Lower Residual Oil Saturation Research Articles

New Method To Reduce Residual Oil Saturation by Polymer Flooding

SummarySix coreflood experiments were conducted to investigate the effect of hydrolyzed-polyacrylamide (HPAM) polymer solutions on the residual oil saturation (ROS) in Bentheimer-sandstone cores. All six cores were first saturated with brine and then flooded in the following sequence: oil to zero water cut, brine to zero oil cut, glycerin solution to zero oil cut, polymer in low-salinity brine to zero oil cut, and finally polymer in high-salinity brine to zero oil cut. The first polymer solution had approximately the same viscosity as the glycerin solution. The first polymer flood was designed to maximize the effect of viscoelasticity on the ROS by flooding the cores at a high Deborah number (NDe), and, as expected, resulted in a lower ROS. The second polymer flood in high-salinity brine had approximately the same viscosity, but a much lower relaxation time, and the flood had a much lower NDe. Unexpectedly, there was a further substantial reduction in ROS during the second polymer flood. The lowest ROS after the second polymer flood was only 0.07. This is a truly remarkable result, considering that there was no reduction in interfacial tension (IFT), the capillary numbers were maintained below the critical capillary number for Bentheimer sandstone, and the viscosities of both polymer solutions were equal to or less than that of the glycerin solution.

Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia

The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01–0.005 mm and the diameter of pores where these fines can be strained is 12 μm. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 μm are shown to be the strongest influencers on colmatation.

Subtle oil fields along the Western Flank of the Cooper/Eromanga petroleum system

Oil production from Cooper/Eromanga started in 1978, peaked in the 1980s and began a steady decline. Oil production from the Western Flank commenced in 2002 and has steadily increased. In the year until July 2014, a total of 8.6 million BBL of oil was produced from 16 active fields along the Western Flank, bringing the cumulative total to 24 million BBL. Western Flank oil has underpinned a ten-fold growth in market capitalisation in four listed Australian companies: Beach Energy, Drillsearch Ltd, Senex Energy and Cooper Energy. Two sandstone plays dominate the Western Flank petroleum geology: the Namur Sandstone low-relief structural play and the mid-Birkhead stratigraphic play. The use of 3D seismic has improved the definition of both plays, increased exploration success and optimised field appraisal and development drilling. Success rates have improved despite most Namur structural closures being close to the resolution margin for depth conversions (less than 8 m). Seismic attribute mapping is being refined in the more difficult search for mid-Birkhead stratigraphic traps with recent exploration discoveries indicating improved success. Reservoir properties in the Namur are excellent with multi-Darcy permeability, unlimited aquifer strength, low gas/oil ratio (GOR) and low residual oil saturation. This combination leads to an oil recovery factor greater than 75%. Initial free-flow production rates commonly exceed 6,000 BBL per a day. The mid-Birkhead reservoir is also of high quality but the lack of a strong aquifer drive reduces primary recovery. New and re-processed 3D seismic and water-flood projects are expected to drive further discoveries, reserve and production growth.

Hydrocarbon migration system of Fulaerji oil field, Songliao Basin, NE China

Abstract Through sedimentologic and petroleum geologic analysis of over 300 exploration wells in the north part of the west slope in the Songliao Basin, the conduit role the incised valley played in the oil and gas accumulation of the Fulaerji oil field is investigated. The major pays in the Fulaerji oil and gas field are the second and third members of the Cretaceous Yaojia Formation, where the hydrocarbon comes primarily from the Qijia-Gulong sag about 80 km east. The pathway of long distance hydrocarbon migration is the overlapping sandstone complex which fills the incised valley. The incised valley deposits overlapped on the delta deposits toward basin, and connected with shore-shallow lake sandy beach-bar formed during the highest lake flooding period toward the basin margin, constituting a sand rich sedimentary complex of delta - incised valley filling - shore sandy beach bar. Towards the basin, delta sand branches and pinches out in mudstone (mature source rock), transporting the hydrocarbon generated in the effective hydrocarbon kitchen to the incised valley filling body, the incised valley filling deposits transported hydrocarbon for a long distance to the updip pinching sandy beach bar lithologic trap, giving birth to the Fulaerji oil and gas reservoir. In the sand-rich sedimentary system related to the incised valley filling, the effective hydrocarbon transporting system is limited along Well Du 412 - Du 71 - Du 65 - Jiang 39 - Jiang 41 and Fulaerji oil and gas field. The pure hydrocarbon transporting layer is a water production layer with a high degree of hydrocarbon impregnation and low residual oil saturation. Baiyinnuole, Erzhan, Alaxin, Jiangqiao oil and gas fields distributed like a string of beads in NW are closely related to this effective hydrocarbon transporting system.

