Injected Pore Volume Research Articles

The influence of salinity on the viscous instability in viscous-modified low-interfacial tension flow during surfactant–polymer flooding in heavy oil reservoirs

In this study, the effect of viscous instability at varying salinities of the displacing non-wetting phase (i.e., surfactant–polymer solution) in surfactant–polymer flooding of heavy oil reservoirs– which is a viscous-modified low-interfacial tension (IFT) flow through an initially preferential oil-wet porous medium– is quantified in the presence of the adverse mobility ratio. The dynamic mean pore-scale capillary number values are determined using two different approaches. The first approach is a Pore network approach (PNA) that excludes the viscous instability effects. The second approach is using the Viscous instability model (VIM) proposed by Peters and Flock [49] in which the concept of the wavelength of the viscous fingers is introduced. Afterwards, these two dynamic mean pore-scale capillary number values are compared to each other to highlight the effects of viscous instability at different salinity levels of the surfactant–polymer solution. The results show that including the viscous instability effects in the qualitative and quantitative evaluations of the viscous-modified low-IFT flow is vital. In particular, the viscous instability effects become more complex near the breakthrough of the displacing non-wetting phase. Furthermore, the effects of the salinity on the dynamic mean pore-scale capillary number (by excluding/excluding the viscous instability effects, i.e., from PNA and VIM, respectively), IFT, dynamic viscosity, contact angle, displacement front configuration, wavelength of the viscous fingers, dynamic values of the desaturated displaced wetting phase, breakthrough time, and the time of infinite injected pore volume is discussed in the surfactant–polymer flooding of an initially preferential oil-wet porous medium containing heavy oil.

Quantifying the Impact of Permeability Heterogeneity on Secondary-Recovery Performance

Summary An improved heterogeneity/homogeneity index is introduced that uses the shear-strain rate of the single-phase-velocity field to characterize heterogeneity and rank geological realizations in terms of their impact on secondary-recovery performance. The index is compared with the Dykstra-Parsons coefficient (Dykstra and Parsons 1950) and the dynamic Lorenz coefficient (Shook and Mitchell 2009). The results show that the index's ranking ability is preserved for miscible and immiscible displacements at different viscosity/mobility ratios. Neither the Dykstra-Parsons coefficient (Dykstra and Parsons 1950) nor the dynamic Lorenz coefficient (Shook and Mitchell 2009) can consistently discriminate between different realizations in terms of breakthrough time and oil recovery at 1 pore volume injected (PVI) for tracer flow or adverse-viscosity-ratio miscible and immiscible floods.

Pore-Scale Micro-CT Imaging: Cluster Size Distribution During Drainage and Imbibition

In the present study we investigate the size and volume distribution of n-decane clusters in a brine saturated porous glass sample by means of micro-CT imaging with pore-scale resolution. Cluster size distribution functions and cluster volumes were obtained by image analysis for a range of injected pore volumes under both imbibition and drainage conditions, and with a field of view larger than the porosity-based representative elementary volume (REV). n-decane clusters were found to be distributed in sizes greater than that of the REV, with the largest one containing between 65 and 99% of the entire non-wetting phase. The results indicate that the two-phase REV may be substantially larger than for single-phase flow and larger than the attainable field of view.

Wettability Altering Secondary Oil Recovery in Carbonate Rocks

Carbonate rocks tend to be oil-wet, leading to lower oil relative permeability and lower oil recovery in the life of a waterflood, which is about 3 pore volume (PV) injection. The goal of this work is to improve oil recovery during secondary waterflood by wettability alteration because of a surfactant addition. The effect of the surfactant is studied by contact angle measurement, spontaneous imbibition, and secondary water/surfactant flood in reservoir cores. The contact angle changes from oil-wet to intermediate-wet in the presence of 0.2 wt % of a surfactant. Brine (without surfactant) does not imbibe into the core spontaneously, but surfactant brine imbibes to the extent of 20% of the oil in place. Secondary waterflooding recovers about 62% of the oil in about 3 PV injection and 80% in about 16 PV. Secondary surfactant flooding recovers about 85% in about 3 PV and about 90% in 4 PV. Injection of 1 PV of surfactant solution followed by waterflood also recovers about 83% of the oil in a total injection of 3 PV. This increase in oil recovery from 62 to 85% by wettability alteration is very significant and needs to be evaluated at the field scale.

