Waterflood Residual Saturation Research Articles

On the reduction of the residual oil saturation through the injection of polymer and nanoparticle solutions

Polymer flooding has been traditionally applied to achieve favorable mobility ratios compared to water flooding, and thus increase formation sweep efficiency in oil displacement processes. Based on laboratory studies, several authors have reported lower residual oil saturations, Sorc, to the waterflood residual oil saturation, Sorw, when viscoelastic polymers were used during polymer flooding. The reported mechanisms contributing to the observed reduced residual oil saturation include mobility control, improved sweep efficiency, and improved microscopic displacement efficiency. The limitations of polymer flooding are obvious: high oil viscosity requires high concentration of polymer which increases the process cost, presence of clays which increases polymer adsorption, formation brine and water make-up salinity and type of ions which will affect the injected polymer viscosity, and extensively fractured formations which will cause sweep challenges. This review paper summarizes the most recent research findings, observations, conclusions, and reported physical mechanisms contributing to more efficient oil displacement processes and lower than Sorw residual oil saturation. The discussion focuses on viscoelastic polymer oil displacement processes and includes formation water and polymer solution salinity, resistance factor (RF), and polymer molecular weight effects. The use of nanoparticles (NPs) during polymer flooding is examined and results obtained are also reported in this review. More specifically, the polymer-NP system rheological behavior for several different types of NPs and surface modified silica NP are examined to find the most efficient system for oil displacement. Mechanisms contributing to more effective oil displacement processes when carefully screened NPs are added into the viscoelastic polymer solutions include interfacial tension reduction, formation wettability alteration, increased injected polymer solution viscosity, and prevention of asphaltene precipitation.

The effect of deformation on two-phase flow through proppant-packed fractured shale samples: A micro-scale experimental investigation

We present the results of an extensive micro-scale experimental investigation of two-phase flow through miniature, fractured reservoir shale samples that contained different packings of proppant grains. We investigated permeability reduction in the samples by conducting experiments under a wide range of net confining pressures. Three different proppant grain distributions in three individual fractured shale samples were studied: i) multi-layer, ii) uniform mono-layer, and iii) non-uniform mono-layer. We performed oil-displacing-brine (drainage) and brine-displacing-oil (imbibition) flow experiments in the proppant packs under net confining pressures ranging from 200 to 6000 psi. The flow experiments were performed using a state-of-the-art miniature core-flooding apparatus integrated with a high-resolution, X-ray microtomography system. We visualized fluid occupancies, proppant embedment, and shale deformation under different flow and stress conditions. We examined deformation of pore space within the proppant packs and its impact on permeability and residual trapping, proppant embedment due to changes in net confining stress, shale surface deformation, and disintegration of proppant grains at high stress conditions. In particular, geometrical deformation and two-phase flow effects within the proppant pack impacting hydraulic conductivity of the medium were probed. A significant reduction in effective oil permeability at irreducible water saturation was observed due to increase in confining pressure. We propose different mechanisms responsible for the observed permeability reduction in different fracture packings. Samples with dissimilar proppant grain distributions showed significantly different proppant embedment behavior. Thinner proppant layer increased embedment significantly and lowered the onset confining pressure of embedment. As confining stress was increased, small embedments caused the surface of the shale to fracture. The produced shale fragments were then entrained by the flow and partially blocked pore-throat connections within the proppant pack. Deformation of proppant packs resulted in significant changes in waterflood residual oil saturation. In-situ contact angles measured using micro-CT images showed that proppant grains had experienced a drastic alteration of wettability (from strong water-wet to weakly oil-wet) after the medium had been subjected to flow of oil and brine for multiple weeks. Nanometer resolution SEM images captured nano-fractures induced in the shale surfaces during the experiments with mono-layer proppant packing. These fractures improved the effective permeability of the medium and shale/fracture interactions.

Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood

SummaryClassical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world's largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.

