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Abstract Injection of CO2 has been used for enhanced oil recovery (EOR) in many light and medium gravity reservoirs. Consequently, sequestration of CO2 in oil reservoirs in conjunction with CO2-EOR is a method that is under consideration for reducing CO2 emissions into the atmosphere. Many oil reservoirs are underlain by an aquifer, and EOR processes often involve water-alternating-gas (WAG) processes. Proper understanding of the relative permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 injection and sequestration sites. While many measurements exist for CO2-oil systems, very few data, if any, exist for CO2-brine systems. This paper provides an analysis of brine-CO2 interfacial tension (IFT) measurements that were conducted for equilibrium brines and CO2 at reservoir conditions, and the detailed 700 MPa mercury-injection capillary pressure tests conducted on all rock samples to determine specific pore size distributions. Three sandstone and three carbonate potential sequestration zones in the Wabamun Lake area in Alberta, Canada, were evaluated, together with a caprock shale. This data set has specific application to the study of the behavior of injected CO2 in contact with bottom water or water-saturated zones that may be encountered in CO2-EOR projects, as well as for CO2 sequestration in deep saline aquifers. The analysis shows some correlation between the CO2-brine IFT, pore size distribution of the intergranular porous media and CO2-brine relative permeability. However, due to the high degree of variability in the pore system character of the different sandstone and carbonate facies tested, additional, better-controlled comparative tests are required to validate these trends. The hope is that, ultimately, compilation of more extensive datasets will allow appropriate selection of proper CO2-brine relative permeability relationships at reservoir conditions for intergranular sandstone and carbonate formations on the basis of relatively simple measurements of pore system geometry and IFT. These data will also provide a valuable tool for the estimation of CO2-brine relative permeability for the simulation and evaluation of intergranular sandstone and carbonate formations on a worldwide basis.
- North America > Canada > Alberta (0.69)
- North America > United States > Texas (0.68)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Nisku Formation (0.99)
- (5 more...)
Abstract Worldwide, carbonate oil-water transition zones contain vast amounts of producible oil. Yet, traditional approaches to open-hole formation evaluation often fail to predict how much oil should flow from them, or even the location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading mud filtrate and formation oil, to result in the following unusual yet often observed behavior:negative pressure gradients, water-like gradients significantly above the free water level, significant shifts in the measured pressure potentials between the lower and upper part of the transition zone, gradients implying an oil-density different to that which is expected. Supercharging effects are shown to be unimportant to the discussion. Both wells drilled with water based mud and oil based mud are considered. It is shown how it is usually possible to produce oil from a zone which has a water-like pressure gradient and low formation resistivity. The theory is supported by detailed analysis of examples from flow simulations, which recreate the well known field cases referred to above. Guidelines are presented on how to interpret traditional open hole pressure measurements in a carbonate oil-water transition zone to determine the free water level and the locations where oil should flow, and on how to improve on these interpretations by performing more advanced formation testing procedures, some of which are based upon new technology. Introduction Large, economically viable reserves of oil are widely thought to remain in the oil/water transition zones of limestone carbonate reservoirs around the world. Such zones can have vertical extents of significantly more than 100ft. This is perhaps not surprising given that the associated rock tends to have relatively low permeability (<20 mD). Typical open hole measurements for diagnosing such zones are pressure surveys by wireline formation testers (WFT), and formation resistivity logs, acquired in vertical and deviated wells. Typical SCAL measurements made on cores taken from such zones include characterization of the bounding imbibition and drainage capillary pressure and relative permeability curves (with associated end points). The answers being sought relate to questions such as:Where are depths of the following contacts? Some use definitions borrowed from Desbrandes and Gualdron[1]. Free Water Level, FWL (location where there is zero capillary pressure between oil and water), OWC (as depth increases below the oil zone, the location at which oil saturation becomes irreducible), SOR (as depth increases below the oil zone, the location where oil ceases to be mobile), SWI (as depth increases below the oil zone, the location where water becomes mobile). At any depth in the transition zone what is the oil saturation, Soil, what proportion (Sor_imb) of this is immobile under water imbibition, and what is the expected fractional flow of water, fw, under production? We share our experience from certain Middle East reservoirs, of the behavior to be typically expected from open hole pressure surveys which have been performed in such zones, and report that if supercharging and production/depletion effects are not major complications in the gradient interpretations, then there are two generic pressure gradients which can be observed in transition zones of homogeneous limestones. The profile of figure 1 is the most general and it is on this we focus our attention for the most of the paper. We present supporting evidence from flow simulation models that the kind of profile shown in figure 1 suggests that the transition zone is mixed wettable, with wettability decreasing from more oil wet at the top to pure water wet on or before reaching the FWL. The character is similar to the purely water-wet case described by Desbrandes and Gualdron (see figure 1 of [1] and/or figure 2 in this paper). But there are two significant variations between their case and the one of figure 1, and it is proposed that these differences relate to systematic changes in rock wettability vs depth.