Evaluation of Hydrocarbon Saturation Using Carbon Oxygen (CO) Ratio and Sigma Tool


 The main aim of this study is to evaluate the remaining oil in previously produced zones, locate the water productive zone and look for any bypassed oil behind casing in not previously perforated intervals. Initial water saturation was calculated from digitized open hole logs using a cut-off value of 10% for irreducible water saturation. The integrated analysis of the thermal capture cross section, Sigma and Carbon/oxygen ratio was conducted and summarized under well shut-in and flowing conditions. The logging pass zone run through sandstone Zubair formation at north Rumaila oil field. The zones where both the Sigma and the C/O analysis show high remaining oil saturation similar to the open hole oil saturation, could be good oil zones that do not appear to be water flooded. The zones where the Sigma analysis shows high residual oil saturation, which is close to open hole oil saturation and the C/O analysis, show medium residual oil saturation; this could indicate that these zones were fresh water flooded to a certain extent and they still keep some residual oil. If the C/O analysis shows low residual oil saturation, it indicates that these zones were probably fresh water flooded thoroughly. If both Sigma analysis and the C/O analysis show medium residual oil saturation, most probably these zones were saline water flooded to a certain extent and they still keep some residual oil.

Structure of residual oil as a function of wettability using pore-network modelling

In the water flooding of mixed-wet porous media, oil may drain down to relatively low residual oil saturations (Sor). Various studies have indicated that such low saturations can only be reached when oil layers in pore corners are included in the pore-scale modelling. These processes within a macroscopic porous medium can be modelled at the pore-scale by incorporating the fundamental physics of capillary dominated displacement within idealised pore network models. Recently, the authors have developed thermodynamic criteria for oil layer existence in pores with non-uniform wettability which takes as input geometrically and topologically representative networks, to calculate realistic Sor values for mixed-wet and oil-wet sandstones [16, 21]. This previous work is developed in this paper to include (i) the visualisation of the 3D structure of this residual oil, and (ii) a statistical analysis of this “residual/remaining” oil. Both the visualisation and the statistical analysis are done under a wide range of wettability conditions, which is reported for the first time in this paper.The structure of residual oil for strongly water wet systems is well known (where residual=remaining oil) and our model agrees with this but this structure changes radically for mixed wet systems (where residual≠remaining) and this has not yet been visualised experimentally. We find that for more water-wet systems high final residual oil saturations are reached at relatively small amounts of water injected and this oil is present in the pores as bulk oil. On the other hand, for more oil-wet systems we find a slow decrease of the amount of remaining oil with increasing amounts of injected water. During the process, the remaining connectivity of the oil phase is increasingly provided by oil layers only, hence the slow drainage. The final residual oil saturation, only reached in the theoretical limit of an infinite amount of injected water, is almost entirely contained in large number of (relatively low volume) oil layers, which are present in pores of most radius sizes.