Experimental Study of Solvent Flooding to Heavy Oil in Fractured Five-Spot Micro-Models: The Role of Fracture Geometrical Characteristics

Abstract The solvent-based process appears to be an increasingly feasible technology for the extraction of heavy oil reserves. However, there is a lack of fundamental understanding of how fracture geometrical characteristics control the oil recovery efficiency in this type of enhanced oil recovery (EOR) technique. In this work, a series of experiments were performed whereby the pure and mixed hydrocarbon solvents (HCS) displaced heavy oil in fractured five-spot glass micro-models. Successive images of the solvent injection process were recorded. The oil recovery factor, as a function of injected pore volume of solvents, was measured using image analysis of the provided pictures. It has been observed that the oil recovery decreased when the fractures' spacing, discontinuity, overlap, and distribution increased. In contrast, the oil recovery increased when the orientation angle, discontinuity-distribution and the number of fractures increased. Also, it has been found that there is an optimum solvent composition, which maximizes the oil recovery. Finally, some pore-level visualization representing the role of asphaltene precipitation during miscible injection was illustrated using these experiments. This study demonstrates the applicability of the micro-models for the fundamental studying of the solvent-based process in fractured five-spot systems, which are used to investigate the effect of fracture geometrical characteristics and their effect on oil recovery. Introduction Heavy oil and bitumen reserves represent a considerable portion of worldwide energy resources. It is estimated that these reservoirs contain six trillion barrels of oil originally in place (OOIP), which is much more than the total conventional oil reservoirs. Great consumption of light oil reserves and their resulting dramatic decline encourages more interest in exploitation of highly viscous oil and bitumen for future energy demands. For optimum conditions, the primary recovery of these reservoirs would not exceed 10% of the OOIP(1). A variety of thermal methods, including cyclic steam stimulation, in-situ combustion and steam assisted gravity drainage are currently being applied for extraction of these crudes. As far as the reservoir's oil is heated, the main fraction of thermal energy is used up in heating the formation itself. For the reservoirs with a thin pay zone, bottom water zone and/or overlying gas zone, excessive depths, low thermal conductivity of rock matrix, high water saturation, etc., the economical applicability of thermal methods is doubtful. With respect to current available recovery technologies, these reservoirs are categorized as problematic reservoirs(2,3).

Research of Improving Water Injection Effect by Using Active SiO<sub>2</sub> Nano-Powder in the Low-Permeability Oilfield

SiO2 nano-powder is a new type of augmented injection agent, has the ability of stronger hydrophobicity and lipophilicity, and can be adsorbed on the rock surface so that it changes the rock wettability. It can expand the pore radius effectively, reduce the flow resistance of injected water in the pores, enhance water permeability, reduce injection pressure and augment injection rate. Using artificial cores which simulated geologic conditions of a certain factory of Daqing oilfield, decompression and augmented injection experiments of SiO2 nano-powder were performed after waterflooding, best injection volume of SiO2 nano-powder under the low-permeability condition was selected. It has shown that SiO2 nano-powder inverted the rock wettability from hydrophilicity to hydrophobicity. Oil recovery was further enhanced after waterflooding. With the injection pore volume increasing, the recovery and decompression rate of SiO2 nano-powder displacement increased gradually. The best injected pore volume and injection concentration is respectively 0.6PV and 0.5%, the corresponding value of EOR is 6.84% and decompression rate is 52.78%. According to the field tests, it is shown that, in the low-permeability oilfield, the augmented injection technology of SiO2 nano-powder could enhance water injectivity of injection wells and reduce injection pressure. Consequently, it is an effective method to resolve injection problems for the low-permeability oilfield.