- North America > United States (1.00)
- Asia > Middle East (0.93)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
Abstract Foam has been widely used as a mobility control agent for Improved Oil Recover (IOR), gas blocking and acid diversion during matrix stimulation. The prediction of foam performance relies on macroscopic modeling. Foam modeling approaches include fractional flow theories and population balance models. Traditionally, fractional foam models assume implicitly that foam is incompressible and do not account directly for the evolution of bubble population. The population balance models, instead, rely on the idea that foam mobility depends on bubble density and are more comprehensive. Yet, population balance models did not gain full acceptance thus far, because of their perceived complexity, with parameters that are hard to obtain experimentally. This paper presents an improved foam model based on a simpler but realistic foam rheology and stochastic bubble generation ideas. Physical ideas in agreement with pictures emerging from recent foam studies using X-ray computed tomography form the basis for the new model. First, we provide the conservation equations for foam motion in porous media. Then we present their analytical treatment considering several cases that are likely to exist in the laboratory and in the field. We present an analysis of quasi-incompressible foam, reconciling for the first time the population balance and fractional flow ideas. We demonstrate why fingering is likely to occur during liquid injection following foam. Then we provide a solution for the coupling of liquid drainage through foam and viscous fingering. Introduction Foam motion in granular porous media is a phenomenon of common experience with applications in various fields, including oil and gas recovery,[1–6] environmental remediation[1,4–6] and water purification.[1] The description of foam behavior in porous media relies on phenomenological modeling. The available foam models aim to capture the drastic lowering of gas mobility associated with foam development. Nevertheless, they differ on their approaches to accomplish this task. With some simplification, current foam models can be grouped in (semi-) empirical,[7] fractional flow,[8,9] population balance[10–13] and percolation or network[14–16] approaches. The emphasis of this work is on fractional flow and population balance methods. The modeling of foam using fractional flow ideas was advocated by Rossen and co-workers.[2,8,9] These authors identified foam states in so-called time-distance diagrams computed from core flow experimental data. They argued that the computation is simplified when done near the critical capillary pressure.[17] Foam fractional flow theory is based on the assumption that foam is incompressible and, therefore, is valid for cases where pressure variations remain small compared with the reference pressure. However, current fractional flow models do not account for the evolution of bubble population explicitly and therefore may lack accuracy when tackling transient foam motion.