New Insights Into Steam/Solvent-Coinjection-Process Mechanism

Summary We present results of a detailed investigation of the steam/ solvent-coinjection-process mechanism by use of a numerical model with homogeneous reservoir properties and various solvents. We describe condensation of steam/solvent mixture near the chamber boundary. We present a composite picture of the important phenomena occurring in the different regions of the reservoir and their implications for oil recovery. We compare performances of various solvents and explain the reasons for the observed differences. An improved understanding of the process mechanism will help with selecting the best solvent and developing the best operating strategy for a given reservoir. Results indicate that as the temperature drops near the chamber boundary, steam starts condensing first because its mole fraction in the injected steam/solvent mixture (and hence its partial pressure and the corresponding saturation temperature) is much higher than the solvent's. As temperature declines toward the chamber boundary and steam continues to condense, the vapor phase becomes increasingly richer in solvent. At the chamber boundary where the temperature becomes equal to the condensation temperature of both steam and solvent at their respective partial pressures, both condense simultaneously. Thus, contrary to steam-only injection, where condensation occurs at the injected steam temperature, condensation of steam/solvent mixture is accompanied by a reduction in temperature in the condensation zone and the farther regions. However, there is little change in temperature in the central region of the steam chamber. The condensed steam/solvent mixture drains outside the chamber, leading to the formation of a mobile liquid stream (drainage region) where heated oil, condensed solvent, and water flow together to the production well. The condensed solvent mixes with the heated oil and further reduces its viscosity. The additional reduction in viscosity by solvent more than offsets the effect of reduced temperature near the chamber boundary. As the steam chamber expands laterally because of continued injection and as temperature in the hitherto drainage region increases, a part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation (ROS) in the steam chamber. Therefore, ultimate oil recovery with the steam/solvent-coinjection process is higher than that in steam-only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the ROS there. Our explanation is corroborated by the experimental results reported in the literature, which show smaller ROS in the steam chamber after a steam/solvent-coinjection process. A lighter solvent has a lower viscosity, a higher volatility, and a higher molar concentration of solvent in the drainage region. Thus, a lighter solvent causes a greater reduction in the viscosity of the heated oil and also leads to a lower ROS. Therefore, the lightest condensable solvent (butane, under the conditions investigated) provides the most favorable results in terms of enhancements in oil rate and oil recovery. This is different from the prior claims in the literature.

Investigating the pore-scale mechanisms of microbial enhanced oil recovery

Microbial Enhanced Oil Recovery (MEOR) is a process where microorganisms are used for tertiary oil recovery. Numerous mechanisms have been proposed in the literature through which microorganisms facilitate the mobilization of residual oil. Herein, we focus on the MEOR mechanisms of interfacial tension reduction (via biosurfactant) and bioclogging in water-wet micromodels, using Shewanella oneidensis (MR-1) that causes bioclogging and Bacillus mojavensis (JF-2) that produces biosurfactant and causes bioclogging. Micromodels were flooded with an assortment of flooding solutions ranging from metabolically active bacteria to nutrient limited bacteria to dead inactive biomass to assess the effectiveness of the proposed MEOR mechanisms of bioclogging and biosurfactant production. Results indicate tertiary flooding of the micromodel system with biomass and biosurfactant was optimal for oil recovery due to the combined effects of bioclogging of the pore-space and interfacial tension reduction. However, biosurfactant was able to recover oil in some cases dependent on wettability. Biomass without biosurfactant that clogged the pore-space also successfully produced additional oil recovery. When analyzing residual oil blob morphology, MEOR resulted in oil blob size and radius of curvature distributions similar to those obtained by an abiotic capillary desaturation test, where flooding rate was increased post secondary recovery. Furthermore, for the capillary number calculated during MEOR flooding with bioclogging and biosurfactant, lower residual oil saturation was measured than for the corresponding capillary number under abiotic conditions. These results suggest that bioclogging and biosurfactant MEOR is a potentially effective approach for pore morphology modification and thus flow alteration in porous media that can have a significant effect on oil recovery beyond that predicted by capillary number.