Effluent as Surfactant for Enhanced Oil Recovery

This investigation considers black liquors (BL) as candidates for chemical enhanced oil recovery (EOR) process. These BLs were effluents from paper mills. The main constituent of BL is sodium lignosulfonate, an anionic surfactant. Results show that these anionic surfactants may be the preferred candidates for EOR as they may be effective in creating low interfacial tension (IFT) at dilute concentrations without requiring an alkali or a co-surfactant. Some of the formulations exhibit a low IFT at high salinity, and hence may be suitable for use in high saline reservoirs. Adsorption tests were conducted on core samples whichindicate that the loss of these formulated surfactants may be comparable to other types of anionic surfactants. Evaluation of surfactants performance was done in oil recovery by core flood tests. Selected formulations recovered about 20-30% of the waterflood residual oil saturation even with dilute concentration of 0.18 wt% surfactant concentrations from core samples.

Bench-Scale Production of Biosurfactants and their Potential in Ex-Situ MEOR Application

The fermentative production of biosurfactants by five Bacillus strains in a bench-scale bioreactor and evaluation of biosurfactant-based enhanced oil recovery using sand pack columns were investigated. Adjusting the initial dissolved oxygen to 100% saturation, without any further control and with collection of foam and recycling of biomass, gave higher biosurfactant production. The microorganisms were able to produce biosurfactants, thus reducing the surface tension and interfacial tension to 28 mN/m and 5.8–0.5 mN/m, respectively, in less than 10 hours. The crude surfactant concentration of 0.08–1.1 g/L, and critical micelle concentration (CMC) values of 19.4–39 mg/L, corresponding to the biosurfactants produced by the different Bacillus strains, were observed. The efficiency of crude biosurfactant preparation obtained from Bacillus strains for enhanced oil recovery, by sand pack column studies, revealed it to vary from 30.22–34.19% of the water flood residual oil saturation. The results are indicative of the potential of the strains for the development of ex-situ, microbial-enhanced, oil recovery processes.

An artificial neural network model for predicting the recovery performance of surfactant polymer floods

Abstract A supervised feed-forward back-propagation neural network model has been developed for estimating the recovery performance of a reservoir subjected to a surfactant–polymer (SP) flood. The optimal network paradigm has been designed by conducting extensive experimentation on the proper number of hidden layers, and of neurons in each of these layers. The optimal multi-layered network topology consists of an 18-neuron input layer, three 11-neuron hidden layers, and a four-neuron output layer. The network input consists of 18 dimensionless groups that critically dominate the displacement efficiency of SP floods. These groups account for the effects of surfactant slug size, polymer slug size, surfactant concentration, surfactant/oil bank mobility ratio, polymer/surfactant mobility ratio, surfactant and polymer adsorption, interfacial tension, reservoir heterogeneity, relative permeabilities, capillary pressure, waterflood residual saturations, the optimal salinity in the three-phase region, gravity, and rock wettability. Principal component analysis indicated that all of these 18 dimensionless groups were essential for scaling SP floods. The network output consists of the oil recovery at 0.75, 1.5, and 2.25 pore volumes injected (PVI), along with estimates of the breakthrough dimensionless time. The network model has been trained on a data set consisting of 499 simulations, generated using a three-dimensional compositional chemical flood simulator. Tertiary chemical floods constitute 90% of the simulation runs. The rest of the simulation cases are secondary chemical injections. The optimal network architecture was able to estimate back the oil recovery from the training set within 1.5% average absolute error. The ANN model was able to predict the oil recovery for a blind-test data-set of 125 simulated field cases within approximately 3% average absolute error. With these remarkable results, the ANN model outperformed the non-linear multivariate models available in the literature. Compared to using extensive numerical modeling based on the detailed knowledge of the oil reservoir, the use of the introduced ANN model saves significant amount of time needed for the performance prediction of surfactant–polymer floods. The ANN model may, therefore, be used as a valuable tool for the preliminary assessment of oil reservoirs with respect to their suitability for surfactant–polymer flood.