- North America > United States > Texas (0.93)
- Asia (0.68)
Abstract We have previously proposed the "inject low and let rise" strategy of storing CO2 in deep saline aquifers. The idea is to maximize the amount of CO2 stored in immobile forms by letting CO2 rise toward the top seal of the aquifer but not reach it. The distance that the CO2 rises depends on the uniformity of the displacement front. In this paper, we address the question of whether the intrinsic instability of a buoyancy-driven immiscible displacement leads to fingering. Fingers could reach the top seal of the aquifer, leading to an accumulation of CO2 at large saturations. We study the mechanisms governing this type of displacement in a series of very fine-grid numerical simulations. Each simulation begins with a finite volume of CO2 placed at large saturation at the bottom of a two-dimensional aquifer. Boundaries are closed, so that CO2 rises and brine falls as the simulation proceeds. Several fine-scale geostatistical realizations of permeability are considered, and the effects of capillary pressure, anisotropy and dip angle are examined. In these simulations, buoyant instability has very little effect on the uniformity of the displacement front. Instead, the CO2 rises along preferential flow paths that are the consequence of spatially heterogeneous rock properties (permeability, drainage capillary pressure curve, and anisotropy). Capillary pressure broadens the lateral extent of the flow paths. If the formation beds are not horizontal, capillary pressure and anisotropy can cause the CO2 to move predominantly along the bedding plane, rather than vertically. Accurate assessment of CO2 migration after injection ends will therefore require accurate characterization of the spatial correlation of permeability in the target formation, and of the capillary pressure and relative permeability curves. Introduction Storing CO2 in deep, saline aquifers will be a key technology if society elects to limit the amount of greenhouse gases entering the atmosphere. The volumes to be stored would be prodigious, on the order of 109 tons per year [1]. In terms of volumetric flow rates through wellbores, this rate of storage is the same magnitude as the current global rate of oil production. Thus inexpensive, reliable methods of ensuring that stored CO2 remains in place will be essential. CO2 can be stored in an aquifer in four modes: as a bulk phase within a structural trap, as a residual phase trapped by capillary forces, as aqueous species dissolved in brine, and as a precipitated mineral. The latter three forms of storage are "permanent" in the sense that the CO2 will remain in the aquifer at least as long as the residence time of water in the aquifer. On the other hand CO2 held in a structural trap at large saturations (above residual) is "potentially mobile", in that it will remain trapped only as long as the seal remains intact. Storage methods that reduce the amount of potentially mobile CO2 correspondingly reduce the risk of leakage over the long term. The "inject low and let rise" strategy is one such method [2, 3]. Under typical storage conditions, CO2 is less dense than brine. If CO2 is injected only into the lower part of an aquifer, then after injection ends, buoyancy will cause CO2 to rise into the upper part of the aquifer. As it rises it will leave behind a residual phase trapped by capillary forces. By choosing the volume injected, one can prevent the CO2 from reaching the top of the aquifer. The distance that the CO2 rises depends on the uniformity of the displacement front and the saturation of CO2 behind the front. In this paper we discuss factors that control the former feature. We report on the latter in upcoming publications.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Geology > Petroleum Play Type > Conventional Play > Structural Play (0.44)
- Geology > Geological Subdiscipline > Stratigraphy (0.36)
ABSTRACT Experimental studies present the effect of horizontal and vertical fractures and well configurations on the SAGD process in a three-dimensional model using 12.4 ° and 18 °API gravity crude oils. A total of eleven runs were conducted, using a 30 cm × 30 cm × 10 cm rectangular-shaped box model. Temperature distributions, the rise and growth of the initial steam chamber were observed by using 25 thermocouples. Three different well configurations were investigated - a horizontal injection and production well pair, a vertical injection - vertical production well pair and a vertical injection - horizontal production well pair with and without fractures that provided a vertical path through the horizontal producer for 12.4 °API gravity crude oil. The effect of fracture orientation (vertical or horizontal) on steam-oil ratio (SOR) and oil recovery was studied using horizontal well pair scheme. The experimental results indicated that vertical fractures improved SAGD. Maximum oil recovery was observed during the horizontal injection - horizontal production well scheme with a fractured model, because of the favourable steam-chamber geometry. Runs showed that the location of the fractures affects the performance of the process. During the early stages of the runs, the fractured model gave significantly higher SORs than those observed in the uniform permeability reservoir. The fractures were successful in shortening the time to generate near breakthrough condition between the two wells. In this study, numerical simulation of the SAGD process is performed. The CMG-STARS thermal simulator was used to simulate the data from the present SAGD experiments for fractured reservoirs. The simulation uses a two-component (water and heavy oil) black oil, three-phase (water, heavy oil and steam) and three-dimensional numerical model. The results from the history-matched numerical simulation are found to be in reasonable agreement with those of the experiment for oil production rate, cumulative oil production, steam chamber and temperature profiles in the model. The numerical simulation using STARS has provided relatively good result for the history matching of the experimental SAGD process using with scaled reservoir model. INTRODUCTION Steam-assisted gravity drainage (SAGD) is a promising recovery process for producing heavy oils and bitumen resources. The method ensures both a stable displacement of steam and economical rates by using gravity as the driving force and a pair of horizontal wells for injection/production. In the SAGD process, this is achieved by drilling a pair of horizontal wells located at a short distance one above the other. Steam is injected into the upper well and hot fluids are produced from the lower well. This progressively creates a steam chamber, which develops by condensing steam at the chamber boundary and gives latent energy to the surrounding reservoir. Heated oil and water are drained by gravity along the chamber walls of the production well (Butler and Stephens, 1981; Joshi and Threlkeld, 1985; Joshi, 1987; Butler, 1987). Figure 1 shows a vertical section through a rising steam chamber. During the rise period, the oil production rate increases steadily until the steam chamber reaches the top of the reservoir. SAGD with horizontal wells not only offset the effect of very high viscosity by providing extended contact or by heating but also maintain the necessary drive needed to move the oil, as the reservoir becomes depleted. A steam-assisted gravity drainage process also maintains reservoir drive and allows high recoveries. However, because of their considerable heat requirements, these processes are limited in their economic use to higher quality reservoirs (Joshi, 1991). In SAGD, horizontal wells are usually employed as injectors as well as for producers although it is possible to use multiple vertical injectors (Butler, 1994). The SAGD process is characterized mainly by gravity drainage. The higher steam pressure allows shorter breakthrough time from the injection well to the production well, and higher spread rate of the steam chamber because higher-pressure drop between two wells may cause driving force for moving oil. Thus pushing effect or moving oil caused by pressure difference between two wells should be suppressed as little as possible especially for laboratory experiments with scaled model.