Downhole Steam Generation Pushes Recovery Beyond Conventional Limits

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 150515, ’Advancing Thermal and Carbon Dioxide Recovery Methods Beyond Their Conventional Limits: Downhole Innovation,’ by Laura Capper, SPE, CAP Resources; Myron Kuhlman, SPE, MK Tech Solutions; George Vassilellis, SPE, Gaffney Cline & Associates; M.J. Schneider, Global Marine Drilling Company; and Nick Fitzpatrick, World Energy Systems, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed. Enhanced oil recovery (EOR) is a general term used for processes that seek to improve recovery of hydrocarbons from a reservoir after the primary production phase. EOR is designed to increase the mobility of the oil, with an objective of improving oil sweep efficiency or enabling lower residual-oil saturation. Downhole steam generation (DHSG), which combines thermal and nitrogen or CO2 EOR, offers several benefits to accelerate the production of oil. Moreover, the CO2 that is generated in situ can be used elsewhere. Conventional-EOR Limitations Surface-Steam-Injection Limitations. Steam that has 100% quality consists entirely of vapor, whereas 0% steam quality is liquid water. Higher-quality steam, therefore, contains much more energy than lower-quality steam, and higher steam quality (generally greater than 60%) results in more-effective oil recovery. The steam vapor transfers heat to the oil, lowering its viscosity, and, when it condenses, the resulting water drives the oil toward the producer well. A simulation and field economic model for a 2,000-ft-deep reservoir in California showed that steam quality drops to 50% or below at approximately 700 m (approximately 2,300 ft). There-fore, surface steam injection is generally limited to reservoirs no deeper than 800 m and, more typically, is applied in reservoirs less than 500 m deep. CO2 Limitations. CO2 use is largely dependent on the reservoir’s proximity to large natural sources or large refineries, chemical plants, or gas plants that produce nearly pure CO2. Because oil fields are not necessarily near these sources, pipelines have been the main source of CO2, and their availability and cost limit applications of CO2 EOR. When reservoir pressure is too low or oil gravity is too high, much of the CO2 does not dissolve in the oil. However, at high pressure, enough CO2 (40–60 mol%) dissolves in the oil to improve heavy-oil recovery by causing the oil to swell, reducing the oil’s density and improving mobility. Conventional In-Situ-Combustion Limitations. In both light- and heavy-oil reservoirs, burning some of the oil in situ creates a combustion zone that moves through the formation. In deep light-oil reservoirs, in-situ combustion (ISC) (or high-pressure air injection) is a method of generating an inert gas from spontaneous combustion of the oil at temperatures above 75°C. This provides pressure maintenance to the reservoir. In heavy-oil reservoirs, combustion creates a steam drive (whose size depends on connate water or the amount of injected water) and an inert-gas drive for the recovery of oil.

Alkaline Steam Foam: Concepts and Experimental Results

Summary Experimental studies have shown that the steam-foam process can be enhanced significantly by injecting a suitably formulated alkali/surfactant mixture in the aqueous phase of steam. Emulsionscreening tests, corefloods, and flow-visualization experiments using an alpha olefin sulfonate (AOS) surfactant with 16–18 carbon, Na2CO3, and a heavy Californian crude have shown that alkaline steam foam offers significant advantages over regular steam foam by combining the benefits of thermal and chemical enhanced-oil-recovery (EOR) processes. First, Na2CO3 reduces surfactant consumption by adsorption by rendering the clay surface more negatively charged. Second, by precipitating divalent ions that get ion exchanged off the clays, Na2CO3 reduces surfactant consumption by precipitation. Third, a suitably formulated alkali/surfactant system reduces the oil/water interfacial tension (IFT) sufficiently to enable the heavy oil to be emulsified into the aqueous phase in the presence of steam. This oil-in-water emulsion is less viscous than the oil alone and can be readily transported. Consequently, the residual-oil saturation (ROS) is reduced to a value less than that of steam. Fourth, this lower ROS reduces the destabilizing effect of oil on foam, resulting in stronger steam foam that provides better mobility control than regular steam foam. Therefore, it has the potential to further reduce steam gravity override. Fifth, the reduction in gravity override also reduces loss of heat to the cap rock, thereby improving steam utilization. When applied to steamdrive, alkaline steam foam has the benefit of increasing foam-propagation rate, improving mobility control, improving steam use, and reducing the ROS. Potential applications of alkaline steam foam to steam soaks and steam-assisted gravity drainage (SAGD) are also discussed.

Prediction of three-phase saturation profiles from two-phase capillary pressure curves as a function of wettability

Gravity drainage of oil with gas is an efficient recovery method in strongly water-wet reservoirs and yields very low residual oil saturations. However, many of the oil-producing reservoirs are not strongly water-wet. Thus, predicting the profiles and ultimate recovery for mixed and oil-wet media is essential to design and optimisation of improved recovery methods based on three-phase gravity drainage. In this study, we perform two- and three-phase gravity drainage experiments in sand-packed columns with varying wettability. We propose a simple method for predicting the three-phase equilibrium saturation profiles as a function of wettability. In each case, the three-phase results were compared to the predictions from two-phase results of the same wettability. We find that the gas/oil and oil/water transition levels can be predicted from pressure continuity arguments and the two-phase data. The predictions of three-phase saturations work well for the water-wet media, but become progressively worse with increasing oil-wet fraction.