Experimental and Theoretical Study of Calcium Sulphate Precipitation in Porous Media Using Glass Micromodel

Mixing of two incompatible waters in water injection projects is usually associated with mineral scale formation and deposition in porous media. Deposition process dramatically affects the performance of water injection scenarios by reduction of porosity and mainly permeability of the rock. In this study, a series of experiments has been conducted to investigate the effect of different parameters on the gradual process of Calcium Sulphate precipitation. These include temperature, concentration of mixing brines, pressure, and flow rate. Due to the visual nature of the glass micromodel, a glass sandstone pattern with water-wet characteristics was used as porous medium to easily observe the scaling formation and distribution. In addition, tracing the movement of the solid particles is highly facilitated in this newly suggested experimental setup. The captured photos in microscopy scanning show that the deposition is initiated from the walls of the pores and throats and extend toward the middle space of porous medium and solid crystals look like chicken roost. For better understanding of the effect of any aforementioned parameter, the related permeability reduction curve versus injected pore volume of the brine solutions was plotted. The results indicated that as the temperature, brine concentration, and flow rate increase the scaling tendency increases as well. The pressure has a minor role on the process development. Deposition of CaSO4 manifests a functional form of permeability reduction due to the effect of different parameters. Therefore, an exponential functionality (correlation) was proposed which incorporates all physical parameters that affect the behavior of the system in dimensionless form. Reynolds number, scaling index, and deviation from equilibrium conditions are the backbone of this correlation. The adjustable exponents of the equation was determined and optimized by means of Genetic Algorithm optimization scheme. This meaningful correlation can also predict the core extracted data with reasonable accuracy.

Zero‐Valent Iron Emplacement in Permeable Porous Media Using Polymer Additions

AbstractAt the Hanford Site in Washington, an extensive in situ redox manipulation (ISRM) permeable reactive barrier was installed to prevent chromate from reaching the Columbia River. However, chromium has been detected in several wells, indicating a premature loss of the reductive capacity in the aquifer. One possible cause for premature chromate breakthrough is associated with the presence of high‐permeability zones in the aquifer. The potential emplacement of zero‐valent iron (Fe0) into high‐permeability Hanford sediments to enhance the barrier’s reductive capacity using shear‐thinning fluids containing polymers was investigated in three‐dimensional wedge‐shaped aquifer models. Porous media were packed in the wedge‐shaped flow cell to create either a heterogeneous layered system with a high‐permeability zone between two low‐permeability zones or a high‐permeability channel surrounded by low‐permeability materials. The injection flow rate, polymer type, polymer concentration, and injected pore volumes were determined based on preliminary short‐ and long‐column experiments. The flow cell experiments indicated that iron concentration enhancements of at least 0.6% w/w could be obtained using moderate flow rates and injection of 30 pore volumes. The aqueous pressure increased by a maximum of 25 kPa during infiltration, but a decrease in permeability was not observed. Under optimal conditions, the 0.6% amended Fe0 concentration would provide approximately 20 times the average reductive capacity that is provided by the dithionite‐reduced Fe(II) in the ISRM barrier.

Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir

Summary Secondary- and tertiary-recovery processes based on gas injection can extend the life of waterflooded reservoirs by maximizing the oil recovery. However, the injection strategy needs to be studied carefully to optimize the overall sweep efficiency. In particular, the impact of possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection, and a simultaneous water-alternating-gas (SWAG) injection. The experiments were carried out on composite cores consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were monitored continually during the hydrocarbon recovery, including the chromatographic analysis of the produced gas. The final oil recovery resulting from the three types of experiments was very good [approximately 90% original oil in place (OOIP) at surface conditions after 6 pore-volume (PV) injection] and quite similar within the expected experimental error, regardless of the sequence of gas injection. The low remaining oil saturation (ROS) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Because of the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by mobility control of the water phase. This enhances the sweep efficiency by viscous drive. A water-blocking effect was found to be negligible because it could be anticipated due to wettability consideration. The influence of the fluid description (equation of state, or EOS) and the three-phase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained with both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with seven pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model (either "geometrical construction" or Stone1) on the results was found to be small.