- North America > United States > Oklahoma (0.28)
- Asia > Middle East > Turkey (0.28)
- Asia > Middle East > Turkey > Raman Field (0.99)
- Asia > Middle East > Turkey > Kozluca Field (0.99)
Experimental Investigation of Drainage Capillary Pressure Computed From Digitized Tomographic Images
Olafuyi, Olalekan Adisa (University of New South Wales) | Sheppard, Adrian P. (Australia National University) | Arns, Christoph Hermann (Australia National University) | Sok, Robert Martin | Cinar, Yildiray (U. of New South Wales) | Knackstedt, Mark Alexander (Australia National University) | Pinczewski, Wolf Val (U. of New South Wales)
Abstract This paper presents comparisons between drainage capillary pressure curves computed directly from 3D micro-tomographic images (micro-CT) and laboratory measurements conducted on the same core samples. It is now possible to calculate a wide range of petrophysical and transport properties directly from micro-CT images or from equivalent network models extracted from these images. Capillary pressure is sensitive to rock microstructure and the comparisons presented are the first direct validation of image based computations. The measured data include centrifuge and mercury injection drainage capillary pressure for fired Berea, Bentheimer and Obernkirchner sandstones and unfired Mount Gambier carbonate. The measurements cover a wide range of porosities and permeabilities. The measurements are made on core samples with different diameters (2.5 cm, 1.5 cm, 1 cm and 0.5 cm) to assess the effect of up-scaling on capillary pressure measurements. The smallest diameter samples were also used to obtain the 3D micro-CT images. Good agreement is obtained between the experimental measurements and direct computations on 3D micro-CT images. 1. Introduction Recent advances in imaging technology now make it possible to routinely image rock microstructure in 3D at the pore scale. Coupling this with an ability to computationally predict petrophysical and multiphase flow properties directly on the 3D digitised tomographic images or on equivalent networks (digital core technology) results in a powerful tool to interpret conventionally measured core data and to extend the range of available data by examining rock fragments which cannot be tested by conventional means (sidewall cores, drill cuttings and unconsolidated or poorly consolidated rocks). A number of studies (Auzerias et al., 1996; Arns et al., 2001; Knackstedt et al., 2004) suggest that computations of permeability, formation factor and mercury injection capillary pressure on digitised image of a small rock fragments cut from a core plug are consistent with laboratory measurements performed on the same plug even though the computations and measurements are performed at significantly different scales. Micro-CT imaging is currently limited to small sample sizes; pore scale imaging on most materials requires resolutions of 3–5 microns, and image size is limited to approximately 2000 cubed---this limits the sample sizes for imaging studies to 5mm-1cm which is significantly smaller than conventional core plug scale. Moreover, computational times usually limit the computational domain used to a smaller sub-set of the imaged volume. Conventional laboratory measurements, on the other hand, are carried on core plugs and composite cores at scales several orders of magnitude larger than that for the image based computations. We investigate this scale effect by performing laboratory measurements at a number of different scales from the core plug scale down to a scale closer to that imaged using micro-CT. We limit the investigation to what are usually considered to be homogeneous or model rock types. These are the rock types normally used to validate image based calculations of a wide range of rock properties.