Effect of Elasticity During Viscoelastic Polymer Flooding: A Possible Mechanism of Increasing the Sweep Efficiency

Summary It has been long believed that the viscoelasticity of polymer solution improves the displacement efficiency in polymer flood operations, but the individual effect of elasticity has not been clearly distilled for a single viscoelastic polymer. In this study, the effect of elasticity of polymer-based fluids on the microscopic sweep efficiency is investigated by injecting two polymer solutions with similar shear viscosity, but significantly different elastic characteristics. Blends of various grades of polyethylene oxide (PEO) with similar average molecular weight and different molecular weight distribution (MWD) were prepared by dissolving in deionized water. The polymer solutions exhibited identical shear viscosity, but different elasticity. A series of experiments were performed by injecting the polymer solutions through a sandpack saturated with mineral oil. The experiments were performed using a special core holder designed to simulate radial flow. Injection was done through a perforated injection line located at the centre of the cell and fluids were produced through two production lines located at the periphery. The experiments were conducted within a shear rate range of field applications. Because both polymer solutions had similar shear viscosity behaviour, but different elastic properties, it was possible to see the effect of elasticity on the sweep efficiency alone. Results of the polymer flooding experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the MWD of the solution at constant shear viscosity and polymer concentration. The polymer solution with higher elasticity exhibited considerably higher resistance to flow through porous media than the one with lower elasticity, resulting in higher sweep efficiency and lower residual oil saturation.

QUANTITATIVE ESTIMATES OF OIL LOSSES DURING MIGRATION, PART II: MEASUREMENT OF THE RESIDUAL OIL SATURATION IN MIGRATION PATHWAYS

Recent experimental observations have demonstrated that losses of oil in a secondary migration pathway depend largely on the characteristics of the pathway itself. Accurate assessments of the residual saturation are required to quantify losses during migration. In the present paper, the authors report on experimental procedures designed to evaluate the oil saturation at various stages of the migration/invasion process. The experiments made use of both apparatuses filled with an artificial medium composed of glass beads, and cores composed of reservoir sandstones from oilfields in NE China. The saturation of residual oil in the pathways was measured by nuclear magnetic resonance imaging.Experiment results show that mobile oil continues to migrate in a porous medium when the supply of oil has been stopped, but that the migration pathway shrinks and may become disconnected into isolated segments. Once active migration ceases, the residual oil saturation varies significantly from location to location within a pathway, and the average residual oil saturation falls to 30∼60%, depending on grain size and composition. A porous medium composed of large grains commonly contains large pores and pore throats and thus may correlate with low residual oil saturations.

Laboratory Screening for Air Injection-Based IOR in Two Waterf looded Light Oil Reservoirs

Abstract In the last two decades, air injection has proven to be an effective method for enhanced recovery from light oil reservoirs. This has led to a need for effective laboratory procedures for screening potential candidate reservoirs, many of which have been previously waterflooded. Experiments at the University of Calgary have shown the benefit of Accelerating Rate Calorimeter (ARC) tests in conjunction with traditional combustion tube testing at reservoir pressure for the planning of field scale implementations. In this study, four ARC tests and two combustion tube tests were performed on resaturated cores from each of the Avil? and Troncoso waterflooded light oil reservoirs of Argentina. The paper reviews the characteristics of the two reservoirs, describes the tests that were performed on the reservoir samples, and summarizes the results obtained. The ARC tests provided Arrhenius-type kinetic rate data for the ignition and combustion reactions. The combustion tube tests were used to evaluate the air requirements and overall burn stability. For each reservoir, one combustion tube test was performed at the original oil and water saturation while the second test was performed at the waterflooded saturation. The effect of initial oil saturation on the burning characteristics and liquid recoveries is of particular interests to operators considering air injection-based oil recovery projects. Background The application of air injection-based processes (or fireflooding) to deep, high pressure light oil reservoirs is a relatively new IOR process. While past applications of this process to low API oils have met with mixed success, many of the problems encountered in heavy oil reservoirs relating to mobility and unfavourable oxidation characteristics are not an issue in high API oils(1, 2, 3). The success of this process is evident from the recent start-up of a new project by Continental Resources, injecting 85 MMscfd of air into a field in the Williston Basin. Currently, several other companies are actively researching potential candidate reservoirs for air injection- based recovery processes. While air injection into light oil reservoirs is not a new process, more recent applications of air injection to light oil fields have targeted reserves that are deep and/or have had low permeability, rendering them poor candidates for waterflooding(4). However, the resulting successes and potential process benefits(5) have extended interest in this IOR process to all types of light oil reservoirs, including those that have undergone waterflooding as a secondary recovery mechanism. Air injection into previously waterflooded reservoirs entails additional considerations. From an operational viewpoint, extensive waterflooding can result in the lowering of the overall reservoir temperature, making the oil less reactive to the oxygen in the injected air. Air injection processes rely on combustion reactions between oxygen and a fraction of the oil in place to produce heat and carbon oxides, so it may be necessary to provide an artificial ignition source. The presence of large saturations of water in the reservoir constitutes a heat load to the combustion process, as it is vapourized by the advancing reaction front. Highly permeable flow channels may have very low residual oil saturations, particularly around water injection wells.