Effluent as surfactant for enhanced oil recovery

This investigation considers black liquors (BL) as candidates for chemical enhanced oil recovery (EOR) process. These BLs were effluents from paper mills. The main constituent of BL is sodium lignosulfonate, an anionic surfactant. Results show that these anionic surfactants may be the preferred candidates for EOR as they may be effective in creating low interfacial tension (IFT) at dilute concentrations without requiring an alkali or a co-surfactant. Some of the formulations exhibit a low IFT at high salinity, and hence may be suitable for use in high saline reservoirs. Adsorption tests were conducted on core samples whichindicate that the loss of these formulated surfactants may be comparable to other types of anionic surfactants. Evaluation of surfactants performance was done in oil recovery by core flood tests. Selected formulations recovered about 20-30% of the waterflood residual oil saturation even with dilute concentration of 0.18 wt% surfactant concentrations from core samples.

Experimental Investigation of Production Characteristics of the Gravity-Assisted Inert Gas Injection (GAIGI) Process for Recovery of Waterflood Residual Oil: Effects of Wettability Heterogeneity

The impact of reservoir heterogeneities in terms of wettability at the macroscopic scale on the recovery efficiency of the gravity-assisted inert gas injection (GAIGI) process was investigated through a systematic experimental study for tertiary recovery of waterflood residual oil. Isolated inclusions of oil-wet consolidated glass beads were embedded in a continuum of unconsolidated water-wet glass beads to create heterogeneous packed columns. In comparison to water-wet homogeneous porous media, such heterogeneous media allowed us to establish higher waterflood residual oil saturation whose amount varied linearly with the volume fraction of oil-wet heterogeneities in the packing. Experimental results obtained from tertiary gravity drainage experiments demonstrated that the continuity of water-wet portions of the heterogeneous porous medium facilitates the tertiary oil recovery through the film flow mechanism, provided that the oil-spreading coefficient is positive. In addition, owing to the high waterflood residual oil content of the heterogeneous media tested, the oil bank formation occurred much earlier and grew faster, resulting in a higher oil recovery factor. However, having favorable wettability conditions in homogeneous porous media resulted in slightly lower reduced residual oil saturation after the GAIGI process compared to that in the heterogeneous media with the same condition of withdrawal rate. A relationship between the oil recovery factor at gas breakthrough and gravity number was developed for the heterogeneous and homogeneous media. The recovery factor at gas breakthrough versus gravity number in homogeneous media follows a similar trend as that of homogeneous water-wet porous media. However, at a given gravity number, the recovery factor of heterogeneous media was greater than that of the homogeneous media.

Laboratory Investigation of Enhanced Light-Oil Recovery By CO/Flue Gas Huff-n-Puff Process

