Endpoint Relative Permeability Research Articles

Determining CO2 /brine relative permeability and capillary threshold pressures for reservoir rocks and caprocks: Recommendations for development of standard laboratory protocols

Important parameters for the determination of fluid transport in reservoir rocks are capillary pressures and relative permeabilities for the CO2/brine system. These factors influence the plume migration, residual CO2 trapping and CO2 dissolution in the reservoir brines. CO2-brine relative permeabilities for different rock types are rare in public literature and usually adapted from mathematical relations or from more recent experimental data. The experimental data vary greatly in saturation and relative permeability endpoints, between 10 and 100%. It is necessary to reduce the uncertainty in the data range, since these parameters are sensitive and indispensable for the numerical simulation of the evolution of a CO2 plume in the subsurface. The petrophysical properties of caprocks are the limiting factor to the amount of CO2 stored in potential storage sites. The caprock sealing capacity is determined by the capillary pressure (or column height) at which the trapped fluid starts leaking through a caprock. These rocks have high capillary threshold pressures, which, combined with wettability and interfacial tension (IFT), determine the final column height that a seal can hold. Those three factors - capillary pressure, wettability and IFT - play an important role in the geological storage of CO2 in controlling the potential of CO2 moving through the seal. The capillary threshold pressures need to be determined accurately toestimate brine displacement in caprocks and hence the onset of viscous flow or leakage to the surface. Within the framework of the Carbon Capture Project (CCP3), we plan to establish standard experimental protocols with academic and/or commercial laboratories.

Two phase brine- CO2 flow experiments in synthetic and natural media

Industrial scale injection of anthropogenic carbon dioxide into the crustal lithosphere has been proposed to reduce atmospheric accumulation. Much of this injection is expected to occur in saline reservoirs. An understanding of two-phase brine- CO2 flow is necessary for predicting storage capacity, fluid migration, and injectivity in geologic reservoirs. Additionally, the chemical reactivity of the rock matrix with CO2(l) affects the transport properties of the rock. A flow system for measuring two-phase transport of CO2 and brine is presented in this paper. The system is capable of displacing brine with either liquid or supercritical CO2. Special effort was taken to circumvent capillary end-effects in these experiments. Drainage end point relative permeability of CO2 displacing brine is found to be in the range of 0.34–0.44, much lower than what is expected for a nonwetting fluid. Such low relative permeabilities would tend to decrease injectivity while increasing displacement efficiency.

Estimation of capillary pressure and relative permeability from formation-tester measurements using Design of Experiment and data-weighing inversion: Synthetic and field examples

Laboratory measurements of relative permeability and capillary pressure are seldom performed on core samples retrieved from petroleum-production wells. Reservoir engineers rely on a limited number of small core samples to characterize many of the large-scale multiphase flow petrophysical properties affecting the production and recovery of hydrocarbon fields. The question also remains whether laboratory measurements are truly representative of in-situ rock properties. Non-linear regression methods were recently proposed to estimate saturation-dependent petrophysical properties from fractional flow-rate measurements acquired with formation testers. However, such procedures are still unclear to many practicing analysts and to date have not been fully explored with either synthetic or field data.This paper presents the development and field test of a new method to estimate saturation-dependent rock properties. The two data sets considered in our examples use in-house and commercial reservoir simulators to model the processes of mud-filtrate invasion, acquisition of borehole resistivity measurements, and subsequent fluid withdrawal during formation tester sampling. Capillary pressure and relative permeability are described using the Brooks–Corey model comprised of 6 independent unknown parameters. The iterative procedure repeats itself until measurements are all honored within prescribed error bounds. As a result, the estimation method satisfactorily reconstructs the relative permeability and capillary pressure curves with minimal a-priori information. Whereas relative permeability end-points of water and oil can be readily estimated in a couple of non-linear iterations (assuming that the remaining parameters are fixed), residual and irreducible saturations add complexity to the inversion. We also investigate the use of Design of Experiment (DoE) tools to secure a reliable initial guess for nonlinear inversion and to understand the separate contributions of the various measurements to specific inversion parameters. Such information is fundamental in the design of a data-weighing scheme that selectively enhances the sensitivity of the measurements to unknown parameters during progressive steps of nonlinear inversion.