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.

Application of Predictive Enhanced Oil Recovery Models on a Very Heavy Oil Field

In this study, several predictive enhanced oil recovery (EOR) techniques are used to evaluate potential thermal oil recovery techniques that could be applied on a very heavy oil (10-12°API) field located in Southeast Turkey. Two of the EOR techniques were found to be applicable after the screening process: in situ combustion and steam injection. Sensitivity of the processes to several operating parameters, such as steam injection rate, air injection rate, and steam quality, were established. It was observed that initial project life was not critical in steam injection. However, at higher air injection rates project life was shorter for in situ combustion. As a result of steam-flood and in situ combustion model applications, it was observed that the steam-flood model provided higher recoveries and longer project lives with low residual oil saturation.

A pore‐level scenario for the development of mixed wettability in oil reservoirs

AbstractUnderstanding the role of thin films in porous media is vital to elucidate wettability at the pore level. The type and thickness of films coating pore walls determine reservoir wettability and whether or not reservoir rock can be altered from its initial state of wettability. Pore shape, especially pore wall curvature, is important in determining wetting‐film thicknesses. Yet, pore shape and physics of thin wetting films are generally neglected in flow models in porous rocks. Thin‐film forces incorporated into a collection of star‐shaped capillary tubes model describe the geological development of mixed wettability in reservoir rock. Here, mixed wettability refers to continuous and distinct oil and water‐wetting surfaces coexisting in the porous medium. This model emphasizes the remarkable role of thin films.New pore‐level fluid configurations arise that are quite unexpected. For example, efficient water displacement of oil (low residual oil saturation) characteristic of mixed‐wettability porous media is ascribed to interconnected oil lenses or rivulets which bridge the walls adjacent to pore corners. Predicted residual oil saturations are approximately 35% less in mixed‐wet rock than in completely water‐wet rock. Calculated capillary pressure curves mimic those of mixed‐wet porous media in the primary drainage of water, imbibition of water, and secondary drainage modes. Amott‐Harvey indices range from −0.18 to 0.36 also in good agreement with experimental values (Morrow et al., 1986; Jadhunandan and Morrow, 1991).

Interwell Tracer Test To Determine Residual Oil Saturation In A Gas-Saturated Reservoir. Part II: Field Applications