Abstract This paper focuses on phase behaviour measurements with reservoir oil-CO2 mixtures and on coreflooding tests in the huffn- puff mode to characterize the system, determine the influential mechanisms, and supply data for simulation of the field implementation. The results indicate that significant amounts of CO2 could dissolve in the oil, which caused oil swelling and viscosity reduction. During the puff cycle, the oil retained CO2 preferentially to methane; thus, the beneficial swelling and viscosity effects were maintained over an extended portion of this cycle. Corefloods were performed to investigate the effect of waterflood residual oil saturation and injection gas composition (CO2 and enriched flue gas) on oil recovery. Incremental oil recovery was observed to be sensitive to waterflood residual oil saturation and to the process application scheme. Coreflooding results suggest that the huff-n-puff process may be more suitable to oil-wet than water-wet reservoirs. Introduction Various technologies have been applied in tertiary oil recovery processes, such as gas miscible/immiscible injection and chemical flooding. Among these enhanced oil recovery (EOR) methods, the huff-n-puff process has been reported to be economic at an oil price of less than US$20/STB and CO2 costs of US$40/ton(1). For example, it was shown in a flue-gas huff-n-puff project(2)that oil production rates stabilized, and the project proved to be cost effective with small investment requirements and low operating costs. In another case(3), the CO2 huff-n-puff process was not successful in increasing incremental oil recovery. However, there were reduced water-handling and electrical requirements during the injection, soak, and flow phases, which were beneficial to the project. There is increasing interest in CO2/flue-gas huff-n-puff injection into single wells because the process is relatively easy to apply and does not require a large initial capital outlay. The process typically begins with the injection of a slug of gas into a single well. This is followed by a shut-in or soak period to allow the gas to dissolve into the oil, swell its volume, and reduce its viscosity. The same well is then returned to production and the response is monitored. In reservoirs with poor inter-well communication, this single-well approach may be one of the best ways, and sometimes the only way, to accelerate response in underperforming wells. Since miscibility between the reservoir oil and injected gas is not a requirement of the huff-n-puff process, it is well suited for low pressure reservoirs and for gases with high minimum miscibility pressures such as flue gas. The mechanisms involved in the production of oil during gas huff-n-puff are diverse and complex. The following mechanisms have been mentioned in the literature(4–6):oil viscosity reduction;oil swelling;solution gas drive;relative permeability hysteresis due to reduced water saturation, drainage/imbibition, and wettability alternation;repressurization;gas diffusion and mass transfer; and,interfacial tension reduction in the zone near the wellbore. The purpose of this work is to investigate the potential for applying the CO2 huff-n-puff process in a medium-gravity oil reservoir in Saskatchewan.

Induced Multiphase Flow Behaviour Effects in Gas Injection EOR Projects

Abstract The recovery of oil by secondary waterfloods and tertiary miscible floods is significantly affected by the native wettability state of the reservoir. In gas injection EOR processes, the initial wettability state of the reservoir could be significantly altered due to mass transfer and phase behaviour interactions between the injected gas and the reservoir crude oil. This, in turn, would influence the water-oil and water-gas flow behaviour by altering their relative permeabilities. Should the reservoir engineer include these dynamic interactions and flow behaviour modifications in designing gas injection projects for optimum economic benefits? We seek to address this question by extending our understanding of the influence of the native wettability state on watergas relative permeability by experimental measurements and by quantifying the effects of induced wettability and relative permeability changes on gas-flood design parameters. A sequence of coreflood steps was designed to mimic the field practices used in water-alternating-gas (WAG) injection projects. The sequence has been applied to two reservoir rockfluids systems. Each sequence consists of four cycles of immiscible nitrogen floods in the core assembly at four different stages starting with clean core (unexposed to oil), core containing liveoil at waterflood-residual saturation, core subjected to a miscible flood, and the core after a repeat of the miscible flood. Both the rock-fluids systems studied indicate that the watergas flow behaviour is modified due to the miscible displacement. These results, combined with the knowledge of our previous work on oil-water flow behaviour modifications, imply the need for a dynamic mode of miscible flood design that would incorporate the in situ rock-fluids interactions. The results of this experimental study and their impact on WAG ratio calculations are presented and discussed in the paper. Introduction A summary of Canadian, US and worldwide EOR production data for the past decade has been recently provided(1). These data indicate that nearly all of the gas-based EOR production in Canada has been due to hydrocarbon gas injection. However, the production share of hydrocarbon gas injection projects (as a per cent of total EOR production) has steadily declined from 49% in 1992 to about 18% in 2000, while steam-based thermal EOR of heavy oil has steadily grown during this period. The historical predominance of hydrocarbon gases over CO2 in Canadian miscible projects appears to be changing. With PanCanadian's Weyburn CO2 miscible project coming on stream this year, the share of EOR production by CO2 injection will increase significantly. The EOR data for the US indicate that, while the production (and number) of CO2 miscible projects has increased steadily over the last two decades, all other gas injection projects (CO2 immiscible, N2 and flue gas) have declined or become extinct except for the hydrocarbon miscible projects. The production from miscible hydrocarbon gas injection projects in the US has steadily increased, in spite of their decreasing numbers. The overall effect is that the share of production from gas injection EOR in the US has almost doubled from 23% in 1990 to 42% in 2000. The worldwide EOR data indicate the increasing dominance of hydrocarbon miscible projects over CO2, and a reversal, in 2000, of the decade-long decreasing trend in the production share of gas injection projects. This discussion points out the significant role that gas injection processes will continue to play in the world to enhance oil recovery.