Analysis of CO2 Endpoint Relative Permeability and Injectivity by Change in Pressure, Temperature, and Phase in Saline Aquifer

Carbon dioxide capture and geological storage are considered to be imperative practical means for reducing greenhouse gas emissions into the atmosphere. Among geological formations for carbon dioxide capture and geological storage, deep saline aquifer is tracked as a key site due to its huge potential and common occurrence when compared to oil and gas reservoirs. But, the two-phase behavior of CO2 accompanied with water formation under conditions equivalent to geological storage are mostly unknown. In this study, relative permeability experiments have been conducted to measure the end-point relative permeability of CO2 and investigations have been carried out to calculate injectivity using the relative permeability. In CO2 and water system, the injectivity is the function of the CO2 endpoint relative permeability. An experimental apparatus for CO2-water relative permeability was designed and experiments were carried out under six different temperatures varying from 70°F to 120°F, while the cell pressure was varied from 500 to 1,300 psi for every respective temperature. From the results, it was evident that, in general, the endpoint relative permeability of carbon dioxide increases with decrease in viscosity ratio, while the endpoint relative permeability in the transition region between gas and supercritical decreases even with decreasing viscosity ratio. Also, based on the sensitivity studies carried out by varying pressure and temperature, it was experimentally confirmed that porous and permeable aquifers at a minimum depth of more than 800 m are the most appropriate storage sites.

Economic Optimization and Uncertainty Assessment of Commercial SAGD Operations

Abstract As SAGD is being increasingly used as a commercial technology to recover heavy oil and bitumen, it is essential to determine the most economical operating conditions for a SAGD operation by reservoir simulation. Furthermore, to support the decision-making process of a SAGD project, it is also important to quantitatively assess the uncertainty of its economicforecasts. In this paper, the application of global optimization, experimental design, response surface generation and Monte Carlo simulation techniques in the workflow of SAGD simulation studies were demonstrated with a real field case example. The field case is an infill SAGD project with two planned SAGD well pairs and eight existing primary production wells which have 5 years of primary production. A bottomwater zone is also present. Three major steps of the workflow are:history matching primary production data;optimizing SAGD performance; andquantifying uncertainty of the SAGD forecasts. Firstly, experimental design and DECE (Designed Exploration and Controlled Evolution) optimization methods were used to achieve a faster and better history match than the traditional manual history match. Secondly, SAGD performance was optimized by adjusting the steam injection rate and producer liquid withdrawal rate during different SAGD operation periods. Finally, experimental design and response surface generation techniques were applied to build a polynomial response surface through which the net present value (NPV) of the SAGD project is correlated with uncertain parameters and a SAGD design parameter. Monte Carlo simulation was then performed to quantify the uncertainty of SAGD forecasts in terms of cumulative probability distribution of the NPV at different values of the SAGD designparameter. The results show that the economics of this project are improved considerably through optimization. The optimum operating conditions obtained use a high initial steam rate and high production rate to develop the steam chamber. After the instantaneous steam-oil ratio reaches a certain value, both steam rate and production rate are lowered to prevent steam breakthrough to the bottomwater. The uncertainty of the project NPV was assessed, taking into consideration the uncertainties in high temperature relative permeability endpoints and the variation of the SAGD design parameter. Introduction Steam-assisted gravity drainage (SAGD) is a thermal oil recovery process which consists of pairs of two parallel horizontal wells drilled near the bottom of the pay(1). Typically, the length of the wells are between 500 and 1,000 m, the inter-well distance of the two parallel wells is between 5 and 10 m and inter-well pair spacing is between 90 and 120 m(2, 3). The top horizontal well is used to inject steam, while the bottom horizontal well is used to produce reservoir fluids. The steam injected from the top well rises into the formation, forming an expanding steam chamber around and above the injection well. The rising steam eventually loses its latent heat near the boundary of the steam chamber, heats the oil and allows it to drain to the bottom production well by gravity. Successful field tests have proven that SAGD is a viable technology for in situ recovery of heavy oil and bitumen(4–6).

