. Meanwhile, the retention of the HAP2010 solution at pore throats were also enhanced, which could reduce water production during subsequent water flooding and enlarge the swept volume during polymer flooding. Therefore, enhancing the interaction among polymer molecules is an effective way to improve the displacement efficiency of polymer solutions in heavy oil reservoirs with high permeability.

Preparation of super-hydrophobic nano-silica aqueous dispersion and study of its application for water resistance reduction at low-permeability reservoir

The preparation of a super-hydrophobic nano-silica and its surface-modification by surfactant using the in situ modification has been discussed. As-prepared super-hydrophobic nano-silica can be well dispersed in water to form a transparent aqueous dispersion with primary particle size and narrow particle size distribution. Core displacement tests simulated at the laboratory show that the as-prepared aqueous dispersion of nano-silica is able to significantly improve water phase permeability and pressure difference. Also the super-hydrophobic nano-silica can be well adsorbed on porous core walls to transform the hydrophilicity into super-hydrophobicity with contact angle >150° by combining surface roughening with surface chemical modification, showing great potential for reducing flow resistance and enhancing water injection at low-permeability reservoirs.

Synthesis and behavior evaluation of a relative permeability modifier

Using N, N-dimethylaminoethyl methacrylate (DMAEMA) and methoxy polyethylene glycol methacrylate (MPEGMA) as raw materials, hydrophobically associating copolymer was synthesized by inverse emulsion polymerization and structurally confirmed by FTIR. Choosing partially hydrolyzed polymer of the copolymer as a relative permeability modifier, its intrinsic viscosity reaches 212.66mL/g at 25°C. Its adsorbability on the oil sandstone is investigated, that is to say, the equilibrium concentration is approximately 5100mg/L while the saturated adsorption is about 0.652mg/g. Temperature and salt also have a certain effect of RPM system based on the partially hydrolyzed polymer. Finally, the residual resistance factors to water and oil were measured by core displacement test. The results show that the flow resistance of the system to water is 19.9 times as large as that to oil. That is, the system has obvious selectivity to water and oil.

Effect of crude oil ageing on low salinity and low salinity surfactant flooding

Injection of brine with lower salinity than the connate brine has proven to give a moderate increase in oil recovery in sandstones. Recent research has shown that this process will significantly benefit from introducing surfactant optimised for low salinity environment. The mechanisms underlying increased recovery by low salinity brine injection are not yet fully understood. However, research to date suggests that they are related to complex crude oil/brine/rock interactions. With this in mind, the present paper investigates primarily how the extent of oil recovery from Berea sandstones subjected to long term exposure of crude oil is influenced by (1) low salinity water injection and (2) combined process low salinity water injection with surfactant flooding. Core displacement tests were conducted on four Berea cores (30 cm), two in a natural state and two that had been subject to extensive crude oil ageing at high temperature. Results obtained from different flooding steps are discussed in terms of oil recovery and effluent properties including turbidity, pH- and ion analysis (Na +, Mg 2+, Ca 2+). The results effectively illustrate that oil recoveries from the aged cores are higher during both low salinity water injection and low salinity water injection combined with surfactant flooding. An assessment of how tertiary oil recovery in aged and unaged cores varies with surfactant concentration is also presented. Effluent ion analysis from low salinity water floods showed that Mg 2+ ions were strongly retained in the aged core while Ca 2+ ions were being produced from both aged and unaged cores. The latter was attributed mainly to calcite dissolution. Results obtained from pressure profiles, effluent ion analysis and turbidity tests suggest higher production and elution of fine particles from the unaged core.

Gravity Drainage-Lab Tests, Relative Permeability Calculation, and Field Simulation