Abstract The critical oil (or gas) rate to avoid coning of unwanted fluids into production wells is an important design parameter. Simulation methods are useful to predict critical rates in reservoirs with complex heterogeneities and boundaries, but they are manpower intensive and prone to errors when large grid blocks are used. Current analytical methods are quick and easy to use, but their assumptions are too restrictive. Thus, there is a need for improved analytical methods that can account for well patterns and more complex boundaries, and also serve as further benchmarks for simulation. This paper makes analytical solutions more realistic by extending existing single-well analytical solutions to account for multiple wells and common no-flow and constant pressure boundary conditions. A potential function is derived to superimpose existing single well coning solutions for single- or simultaneous two-phase flow. Capillary pressure and relative permeability effects on coning are included. The only limiting assumptions are vertical equilibrium (VE) and steady-state flow. Comparisons with simulation show good agreement in predicted critical oil rates when steady state and VE are approached. VE and steady-state are approximately achieved when aspect ratios are greater than about 10. Even when aspect ratios are less than 10, the predicted critical rates are useful in that they are always conservative. The proposed analytical solutions are quick and easy to use compared to reservoir simulation and can be used in the development of downhole water-sink technology (DWS). Introduction Water or gas coning can adversely affect oil production in oil reservoirs and gas production in gas reservoirs. In oil reservoirs, a large oil rate can cause upward coning of water or downward coning of gas into the well perforations. Once gas or water is produced, the oil rate decreases and the cost of water and/or gas handling is increased. It is a common industry practice to reduce water coning in oil reservoirs by perforating vertical wells as far above the oil-water contact (OWC) as possible and to produce the wells at or below the critical oil rate. Similarly, wells are often perforated low in the oil column away from the gas-oil contact (GOC) in gas-oil reservoirs. The benefits of this practice are mixed in that limited perforations may increase the pressure gradient (the drawdown) near the well, which can exacerbate coning. There has also been success in reducing coning with polymers and gels.[1] A more recent and novel approach is to use downhole water-sink technology (DWS) where water is produced separately from the oil using dual packers.[2] The water production below the OWC may reduce upward water coning so that the oil rate can be increased. The DWS technology, however, requires a good understanding of how fluid rates affect coning, which is one of the goals of this paper. Dupuit[3] published one of the first papers on the down coning of air into aquifers. The Dupuit equation, which assumes vertical equilibrium and segregated flow, gives the steady-state relationship between the water production rate and water table elevation in the vicinity of a single wellbore. The Dupuit equation is still used today to determine the elevation of the water table when producing water to a well.[4,5] Muskat and Wyckoff,[6] who coined the term "water-coning," derived an approximate steady-state solution for two-dimensional water coning in an oil reservoir. Pirson[7] extended the Dupuit approach to estimation of critical oil rates for oil flow in a segregated gas-oil-water reservoir. Numerical simulation has also been used to estimate critical rates to avoid coning.[8–12] Although numerical simulation methods are useful, numerical dispersion can affect simulation results leading to errors in predicted critical rates. Analytical methods can provide quick first estimates of critical rates, and are independent of the grid-block size. Johns et al.[13] derived new analytical solutions of "Dupuit form" that allow for both single- and simultaneous two-phase flow that include the effect of capillary pressure and relative permeability on fluid interfaces. Their solution, however, assumed a single well in an infinite acting reservoir.