The Application of Cutoffs in Integrated Reservoir Studies

Summary Methodologies have been developed for applying net reservoir and thence net pay cutoffs in cases of primary and waterflood depletion. The cutoffs are dynamically-conditioned to be reservoir-specific (i.e., they are tied back to a reference permeability parameter in a way that is driven by the reservoir data themselves). They also honor scale, where feasible, and are conformable with any pertinent rock-typing. For primary depletion, the Leverett equivalent circular pore diameter has been used to distinguish between reservoir and nonreservoir rock. This composite parameter can incorporate mobility for multiphase work. It is linked to a discrete core porosity under simulated reservoir conditions, so the adopted net reservoir cutoff is expressed as a limiting porosity. For waterflood depletion, an extrapolated endpoint relative permeability to oil has proved effective for the same purpose. Here, the zero endpoint relative permeability is linked to a conventional "absolute" core permeability corrected to reservoir conditions. Porosity is tied back to this limiting absolute permeability so that the net reservoir cutoff is again expressed in terms of porosity. Consequently, in both cases, the discrete porosity cutoffs have a dynamic significance. Other cutoff parameters, such as shale volume fraction and water saturation, can be tied back to these. A proposed workflow for applying dynamically-conditioned cutoffs allows data character to drive their use in integrated reservoir studies. The workflow constitutes a basis for greater technical consistency in the estimation of ultimate hydrocarbon recovery. However, the treatment is not exclusive, and other approaches to the determination of net pay will emerge as more reservoirs are considered.

Two-Phase Flow in Porous Media with Slip Boundary Condition

Flow in porous media described by Darcy’s law extended to two-phase flow using the concept of relative permeabilities k r naturally assumes a maximum value of 0 ≤ k r ≤ 1. Reports in literature and our own experimental data show endpoint relative permeabilities k r > 1. In the porous medium, the flux of the non-wetting phase is in many cases about 2-4 times higher when a small amount of the wetting phase is present. Here, we draw an analogy between k r > 1 and a slip-boundary condition for the pore scale flow. We use a model description assuming flow in capillary tubes with a slip boundary condition. This model predicts that the flux increase due to slip depends on the equivalent capillary radius of the flow channels. Our k r data specifically follows this dependence indicating that slip is a plausible explanation for the observation of k r > 1.

Dynamic Modeling of Invasion Damage and Impact on Production in Horizontal Wells

Summary We present a novel approach that combines dynamic reservoir simulations and special core tests to model the extent of invasive damage and its impact on flowback during production. A radially adaptive 3D microsimulator is used to estimate the extent and impact of filtrate invasion on near-wellbore saturation and reservoir pressure. Time-varying reservoir exposure is used to simulate the acts of drilling, tripping, completions, and workovers. Extremely fine, core-scale grids are used to capture saturation and pressure in the invasion zone. Special core tests using a specially designed core holder are conducted on the subject reservoir core. Test results are interpreted to obtain an estimate of endpoint relative permeabilities, dynamic mudcake effect on filtrate loss, and impact of solids invasion on return permeability. The saturation and pressure profiles from this model are then used as initial conditions in a sector-scale simulator to model flowback effects. Absolute-permeability damage is modeled using the core-test results as an incremental and hyperbolically recovering effect during flowback simulations. A near-wellbore fine-grid overlay is used to capture the near-wellbore effects from the microsimulator results. Several sensitivities, including initial reservoir pressure, degree of overbalance and drawdown, heterogeneity, anisotropy, and mudcake effect, are examined. Equivalent skin factors that vary with time and depth are developed to enable comparison with full-field simulations. A horizontal-well example is used to illustrate the results of the study. Results illustrate the stark and often underappreciated effects of invasive damage on flowback and, therefore, on production performance. The methods described in this work can be used in reservoir-specific studies to quantify formation damage and aid in the selection of mud types, drilling techniques, and remediation methods required to improve performance. It is hoped that this work bridges the typically empirical damage-characterization methods and dynamic reservoir simulations.