Abstract In order to confirm the expected high recoveries obtained in gravity drainage field operations we performed a series of lab tests, developed an oil relative permeability calculation, and used this data to conduct a reservoir simulation for a Brazilian offshore oil field. The lab tests were conducted at ambient temperature and low pressure, and were performed in long cores (90 - 252 cm long) with dead oil and conventional production where the oil was produced at the lower end of the vertically oriented core and air entered the upper end. For one test we performed a counter-current drainage test using live oil where the production was collected at the lower end of the core and the liberated dissolved gas was removed counter-currently from the upper end. The saturation evolution inside the core was monitored by an X-Ray system. Using the same rock and fluids, centrifuge tests were performed using 3 - 4 cm long plugs to compare to the core displacement test results. When the results did not agree, an explanation for the variance using a model of bundles of capillary tubes was postulated. Verification using the principle of minimum energy was performed. A computer program was implemented to calculate the oil relative permeability using the lab data, the results of which were compared with the published literature. The calculated relative permeability was used to simulate the behaviour of a Brazilian offshore oil field that was initially exploited with water injection, and then, due to the appearance of a secondary gas cap, subsequently subjected to gas injection into the crest of the structure. Introduction Numerous papers describe lab test results concerning gravity drainage(2–4, 7, 8, 10, 12, 14, 16, 19, 23, 24, 26, 27). We present the results of gravity drainage long core tests and centrifuge tests using samples with identical rock and fluid properties. In those situations where the results of the two methods did not agree, we calculated the results by considering a bundle of capillary tubes to understand the difference. The long core tests showed, in accordance with the literature, a very low residual oil saturation at the top of the core. The results of these tests were used to calculate the oil relative permeability to be used in to simulate the performance of an offshore Brazilian oil field with a 110.6 MMSTm3 OOIP has been under production for 13 years under peripheral water injection and, due to the appearance of a secondary gas cap, has been supplemented with a crestal gas injection. After a history match, we performed the production forecast for both water and combined water and gas injection. Methodology of the Experimental Tests Long Core Tests After the traditional core mounting process, the sequence of the tests can be summarized in the following steps:Measurement of rock and fluid properties;Water saturation of the sample under vacuum;Displacing the water by oil and establishing the initial water saturation; and,Drainage of oil in the presence of air.

Coreflood Studies of Tertiary CO2 Flood in Naturally Fractured Midale Formation in Southeast Saskatchewan

Abstract The distinctive geology of the Weyburn and Midale reservoirs has important implications for the design of a CO2 injection process for these fields. They are contained within two distinct zones of the Mississippian Carbonate formation; the tight, high-porosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically, than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. The Marly/Vuggy sequence presents an opportunity for a CO2 flood to take advantage of gravity segregation to recover the large remaining oil target in the Marly zone. A series of coreflood tests were conducted to simulate tertiary CO2 injection in the Marly/Vuggy zones in the Weyburn and Midale reservoirs. Berea cores with different permeabilities were split lengthwise. The halved segments of the core were butted together to represent the Marly and Vuggy zones. Water (in waterflood mode) and CO2 (in tertiary CO2 flood mode) were injected into the bottom high-permeability section of the dualpermeability core. The coreflood results showed that, in the tertiary CO2 flood, CO2 could migrate to and recover the oil from the top low-permeability zone which was poorly swept by the waterflood. Also, the effects on tertiary oil recovery of operating pressure, injection rate, and permeability contrast could be significant. Introduction The Weyburn and Midale reservoirs in southeast Saskatchewan hold light and medium gravity oil in fractured, low permeability Midale Beds. These reservoirs are contained within two distinct zones of the Mississippian Carbonate formation: the tight, highporosity Marly zone sits on top of the low-porosity Vuggy zone. The latter zone has a higher permeability, and is more extensively fractured vertically than the Marly zone. These geological features result in a relatively unswept Marly zone after waterflooding. It is believed that the distinctive geology of these reservoirs has important implications for the design of a CO2 injection process for these fields, i.e., the Marly-Vuggy arrangement of the reservoir offers potential to utilize gravity segregation effects to enhance oil recovery. Numerical analyses(1, 2) of tertiary CO2 injection in these naturally fractured reservoirs showed that CO2 injected into the lower, more permeable Vuggy zone can contact and mobilise a large amount of oil in the Marly, which has remained relatively unaccessed by waterflooding. A coreflood program was designed at Saskatchewan Research Council (SRC) to address the CO2 injection process in Weyburn reservoir and comparable fields. Laboratory core displacement tests were conducted with a dual permeability split Berea core representing the Marly and Vuggy zones of a reservoir. Some preliminary results reported in a previous paper(3) showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone, and that the potential to recover incremental oil by a tertiary CO2 slug flood is high. After the technique of butting the core halves was improved, the several additional tertiary CO2 coreflood tests reported here were performed with Weyburn reservoir fluid at 63 ° C (reservoir temperature) to confirm the previous finding.