Abstract This paper entails the implementation and interpretation of the first successful interwell test ever reported in the industry to determine residual oil saturation in a gas-saturated reservoir. Two interwell tests were conducted in Golden Spike to measure the residual oil saturation to gas-flood at two different depths. This method, which involves the comparison of the whole partitioning and non-partitioning tracer curves to derive residual oil saturation values, is an improvement of the original method that compared only the breakthrough times. A chromatographic transformation technique was developed for curve comparison so as to avoid tedious simulation for data interpretation. For layers with different residual oil saturation, the transformation method works only for a pseudo single porosity reservoir with ordered layers, i.e. low residual oil saturation for a high permeability layer. The first test indicated that there were three layers with residual oil saturations of 7%, 15% and 20%. The results from the second test conducted in a lower production interval were masked by the presence of extensive fractures in the production zone. In spite of the interference from the fracture production, the residual oil saturation in some flow channels could still be estimated to be about 12%. Because it is unlikely that the tracers could enter the matrix during the test, the residual oil saturation measured is probably the oil saturation in some secondary channels. Sulphur hexafluoride, F13BI (brome-trifluoro-methane) and F12 (dichloro-difluoro-methane) were selected as the tracers from the previous lab tests. The tracers were pre-mixed and injected as a liquid. A Freon phase behavior program was developed to calculate the exact amount of the Freon's injected. Introduction Upon evaluation of various conventional methods, the interwell tracer test(1) has been identified as the most reliable means to determine residual oil saturation in Golden Spike, a low-pressure, low-porosity, gas-saturated carbonate reservoir. The original interwell method disclosed by Cooke(2) in 1971 involved the comparison of the relative breakthrough times of the partitioning and non-partitioning tracers for residual oil saturation calculation. Breakthrough time is not a well-defined quantity, as it is often obscured by dispersion, the detection limit, and most importantly, by the streamline and layer distributions. As a result, the interpretation technique, certainly inadequate, draws criticism(3,4). Consequently, because of the lack of suitable chemicals and interpretation technique, no single test has been tried in the field or, at least, published in the literature. To circumvent the problems anticipated in Cooke's method, our interwell method employed a whole curve comparison to derive a residual oil saturation value at any location on the curve using a simple "landmark" comparison technique. Under ideal conditions, residual oil saturation can be determined by layers. To demonstrate the feasibility of the method, extensive tests were performed in the lab(5). Slim tube displacement results indicated that residual oil saturation could be measured in an accuracy of± 1 % pore volume from the separation of tracers. This paper entails the design, implementation and interpretation of the two field tests conducted in Golden Spike in 1987.

Relative Permeabilities at Simulated Reservoir Conditions

Summary Relative permeability was determined at conditions from ambient to those simulating a depth of 1200 m [3,940 ft] from laboratory displacement data. The data were analyzed with the semianalytical interpretation method of Civan and Donaldson, which includes capillary pressure. The unsteady-state displacement method requires that the data be collected at high flow rates to diminish the influence of capillary end effects. including capillary pressure removes this constraint but results in a more complex mathematical model. The results show the capillary end effects and the error introduced by not including them in the calculation of relative permeability. When capillary pressure was ignored in our model, it reproduced the literature values. Relative permeability measurements at elevated temperature show the characteristic temperature effect of higher oil relative permeability and lower residual oil saturation (ROS). These effects result from a change of wettability to a more water-wet condition at the higher temperatures. The equipment used for relative permeability measurement can easily be constructed; in fact, some commercial designs can be used without modification. The results represent data at reservoir conditions; the data are taken on cores that are recompressed, eliminating the adverse influence of microfractures and changes of pore-size distribution frequently present in field cores run at ambient conditions. The displacement data are not restricted to high-flow-rate experimental conditions; removal of this restriction allows the analysis of low-permeability cores when flow rates are necessarily low.

Mechanisms of Residual Oil Displacement by Steam Injection

Summary In an attempt to isolate various thermal and hydrodynamic mechanisms, a model of one-dimensional (1D) steam displacement of residual oil has been developed. The quasisteady model considers capillary pressure gradients and gravity forces during the simultaneous flow of oil, water, and steam to be the dominant factors in oil-bank mobilization. It was shown that under most conditions, the Buckley-Leverett displacement velocity is significantly faster than the steam-condensation-front velocity. This feature dictates the use of the steam-condensation-front velocity as the characteristic velocity in the problem formulation. Semianalytical solutions of saturation and pressure distributions are presented. Experiments were conducted to examine steam displacement of volatile, partially volatile, and nonvolatile nonaqueous-phase liquids at a residual saturation of 2.5%. Complete displacement of all low-viscosity, partially volatile liquids was observed. Displacement of a high-viscosity, nonvolatile oil was not observed. These experiments and similar results from the literature were in reasonable agreement with the model. It is concluded that mass-transfer-limited evaporation of hydrocarbon components with significant vapor pressures is responsible for the observed low residual oil saturations (ROS’s) in the steam zone.