POROSITY AND PERMEABILITY EVOLUTION ACCOMPANYING HOT FLUID INJECTION INTO DIATOMITE

An experimental study of silica dissolution was performed to probe the evolution of permeability and porosity in siliceous diatomite during hot fluid injection such as water or steam flooding. Two competing mechanisms were identified. Silica solubility in water at elevated temperature causes rock dissolution thereby increasing permeability; however, the rock is mechanically weak leading to compression of the solid matrix during injection. Permeability and porosity can decrease at the onset of fluid flow. A laboratory flow apparatus was designed and built to examine these processes in diatomite core samples. At the core level, we measured the pressure drop as a function of time for fixed injection rates to determine permeability variation and utilized an X-ray Computerized Tomography (CT) scanner to measure in-situ porosity. At the pore level, a scanning electron microscope (SEM) was used to observe changes in pore morphology. We found that porosity decreased initially due to compaction caused by the imposed pressure drop across the core. Later, porosity increased as silica dissolved. Dissolution of the rock matrix appeared to be relatively uniform; wormholes were not observed even after tens of pore volumes of fluid injection.

Generation of stable microbubbles and their transport through porous media

Laboratory experiments were conducted to generate stable microbubbles and to measure their transport properties in porous media in order to evaluate their possible use in subsurface remediation. A mathematic model was developed as a special case of filtration theory for predicting microbubble transport in porous media. Several physical‐chemical parameters were tested, including surfactant type, surfactant concentration, generation method, and pressure. A combination of an anionic surfactant and a hydrophobic nonionic surfactant was found to yield the highest concentrations of stable microbubbles (3 × 109 bubbles mL−1) in the size range of 0.7 to 20 μm. The specific surface areas of the microbubble suspensions were in the range of 50 cm2 mL−1, and specific air volumes were >0.07 mL mL−1. For 1 pore volume of injected bubble suspension, effluent recoveries of 100, 80, and 30% were achieved from columns of coarse (415–500 μm), medium (150–212 μm), and fine (53–106 μm) sands, respectively. Effluent recovery in the fine sand column increased to 63% following a 3 pore volume injection. Microbubble generation and injection under pressure were shown to minimize microbubble loss due to gas dissolution. Results from the modeling suggest that retention of microbubbles could be adequately described by filtration theory.

The Effect of the Initial Rock Permeability on the Extent of Injectivity Reduction Due to Brine Injection Through Fractured Formation

The injectivity reduction with time is an important aspect in designing water injection projects. One of the main factors that affect the injectivity, due to particle invasion, is the matrix initial permeability. This factor had been experimentally investigated and evaluated by many researchers, but all of their experimental works were based on linear core flow tests. However, in some field injection projects, there was a much less reduction in the injectivity with time than what was predicted by the experimental models. This incompatibility was related to the induction of fractures caused by injection at a pressure higher than the formation fracturing pressure. This study was conducted to investigate experimentally the effect of the matrix initial permeability on the extent of injectivity reduction caused by brine injection through a rock matrix with a single fracture. The injected brine contained solid particles less than 6 mm or less than20 mm in size at a concentration of 9 mg/l. The early results show experimentally the huge difference in the injectivity reduction extent between flow tests carried out with closed and open fracture injection. Then, the results are presented as an injectivity index at a certain injected pore volume versus initial permeability. The slope of this relation is called reduction rate. This rate was evaluated for different cases. For the case of brine suspensions that contain small particles, the reduction rate of the injectivity index due to initial permeability variation in the case of open fracture tests was much less than that of the closed fracture tests. For the case of fracture injection of the large particles suspensions, the reduction rate was threefold higher than that of the small particles suspension. This proves that the particle size factor has an important role in determining the extent of the initial rock permeability effect on the injectivity index in fracture injection.