The effect of wettability on three-phase relative permeability

We study three-phase flow in water-wet, oil-wet, and fractionally-wet sandpacks. We use CT scanning to measure directly the oil and water relative permeabilites for three-phase gravity drainage. In an analogue experiment, we measure pressure gradients in the gas phase to determine the gas relative permeability. Thus we find all three relative permeabilities as a function of saturation. We find that the gas relative permeability is approximately half as much in a oil-wet medium than in an water-wet medium at the same gas saturation. The water relative permeability in the water-wet medium and the oil relative permeability in the oil-wet medium are similar. In the water-wet medium the oil relative permeability scales as kro ∼ So4 for So > Sor, where Sor is the waterflood residual oil saturation. With octane as the oil phase, kro ∼ So2 for So < Sor, while with decane as the oil phase, kro falls sharply for So < Sor. The water relative permeability in the oil-wet medium resembles the oil relative permeability in the water-wet medium for a non-spreading oil such as decane. These observations can be explained in terms of wetting, spreading, and the pore scale configurations of fluid.

A Waterflood And Chemically Improved Oil Recovery Evaluation For the Pembina Bear Lake Unit

Abstract The Pembina Cardium reservoir is the largest conventional oil reservoir discovered thus far in Canada, and has been extensively waterflooded since the late fifties. Operating waterfloods are now reaching their economic limits and improved oil recovery techniques are being considered to extend the life of the reservoir. This report investigates the technical feasibility of applying a chemical flood to the Pembina Bear Lake reservoir. The investigation has two major components. First, a chemical system was designed that lowered the brine/oil interfacial tension sufficiently to mobilize waterflood residual oil. Second, the effectiveness of the chemical system was tested using corefloods at reservoir conditions. Through phase behaviour studies an optimum chemical composition was determined: 5 wt% Petrostep B100 + 2 wt% nbutanol + 0.5 wt% NaCl in Bear Lake Brine. Injection of a slug of this chemical composition led to an incremental recovery of up to 48.5% OOIP Bear Lake Crude in homogenous rock material. Using real reservoir core the average incremental oil recovery was only 15% OOIP. The low oil recovery during the chemical floods in reservoir cores is a direct result of the extreme heterogeneity in the conglomerate rock. Introduction The Bear Lake reservoir consists of several deposited sandstone layers overlain by a high permeability conglomerate layer. During waterflooding, the conglomerate acts as a thief zone through which most of the water channels. The waterflood residual oil saturation has been estimated to be approximately 50%, reducing the oil recovery during waterflooding even further. As a result large quantities of oil are left behind due to poor sweep and poor displacement. This kind of problem can be addressed in several ways. One option is to place a blocking agent into the conglomerate zone to force more water into the sandstone layers. The sandstone layers would be better swept, improving the oil recovery. However, a large amount of waterflood residual oil would be locked in the conglomerate layer and lost from future production. Therefore, it was decided to look at a chemical flooding option to lower the waterflood residual oil and improve the sweep efficiency at the same time. Lowering the interfacial tension between reservoir brine and oil to the point of micro-emulsification has been proven to be tremendously effective in reducing residual oil saturations. The interfacial tension can be lowered by injecting a properly selected surfactant solution into the reservoir. Increasing the viscosity of the injection brine with polymer addition enhances the oil recovery by improving the sweep efficiency and displacing emulsified oil. In this work a micellar-polymer process was investigated for application in the Pembina Bear Lake Unit. Theory Micellar-polymer flooding relies on the injection of a micellar surfactant solution to lower interfacial tension (IFT) to ultralow levels, lower than 10−3 mN/m. Ideally, microemulsions are formed during micellar-polymer flooding which help to solubilize and transport residual crude oil. This reduction in the interfacial tension reduces the capillary forces which trap residual oil in place in porous media, making displacement of the oil easier.