Abstract We propose an improved procedure for measuring acid numbers and illustrate the significance of the results by correlating with oil/brine interfacial properties. Introduction Chemical methods of improved oil recovery are not equally effective in all reservoirs. An important factor that can influence a project's success is crude oil composition. Since crude oils are complex mixtures, evaluation of oil composition in a way that is meaningful with respect to specific chemical recovery processes can present many problems. In particular, there is a need for improvements in acid number (AN), also known as total acid number (TAN) measurements. Acid numbers (AN) are important in evaluating crude oils for alkaline and surfactant processes, but in order to be useful, measurements must be comparable from one laboratory to another and must also capture chemically meaningful information about the crude oil. Standardization (e.g., the current ASTM recommended procedure[1]) should assist with the first requirement, that different labs be able to reproduce the AN value within some reasonable tolerance. Standardization does not, however, ensure that the measurement captures information about a crude oil that can be used to predict its interactions in chemical recovery processes. Acid number measurements attempt to characterize an oil with respect to concentration of strong and weak acids by means of non-aqueous potentiometric titration. The standard procedure1 is designed to measure ANs in the range of 0.05 to 250 mg KOH/g oil. Stock tank samples of crude oil usually have ANs that are at the low end of this range; strong acids are not encountered. Thus the sensitivity of the ASTM method is barely adequate for many samples of interest. According to the ASTM procedure, 20 g of oil should be used if AN is less than 1 mg KOH/g oil. Unfortunately, high quality samples of crude oil are expensive to obtain and the quantity is very limited. Using 20 g for AN measurement would often preclude making any other measurements. The usefulness of AN data is greatly increased if it forms part of a matrix of information that includes, at a minimum, base number (BN), SARA fraction data, and information about asphaltene stability. There are few, if any, interfacial phenomena that correlate exclusively to AN. Basic constituents of an oil can also be assessed by non-aqueous potentiometric titration, but end-points are often more difficult to detect because the organic bases that occur in crude oils have a wide spread of dissociation constants. More than a decade ago, Dubey and Doe[2] published recommendations for improved base number measurements by adding a known amount of quinoline to force a readily detectible titration end-point. Base numbers measured using spiked oil samples were significantly higher than those measured by the ASTM method and the higher base numbers were shown to correlate, together with AN for the same oils, with observations of wetting reversal on silica surfaces. A similar procedure was shown to improve the precision of AN titrations using stearic acid as the spiking agent for routine AN measurements.[3] Precipitated material was observed for some crude oils in the standard solvent (50% toluene, 49.5% isopropanol or IPA, and 0.5% water). Stearic acid and o-nitrophenol were used as spiking agents by Zheng and Powers.[4] No precipitation was reported in the base number solvent, methyl isobutyl ketone (MIBK),[3] which has been used as a solvent for both acidic and basic titrations.[4,5] Substitution of tetrabutyl ammonium hydroxide (TBAOH) for KOH in the titrating solution[4,6] and MIBK for IPA as the titration solvent[4] have been reported. A variety of electrodes have been tested to overcome problems with slow electrode response times in the non-aqueous environment. In this work we have used stearic acid as a spiking agent and varied solvents, titrants, and electrodes to optimize AN measurement. Experimental Materials and Methods Crude oil samples. Acid numbers have been measured for more than 250 crude oil samples. Table 1 summarizes selected properties of the xx oil samples used as examples in this paper. For each titration, a sample of 0.5 to 1.0 g of crude oil was used.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Carbonate reservoirs become more water-wet during thermal recovery. The effect of temperature on wettability-altering process is caused by contribution from several parameters involving fluid/fluid and fluid/rock interactions. This paper aims at describing the interrelationship between different parameters of a simple oil/water/rock model over temperature range of 25 to 130 degree centigrade. Saturated and unsaturated fatty acids as well as naphthenic acids with saturated and unsaturated rings are selected for this work to alter the water-wet calcite surface. The type of selected acids is based on the distribution of these components in reservoirs in the Norwegian continental shelf. Contact angle measurements on the treated calcite surfaces are used as indication of wattability alteration. At fluid/fluid interface the interfacial tension and distribution of the solutions of n-decane /fatty acids /water systems are measured at elevated temperature. A set of experiments is also performed in order to understand the role of the temperature on fluid/rock interface by zeta potential measurements. As the temperature increases, calcite surface becomes more water-wet. The obtained results at fluid/fluid interface (IFT and distribution coefficients) and contact angle measurements show that the trend of decrease in contact angles with temperature follows the same trend as IFT and distribution coefficients, specifically if one divides acids to saturated and unsaturated separately. Electro-kinetic measurements (zeta potential) of calcite surfaces with temperature demonstrate that increasing temperature reduces surface charge to less positive, which may enhance the repulsive forces between dissociated acids and calcite surface. Due to this change in surface charge, the adsorption of acids on the surface becomes less effective at high temperatures; hence wettability of the calcite surface tends to be more water-wet. Introduction The wettability of a hydrocarbon reservoir depends on how and to what extent organic components are adsorbed to the solid phase's present.