Fluid flow properties for different classes of intermediate wettability as studied by network modelling

Most clastic reservoirs display an intermediate type of wettability. Intermediate wettability covers several local wetting configurations like fractional wet and mixed-wet where the oil-wet sites could either be in the large or smaller pores. Clastic reservoirs show a large variation in fluid flow properties. A classical invasion–percolation network simulator is used to investigate properties of different intermediate wet situations. Variation in wetting properties like contact angles, process dependent contact angles, contact angle distribution, and fraction of oil wet sites are investigated. The fluid flow properties analysed in particular are residual oil saturation and normalized endpoint relative permeability. Results from network modelling have been compared to reservoir core analysis data. The network models applied are at the capillary limit, while the core flood results are clearly viscous influenced. Even though network modelling does not cover all the physics involved in fluid displacement processes, results show that data from simulations are sufficient to present trends in fluid flow properties which are comparable to experimental data.

Experimental and numerical investigation of high temperature imbibition into preferential oil-wet chalk

Spontaneous imbibition (SI) of water into the matrix blocks is believed to be a very important drive mechanism for oil recovery from naturally fractured reservoirs, including the Ekofisk field in the North Sea. This work presents SI of artificial seawater containing sulfate ions at 130 °C on outcrop chalk saturated with crude oil (plus connate water) of high acid number to render the wettability of the porous medium preferential oil-wet. The results for the SI tests show that artificial seawater containing sulfate ions is able to spontaneously imbibe into preferential oil-wet chalk (at 40 °C) due to a wettability modification process towards more water-wet conditions. No imbibibition of any water took place at 40 °C. After raising the temperature to 130 °C, a water saturation change of 28% was observed during 15 days of imbibition time on two duplicated core samples (from S wi = 24% to 52%). The SI taking place at elevated temperature is interpreted as a wettability modification process, where the sulfate ions in the imbibing water phase are assumed to play a very important role. One core sample was re-saturated with crude oil after the SI process had ceased and the relative permeability of oil and water was measured using the steady-state method. The high end-point relative permeability of water k rw ⁎ = 0.761 indicated core surface to be close to neutral wettability. The measured relative permeability curves were then utilized to generate a capillary pressure curve by history matching oil production vs. time to the oil production measured experimentally using numerical simulations. The result showed that weak capillary forces were generated as a result of the SI process. Further fine-grid simulations after magnifying the size of the core sample up to 100 times (diameter D = 350 cm and height H = 691 cm) showed that weak induced capillary forces contributed significantly to the initial oil production rate even for the largest sample investigated. This result indicated that the induced capillary forces after a wettability modifying process may have effect on field oil production rates, as the matrix blocks investigated are representative for those blocks sizes ( D = 350 cm and H = 691 cm) usually applied, when modeling fractured reservoirs by the dual-porosity scheme.