The potential of Bacillus licheniformis strains for in situ enhanced oil recovery

The ability of microorganisms isolated from oil reservoirs to increase oil recovery by in situ growth and metabolism following the injection of laboratory grown microbial cells and nutrients were studied. Four strains isolated from Northern German oil reservoirs at depths of 866 to 1520 m, and identified as Bacillus licheniformis, were characterized taxonomically and physiologically. All strains grew on a variety of substrates at temperatures of up to 55°C and at salinities of up to 12% NaCl. Extracellular polymer production occurred both aerobically and anaerobically over a wide range of temperatures, pressures and salinities, though it was optimal at temperatures around 50°C and at salinities between 5 and 10% NaCl. Strain BNP29 was able to produce significant amounts of biomass, polymer, fermentation alcohols and acids in batch culture experiments under simulated reservoir conditions. Oil recovery (core flooding) experiments with strain BNP29 and a sucrose-based nutrient were performed with lime-free and lime-containing, oil-bearing sandstone cores. Oil recovery efficiencies varied from 9.3 to 22.1% of the water flood residual oil saturation. Biogenic acid production that accompanied oil production, along with selective plugging, are important mechanisms leading to increased oil recovery, presumably through resulting changes in rock porosity and alteration of wettability. These data show that strain BNP29 exhibits potential for the development of enhanced oil recovery processes.

Liberation of Solution Gas During Pressure Depletion of Virgin and Watered-Out Oil Reservoirs

Summary Multipurpose experimental equipment was constructed to investigate the buildup of gas saturation during depressurization of virgin and watered-out oil reservoirs at representative conditions. The measured dependencies of critical gas saturations on gas/oil interfacial tension (IFT), amount of dissolved gas, pressure-decline rate, and structure of the porous medium are discussed. In addition, experimental results indicating significant reductions of waterflood residual oil saturation (ROS) owing to the presence of a gas saturation are presented.

Comparison of Laboratory and In-Situ Measurements of Waterflood Residual Oil Saturations for the Cormorant Field

Summary Shell Expro and Koninklijke/Shell E&amp;P Laboratorium (KSEPL) have been engaged in a multidisciplinary effort to deter mine the waterflood residual oil saturation (ROS) in two principal reservoirs of the Cormorant oil field in the U.K. sector of the North Sea. Data acquisition included special coring and testing. The study, which involved new reservoir-engineering and petrophysical tech niques, was aimed at establishing consistent ROS values. Reservoir-engineering work centered on reservoir-condition corefloods in the relative-permeability-at-reservoir-conditions (REPARC) apparatus, in which restoration of representative wettability conditions was attempted with the aging technique. Aging results in a con sistent reduction of water-wetness of all core samples. The study indicated that ROS values obtained on aged cores at water throughputs of at least 5 PV represented reservoir conditions. The petrophysical part of the study involved ROS estimation from sponge-core analy sis and log evaluation.