Permeability Modification With Sulfomethylated Resorcinol-Formaldehyde Gel System

Summary The effect of various parameters on the gelation of the resorcinol-formaldehyde (RF) system and a newly developed sulfomethylated resorcinol-formaldehyde (SMRF) system was investigated. The SMRF system was more tolerant of salinity, divalent ion content and pH than the RF system. The SMRF system was tested in laboratory core floods conducted at 41°C (106°F) using Berea sandstone cores, Baker dolomite cores and reservoir rock from the Lansing-Kansas City formation. SMRF forms strong and stable gels at temperatures between 25 and 52°C (77 and 126°F) and in the pH range between 5 and 8.0. Gel times are a function of pH, salinity, concentration of the chemical constituents and temperature, and can be controlled by appropriate adjustment of these parameters. Laboratory data describing the characteristics of the SMRF system in beaker tests are presented. The SMRF gel system has a viscosity close to water when the reactants are mixed and is easily injected into porous rock. In core tests, the gel system was injected into short cores and allowed to gel in situ. Permeability to brine after in-situ gelation was determined for each core as well as permeability after several pore volumes of brine injection. The SMRF gel system reduced the permeabilities of Berea and Baker dolomite cores by factors on the order of 10,000. The Lansing-Kansas City reservoir rock was plugged by the gel system. The SMRF gel system is one of a few gel systems that will form a gel in situ in the presence of the strong buffering that occurs when brine is injected into carbonate rock. The SMRF system has potential for treatments of carbonate matrix rock such as that found in the Lansing-Kansas City formations of central Kansas as well as the low-permeability carbonates found in the San Andres formations in west Texas.

Experimental Investigation on the Injectivity of Phenol-Formaldehyde/Polymer Gels

Summary Knowing the injectivity of a gelant (i.e., the pressure gradient required to achieve a given flow rate) enables the designer to program the rate/volume schedule of a water shutoff treatment. Bulk gelation times determined from bottle testing have been used often to estimate available pumping time, but such tests do not measure the evolution of gelant rheology as crosslinking proceeds, nor do they measure the tendency of the gelant to undergo filtration within a porous medium. These factors can affect injectivity significantly, resulting in pumping times much less than the bulk gelation time. We describe techniques for discriminating between viscosification and filtration by means of experiments in porous media, making use of multiple pore volume (PV) injection, step changes in flow rates, and in-line capillaries. Tests with phenol-formaldehyde-crosslinked polymer gelants, which possess a number of characteristics favorable to high temperature applications, show that filtration of pregel aggregates in sandpacks and cores can play the dominant role in reducing the mobility of the gelant. The filtration behavior is not universal; one gelant formulation showed no loss of mobility at all by this mechanism. When filtration does occur, it is strongly correlated to the age of the gelant (i.e., time the gelant has spent at temperature) but is relatively insensitive to the permeability of the porous medium or the presence of residual oil. The viscosity of the gelants tested evolves in similar ways in bulk and during flow in porous media.

Impact of Model Error on the Measurement of Flow Properties Needed to Describe Flow Through Porous Media

Indirect methods are commonly employed to determine the fundamental flow properties needed to describe flow through porous media. Consequently, if one or more of the postulates underlying the mathematical description of such indirect methods is invalid, significant model error can be introduced into the measured value of the flow property. In particular, this study shows that effective mobility curves that include the effect of viscous coupling between fluid phases differ significantly from those that exclude such coupling. Moreover, it is shown that the conventional effective mobilities that pertain to steady-state, cocurrent flow, steady-state, countercurrent flow and pure countercurrent imbibition differ significantly. Thus, it appears that traditional effective mobilities are not true parameters; rather, they are infinitely nonunique. In addition, it is shown that, while neglect of hydrodynamic forces introduces a small amount of model error into the pressure difference curve for cocurrent flow in unconsolidated porous media, such neglect introduces a large amount of model error into the pressure difference curve for countercurrent flow in such porous media. Moreover, such neglect makes it difficult to explain why the pressure gradients that pertain to steady-state, countercurrent flow are opposite in sign. It is shown also that improper handling of the inlet boundary condition can introduce significant model error into the analysis. This is because, if a short core is used with one of the unsteady-state methods for determining effective mobility, it may take many pore volumes of injection before the inlet saturation rises to its maximal value, which is in contradiction with the usual assumption that the inlet saturation rises immediately to its maximal value. Finally, it is pointed out that, because of differences in flow regime and scale, the effective mobilities measured in the laboratory may not be appropriate for inclusion in the data base for a reservoir-scale simulation.