[1] For carbonate reservoirs naphthenic acids and number of carboxylic acids are recognized to be the most frequent acidic components that adsorbed on the surface and altered the wettability.[2–5] The degree to which the wettability is altered by these components is determined by several parameters. Temperature is one of those controlling parameter that has an effect on both oil/water and water/mineral interfaces. Many authors have reported a shift in wettability of mineral surfaces toward water-wet at elevated temperatures.[6–9] Increasing the solubility of adsorbed materials from surfaces and decreasing the IFT are two different effects of temperature on wettability at elevated temperature.[2] Several work have directed to the partition coefficients of carboxylic acids between oil and water phase as a function of pH and salinity and to perhaps a lesser extent on the effect of temperature.[10–13]. Hamouda et al.[13] have performed an extensive experimental work on wettability alteration of calcite surfaces due to dissolved carboxylic acids in oil phase at ambient temperature and different pHs. It was shown that there is a possible implication between change in IFT and partitioning with the wettability of the calcite surfaces. They showed that the high soluble acids in water owing low partitioning coefficients hence lesser effect on IFT has minor change on wettability alteration of calcite surfaces. Increasing pH decreased the IFT between water/n-decane /fatty acid systems as well as partition coefficients of acids from oil to the water phase. Consequence of those changes resulted in decrease in contact angles on calcite surfaces. These behaviors were explained by possible increase in the repulsive forces due to dissociation of acids at water/n-decane interface hence change in the surface charge of calcite surface. Depending on the oil composition, both decreasing and in some cases increasing in IFT with the temperature were reported in literatures.[6–7,14] In terms of partition coefficients it has been shown insignificant effect by the temperature.[11,15]
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.88)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.81)
Abstract Addition of polymer has been proposed as a way to stabilize foam, especially in the presence of oil. This study probes the putative stabilizing effect of polymer on foam in terms of steady-state properties. Specifically, we tested the effect of polymer addition on the two steady-state foam regimes identified by Alvarez et al. (SPEJ, 2001). For the two polymers (xanthan and partially hydrolyzed polyacrylamide), two oils (decane and 37.5º API crude oil), and an alpha-olefin sulfonate surfactant, it appears from coreflood pressure gradient that polymer destabilizes foam modestly, raising water saturation and water relative permeability. The increased viscosity of the aqueous phase with polymer counteracts the effects of destabilization of foam. For the same polymers and surfactant, polymer does not stabilize foam in the presence of decane or 37.5º API crude oil relative to foam without polymer. Surface-tension measurements with these polymers and surfactant likewise showed no evidence of presence of polymer at the air-water interface that might stabilize foam lamellae between bubbles. This suggests that, for similar polymers and surfactants, addition of polymer would not give stronger foam in field application or stabilize foam against the presence of crude oil. Complex behavior, some of it in contradiction to the expected two steady-state foam regimes, was observed. At the limit of, or in the place of, the high-quality regime, there was sometimes an abrupt jump upwards in pressure gradient as though from hysteresis and a change of state. In the low-quality regime, pressure gradient was not independent of liquid superficial velocity, but decreased with increasing liquid superficial velocity, as previously reported and explained by Kim et al. (SPEJ, 2005). Introduction Foam is a dispersion of gas in liquid stabilized by surfactant. It is used for mobility control in EOR (Rossen, 1996), acid diversion in well stimulation (Gdanski, 1993; Rossen and Wang, 1999) and recovery of wastes in environmental remediation (Hirasaki et al., 2000; Mamun et al., 2002). However, foam has a limited lifetime. One proposed solution is the use of polymer in conjunction with surfactant solution to improve foam properties. It is a familiar observation that polymer increases liquid viscosity and slows the rate of liquid drainage from bulk foam. Whether polymer stabilizes foam in porous media, where water drains rapidly from one pore to the next driven by capillary forces, not gravity, is not clear. In this paper we investigate the effect of polymer additives on the stability of foams made from AOS surfactant. Coreflood experiments have been run with both conventional and polymer-enhanced foam, without and with oil in sandpacks and Boise sandstone.
- North America > United States > Texas (0.93)
- North America > United States > Idaho > Ada County > Boise (0.27)