Volumetric Balance Method To Monitor Field Performance Of Gas-Miscible Floods

Abstract A methodology has been developed for quantitatively evaluating (1) the flow distribution of the injected solvent toward producer wells, and (2) the solvent-swept volume between each injector producer well pair from injection-production data. At a steady-stale hydrocarbon production, the production rate reflects the solvent flow- rate to the producer. At the same time, the volumetric balance between cumulative solvent injected and cumulative hydrocarbon production from the producer reflects the volume swept by the solvent. An application of the method to the hydrocarbon miscible flood in Judy Creek ‘A’ Pool yielded data on the solvent-swept volumes which are consistent with the gravity override theory. Introduction Since the hydrocarbon miscible flood was started in Judy Creek A Pool(1) in May 1985, production performance has indicated that the gravity override by the solvent is affecting solvent conformance. This conclusion is substantiated by a comparison between injection logs and production logs; i.e. although solvent injections are reasonably uniform down to the lowest perforated zones, solvent production occurs only at the top of the uppermost geological zones. Although such qualitative evidence or gravity override abounds, no adequate technique has been available for quantitative estimation of the solvent swept volume based on field data. For the purpose of evaluating the performance of gas-miscible floods at sufficiently early stages, the "Volumetric Balance Method" was developed to determine the solvent distribution and the solvent-swept volume for each injector-producer pair from field injection-production data. This paper describes the basic principle of the "Volumetric Balance Method ", potential problems and their remedies in applying the method to field operating conditions, and actual field examples. Although Field application examples or the technique in the Judy Creek hydrocarbon miscible flood project are used, the technique is also applicable to CO2 miscible floods. Volumetric Balance Method Basic Principle Let us assume that in a reservoir (schematically shown in Fig. 1) Injector I is supplying injected fluids toward Producer P as well as toward other directions. Solvent and water injection was started at Injector I upon completion or waterflood, i,e. the reservoir was assumed to retain only the residual oil saturation after waterflood (Sorw). It is assumed that the solvent flow rate (qP toward Producer P is a fraction (f) of the total solvent injection rate (qI) at Injector I and that the solvent-swept pore volume toward Producer P is VS. The swept volumes would be determined by factors such as reservoir size, continuity and gravity override. Figure 1 depicts the case of gravity override. During the solvent flood, the swept pore volume (VS) has a non-aqueous phase saturation (Sso; solvent and oil combined) which depends on fractional flow conditions and is higher than the initial waterflood residual oil saturation (Sorw). If piston-like displacement were considered, the non-aqueous phase saturation (Sso) would reach the Producer P and production or tertiary oil would start when the volume of injected solvent toward Producer P (QP) became equivalent to VS (Sso - Sorw). In other words, the solvent-swept pore volume (VS) would become filled with the saturation Sso.

Reply to Discussion of the 1984 Natl. Petroleum Council Studies on EOR

Reply to Discussion of the 1984 Natl. Petroleum Council Studies on EOR

Reconciliation of contradictory ros data from a Venezuelan light-oil sandstone reservoir

In the context of the Joint Maraven/Intevep/Shell Enhanced Oil Recovery Research Agreement an evaluation was made of all data available on waterflood-residual oil saturations ( ros) in the Eocene C5 sandstone reservoirs in the Horst of Block I, Lake Maracaibo. Special attention has been paid to contradictory data obtained in the same well by log evaluation, pressure coring and a single-well tracer test. It was found that the absolute values of the log-derived ros's are unreliable. The pressure core, on the other hand, has yielded the most complete and dependable information on the vertical distribution of the residual oil, while the single-well tracer test was inferred to have investigated an uncored sand unit. Widely varying ros values were also obtained from core-plug measurements, which further revealed a significant dependence on the degree of flooding. On the basis of this dependence it could be shown that the apparently conflicting in-situ ros data reflect, in all likelihood, different degrees of flooding of the relevant interval. The residual oil saturation in the N2.3 sands at the test well was concluded to vary from 23% in the well developed sands at the bottom of the unit to 35% in the poorer sands in the top half. Similar variations can be expected throughout the reservoir.