Horizontal well stream function model for improved waterflood performance and evaluation

This paper describes the construction of a new streamtube numerical reservoir simulator and detailed results of recovery performances of mixed five-spot pattern waterfloods. Newly defined stream functions for horizontal wells were combined with conventional (vertical well) stream functions to implement streamtube modeling of horizontal wells in mixed pattern waterfloods. The horizontal wellbore was approximated with a finite, distributed line source in two dimensions. The new streamtube simulator was used to numerically simulate the recovery performance of horizontal wells in mixed five-spot pattern waterfloods. The numerical study encompassed a wide range of horizontal wellbore lengths as well as three magnitudes in mobility ratios.Horizontal well five-spot patterns have higher recovery performance than mixed patterns. Mixed five-spot patterns (horizontal wells used in conjunction with vertical wells in) also show accelerated recovery, but they require more pore volumes of water injected per pore volume hydrocarbon produced. Interestingly, longer horizontal wellbores require more injected pore volumes of water to displace the same amount of pore volume of hydrocarbons than shorter wellbores.Breakthrough areal sweep efficiency of mixed patterns decreased with increase in horizontal wellbore length. Nonetheless, mixed patterns with horizontal injectors and vertical producers consistently gave higher breakthrough sweep efficiencies than other patterns with vertical injectors and horizontal producers. This performance difference was considerably greater for unfavorable (M > 1) mobility ratio waterfloods than for favorable mobility ratio floods (M < 1).

A Study of Formation Damage of Selective Mineralogy Due To Bacterial Plugging

Abstract In this study we investigate the nature of formation damage due to growth of bacteria on formation minerals. The bacteria growth results in plugging the pores with consequent reduction in permeability. We performed experiments by injecting live bacteria cells through pipettes packed separately with different clay and non-clay minerals. We tested a total of eight minerals: non-clay (Quartz, Feldspar, Calcite and Olivine) and clay (Illite, Kaolinite, Calcium montmorillonitc and Sodium montmorillonite). Bacteria used for the experiment was Bacillus Cereus. A 10% Trypticasc Soy Broth (TSB) solution as a brine was passed through packed minerals, and the flow rates were recorded periodically before and after the bacteria injection. The flow pressure, temperature and the concentration of bacteria cells were held constant during these experiments. The absolute permeability of packed porous media was determined by using Darcy's equation. The pore plugging effects were analyzed using the percentage ratio of reduced absolute permeability to the initial absolute permeability versus the injection pore volume. We measured the Zeta Potential for each mineral under test before and after its interaction with bacteria. This was another way of testing the affinity of bacteria toward any particular mineral and their subsequent accumulation around that mineral in the pore space. For this purpose, we used particle micro-electrophorcsis instrument to measure the Zeta Potential of the bacteria, the minerals under test, as well as the cumulative Zeta Potential of mineral-bacteria assemblage. Permeability measurements and Zeta Potential readings indicate that the type of mineral present has a significant effect on plugging characteristics of the porous media. We detennincd that Olivine as compared with other minerals had the highest tendency to attract bacteria. The reason for this ppears to be the abundance of magnesium and iron as a nutrient source for bacteria. These studies, also, showed that both clays, Calcium and Sodium montmorillinite, carry a larger net negative charge than other clay minerals after interaction with bacteria. In order to be certain about the accuracy of the results of mineral-bacterial interaction, we measured the Optical Density of solutions as well, before and after injection of bacteria into porous column. Furthermore, we verified the growth of bacteria on the minerals through the use of Scanning Electron Microscope (SEM).