The CO2 Huff 'n' Puff Process in a Bottomwater-Drive Reservoir

Summary Two CO2 huff ‘n’ puff projects were conducted in the 4,900-ft [1495-m] Reservoir (BA) Sand Unit [4900' R(BA)SUI, Timbalier Bay field, Louisiana. This reservoir is a bottomwater-drive reservoir with a 26 degrees API [0.9-g/CM3] Oil gravity and 18% primary oil recovery. Before CO2 injection, both project wells were gas lifting more than 1,000 BFPD [160 M3/d fluid] with 99% water cuts. After CO2 injection, the production from each well increased to 200 BOPD [32 m3/d oil]. This paper discusses the CO2 huff ‘n’ puff process, specific reservoir characteristics, and project evaluation. Introduction When properly administered, the CO2 huff ‘n’ puff process provides quick payout with a low capital investment. These are important factors when oil prices are difficult to forecast. Timbalier Bay field was chosen to test the injection process because existing CO2 pipeline and facilities I would reduce the investment. The 4900' R(BA)SU was chosen for the huff ‘n’ puff because of its high residual oil saturation and relatively low API oil gravity. Process Discussion Limited references are available on the CO2 huff ‘n’ puff process despite voluminous publications on CO2 miscible and immiscible recovery. Khatib et al. summarized the evolution of immiscible CO2 injection in light and heavy crudes. Monger and Coma's research work concentrated on applying the CO2 huff ‘n’ puff process on light oils. From their laboratory work on cores at waterflood residual oil saturations and their data base of actual field test results, Monger and Coma concluded that residual oil can be displaced by the cyclic CO2 injection process. Patton et al. and Haskin and Alston have developed the only two correlations for estimating production responses from the CO2 huff ‘n’ puff process. Patton et al. defined two efficiencies to use in evaluating the success of a huff ‘n’ puff project. One efficiency is defined as the ratio of incremental oil produced to CO2 injected. This efficiency should range from 0.5 to 0. 8 STB/Mcf [2.8 × 10(-3) to 4.5 × 10(-3) stock-tank M3/M3], with a value of 1 STB/ Mcf [5.6 × 10(-3) stock-tank M3/M3] representing ideal conditions. The second efficiency is defined as the CO2 injection volume per foot of sand. This efficiency should range from 0.1 to 0.2 MMcf/ft [9.3 × 10(3) to 18.6 × 10(3) M3 /M]. Stright et al. Concluded that the cyclic process "does not appear to be a feasible recovery scheme" in a bottomwater-drive reservoir. When huff ‘n’ puff was applied, their subject reservoir was producing at much lower WOR's than the 4900' R(BA)SU project (2.19 vs. 70). The Timbalier Bay project is notable in that the incremental oil recoveries are greater than those predicted by the Patton et al. method and are recoverable from a bottomwater-drive reservoir with a low sweep efficiency. Throughout the literature is general agreement that the two principal recovery mechanisms in the immiscible CO2-injection process are oil swelling and viscosity reduction. The fractional-flow curves for the 4900' R(BA)SU illustrate how the viscosity-reduction and oil-swelling mechanisms cause production of incremental oil (Fig. 1). The procedure involved in generating these curves is as follows.The water/oil relative permeability is estimated from Stone's correlation.The Buckley-Leverett fractional flow of CO2-free oil is calculated with oil viscosity at reservoir temperature and pressure (Curve 1).The viscosity of CO2-saturated oil is estimated with Emanuel's equation.The new fractional-flow curve is calculated (Curve 2).The fractional-flow curves are overlaid. The viscosity reduction shifts the fractional-flow curve to the right, resulting in a reduced fractional flow of water for a given water saturation. Oil swelling reduces the water saturation, which also results in a decrease in the fractional flow of water. The CO2 swelling effect on the o"/CO2 mixture is estimated with the Peng-Robinson equation of state (PR-EOS). Because of the improvement in fractional-flow conditions, the reservoir is produced to a lower residual oil saturation.

An experimental investigation of hydrocarbon recovery from a porous medium by continuous steam injection

Experiments were carried out to recover oils by steam flooding a previously waterflooded core maintained at room temperature (21 °C), 71.5 °C and steam temperature (143 °C), using continuous steam injection in an unconsolidated core containing oils of different viscosity, Primol, light paraffin and heavy paraffin, under varying heat loss conditions. In an actual petroleum reservoir, the injection of steam results in heat loss situations represented by all of the conditions used in this investigation on a stage-wise basis. Results indicate that the steamflood residual oil saturation is a highly variable quantity and any estimate of it must take into account the prevailing heat losses. The overall recoveries of Primol, light paraffin and heavy paraffin were found to be 62, 31 and 65% of the waterflood residual oil saturations.