Mechanistic Study Of Carbon Dioxide Flooding Using Horizontal Wells

Abstract A finite-difference, equation-of-state, compositional simulator has been used to conduct a mechanistic study of carbon dioxide flooding using horizontal wells. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behaviour and properties of the CO2 used in these simulations are typical of those of multiple-contact-miscible (MCM) field conditions of West Texas. Although the equation-of-state MCM calculations require much more computer time, comparison with a first-contact- miscibility (FCM) displacement demonstrates the importance of the more realistic phase behaviour description since the injectivity and oil recovery were significantly different for the MCM than for the FCM simulations. All simulations were conducted using permeability fields that have been conditioned with core data taken from two wells in the field. We have compared the performance of the process using a vertical injector and a vertical producer with that using a horizontal injector and a vertical producer combination. We have also investigated the impact of CO2 slug size, skin factor, and relative permeability parameters. These studies show significant sensitivity of the tertiary injectivity of CO2 and brine to the wellbore skin factor and to relative permeability. In tight reservoirs such as that considered in this study, injectivity has a major impact on the efficiency of the process. Although the oil recovery after a given number of injected pore volumes is relatively insensitive to many of the variables investigated in this and earlier studies, the oil recovery at a fixed time such as 20 years varies tremendously since it is limited by the amount of CO2 that can be injected in this time period. This study adds significant new insights and conclusions about the feasibility of using CO2 with horizontal wells. Introduction During the last 15 years, the petroleum industry has experienced a rapid increase in the number of horizontal wells being drilled and completed because recent advances in drilling technology have resulted in substantially reduced drilling and completion costs of horizontal wells(l). Drilling cost figures compiled by Joshi(2) showed that horizontal well costs have declined from about six to eight times that of vertical well costs to about two to three times. In some cases where extensive drilling experience has been acquired, the costs of drilling horizontal wells are reported to be about the same or even lower than vertical well costs(3). Another factor contributing to the upsurge in horizontal well activity is the fact that horizontal wells can deliver two to ten times the performance of conventional wells, mainly because of their larger surface areas exposed to flow(l). Finally, horizontal wells offer solutions to the problem of producing oil or gas in reservoirs where conventional technology either fails or is uneconomic. Some examples are(l):reservoirs where conventional wells have low productivity,reservoirs with vertical fractures,oil reservoirs where recovery is limited by water or gas coning, and (4) thick continuous heavy oil and bitumen reservoirs where steam-assisted gravity drainage is practical.

Analytical Software For Pool-wide Performance Prediction of EOR Processes

Abstract In order to facilitate management of large scale gas miscible EOR projects, a software package called FAME (Forecast Analyser for Miscible EOR) has been developed based on an analytical approach. The primary role of the software is to provide pool-wide performance predictions from mechanistic displacement characteristics determined either by part-pattern numerical simulations, Of by preliminary history matching of field data. The notable features incorporated into the software are that:important flood parameters, such as pattern allocation factors, solvent distribution and sweep, are dependent on pool-wide fluid movement and pattern interactions, which in turn are dependent on the injection/production sequence of historical and planned flood operations,crucial physical mechanisms associated with the gas miscible EOR, such as gravity override, solvent and chase gas miscibility with reservoir oil, and miscible and immiscible displacement processes are adequately represented, andresults of mechanistic numerical simulations or history-matching past field data can be mimicked through variations of a small number of parameters. The software has impacted the management of the Judy Creek hydrocarbon miscible projects with the achievement of a successful history match and the provision of useful information related to flood performance. Introduction During the operation of large-scale oil recovery projects, especially in enhanced oil recovery projects such as hydrocarbon miscible floods, it is highly desirable to be able to assess the project performance. Factors of interest include pool-wide fluid movements, local fluid distribution, sweep efficiency and displacement characteristics, as well as the prediction of future performance under different operating scenarios. Numerical simulation is a powerful method to assess the compound effects of numerous crucial mechanisms involved in various enhanced oil recovery processes. However, numerical simulation models for enhanced oil recovery processes require a large number of simulation grid blocks and small rime steps in order to adequately represent the critical mechanisms. A typical example of such a mechanism is the gravity override of injected solvent in gas miscible processes which causes low sweep efficiencies of solvent as described by H. Stone(1). The solid curve in Figure 1 is the theoretical relationship between the vertical sweep efficiency and water to solvent injection ratio (WAG ratio) at the fixed total fluid rate based on the Jenkins' analytical Expression(2) derived from the Stone's vertical conformance theory. The triangles and circles are corresponding outputs of the Todd-Longstaff type numerical simulations(3) using the horizontal and vertical numbers of grids of 10 × 3 and 15 × 13, respectively. In these numerical simulations, the sweep efficiencies were determined from values of tertiary oil recovery normalized by the tertiary oil potential at the two pore volumes of solvent injection. It is apparent in Figure 1 that the number of grids of 10 × 3 is not enough and overestimating the sweep efficiency, whereas the 15 × 13 is sufficient for representing the mechanism of gravity override. In three-dimensional models, several thousand grid blocks typically are necessary for part-pattern (such as a quarter five-spot pattern) simulations, even with a uniform geology description.

Wettability And Immiscible Displacement In Pembina Cardium Sandstone

Abstract Imbibition tests, along with water floods and oilfloods, using various oils including Pembina crude oil, have been performed on Pembina Cardium sandstone core samples of homogeneous appearancess characterized by nitrogen permeabilities ranging from 3.9 md to 119 md. In the waterfloods the oil-la-water viscosity ratio was varied over the range of 0.23 to 15.2 and in the oil floods the water-lo-oil viscosity ratio ranged from 0.066 to 4.4. All the results obtained on the Pembina Cardium samples were compared with results of similar tests performed on strongly water-wet and strongly oil-wet Berea sandstone samples. The Pembina Cardium sandstone samples were found to have mixed wettability characteristics of the bicontinuous type because samples 100% saturated with brine spontaneously imbibed up to 53.4% pore volume 0/ oil, whereas oil sampler 100% saturated with oil imbibed up to 49.6% pore volume of brine. The average oil imbibition into eight samples was 40% pore volume and the average brine imbibition into six samples was 26% pore volume. Using styrene as the oil, the microscopic phase distribution after both types of imbibition, investigated by the phase immbolization technique, showed that the oil was mostly present in narrow pore crevices, whereas the water occupied most of the relatively large pore bulges. Waterfloods in Pembina Cardium core plugs of 3.9 md and 11.6 md permeability showed water breakthrough at 0.17pore volumes and 0.27pore volumes water satruation, respectively, and oil recoveries of 0.39 pore volumes in both samples after 6 to 8 pore volumes of water injection. By contrast, in the water flood of Pembina sample of 119 md permeability water breakthrough occurred at 0.44 pore volumes water saturation and a total oil recovery of 0.66 pore volumes was reached after injecting 13 pore volumes of water. The water flood and the oilflood histories of the Pembina samples display both water-wet and oil-wet characteristics. The shape of the characteristic top portion of the fractional flow curves of the Pembina samples occupies an intermediate position between the corresponding shapes of the fractional flow Clines obtained in strongly water-wet and strongly oil-wet sandstones, respectively. Toluene-methanol extraction of Pembina Cardium core plugs yielded water-wet samples with dramatically improved waterflood oil recovery efficiency. Ageing the extracted samples with Pembina crude oil resulted in mixed-wet samples with only a slight waterwet behaviour. INTRODUCTION The Pembina Cardium oilfield is the largest oilfield in Canada, covering 283 000 ha (700 000 acres) and containing estimated reserves of 1.2 billion m3 (8 billion barrels) of original oil-in-place (OOIP)(1). Expected recoveries from waterflooding are low, estimated at only 21% to 23% of OOIP. Early water breakthrough has caused declining production in many regions of the pool. Waterflooding is the main recovery method used in the Pembina reservoir with 70% of the approximately 4400 active wells being waterflooded(2,3). Although macroscopic-to-megascopic reservoir heterogeneities may drastically affect waterflood performance, oil displacement ultimately occurs at the pore level, because the oil resides in the pore spaces and it must be displaced from there in order to produce it.