Wettability alteration by aging of a gel placed within a porous medium

Wettability has a strong impact on many oil recovery processes. However, the determination and restoration of reservoir wettability in the laboratory is still problematic, due to the difficulty in reproducing reservoir conditions. Wettability changes are usually achieved in the laboratory by aging the rock samples with selected crude oils, or by chemical treatment of the solid surfaces. The objective of this work is to study the effects of wettability alteration, by aging silica gels, placed within a porous medium, on the ability of oil and water to flow through that medium. A series of experiments was performed to visualise oil and water flow through a porous medium containing silica gel. The experiments were conducted in transparent glass models in which the flow events and the fluid distribution were clearly visible and could be recorded. To form the gel in situ, an alkyl silicate gelant was used, which is soluble in an organic phase, and which, when in contact with water, reacts to convert the water phase into a gel. The newly formed silica gel is water-wet, but when aged in paraffin, interesting changes are observed over time: the surface wettability changes to finally become oil-wet, while small cracks develop within the gel structure. The gel was placed in both strongly water-wet and oil-wet models, which, combined with the gel behaviour, generated a wide range of flow and wettability conditions, i.e., water-wet, intermediate-wet, mixed-wet and oil-wet. The visual observations are complemented by measurements of end-point relative permeabilities, allowing the demonstration of the effects of wettability upon relative permeability. The fluid distribution at pore level and the hierarchy of wetting determine the flow characteristics. The high values of both oil and water relative permeabilities correspond to the strongly wetting conditions, which agrees with the traditional description of oil–water distribution within porous media. On the other hand, the intermediate-wet case has the lower oil and water relative permeability, with the oil permeability proportional to the fraction of the surface that is oil-wet. The mixed-wet cases have intermediate oil and water permeability, but show an increase in water relative permeability as the amount of water-wet surface decreases. These results have important implications in the design and performance of wellbore gel treatments, which are used to modify water and oil flow behaviour.

The effect of sandstone microfabric upon relative permeability end points

The nuances of relative permeability curves are commonly considered to be the product of variations in pore structure and wettability. Extrapolation of the results of a few flow tests into an entire reservoir for simulation purposes assumes that wettability does not change much over most of the reservoir and that the porous microstructure is relatively random and homogeneous. However, there is an increasing body of research indicating that the distribution of porosity is never random or homogeneous. Sandstone fabrics are a mixture of close-packed domains and packing flaws. This characteristic structure imparts a characteristic structure to the pore network that, in turn, defines fluid flow behavior (both single- and multiphase). Packing flaws are zones of oversized pores and pore throats with great spatial continuity. In lithified sandstones, virtually all of the single-phase flow occurs within packing flaws. The close-packed zones have much smaller pores and pore throats, and along with microporosity, tend to retain irreducible water. Results from a variety of quartz-rich sandstone reservoirs indicate that the domainal structure of porosity exerts a major influence upon S or and S wi values observed in unsteady-state tests. The sample set is limited to quartz-rich reservoir sands with an induced water-wet condition. However, the results demonstrate the linkage between pore fabric and relative permeability end points, and may ultimately permit one to extrapolate those properties as a function of depositional fabric.

Capillary end effects in coreflood calculations

Capillary end effects in coreflood experiments, in some cases, can significantly influence the computation of end-point relative permeabilities and final saturation levels. Because capillary end effects arise from capillarity, these corrections for relative permeability and saturation can be quantified if the capillary pressure curve is known a priori. Based on Darcy's law and the relative permeability–capillary pressure relationships, we present in this paper how these corrections can be done in corefloods if the in situ saturation profile is unavailable. Under the same principle, if the in situ saturation profile of the capillary end is available, it is therefore possible to simultaneously predict both relative permeability and capillary pressure using pressure data. Such a method of prediction is presented in the paper and experimentally verified. In a reservoir-conditioned oilflood using a carbonate core sample, we obtained the capillary end information through in situ microwave monitoring, and the relative permeability and capillary pressure were predicted based on the theory. The predictions were compared with separate capillary pressure (mercury injection, porous-plate, and centrifuge) and relative permeability (steady-state) measurements. The predictions and experiments agree well with one another.

石灰岩油層の岩質キャラクタリゼーション

This paper proposes a novel method for the grouping of rock types for the successful estimation of the in-situ absolute permeability accurately and for the smooth interpolation of relative permeability endpoints which are inevitably required for reservoir simulation models. The method consists of the grouping reservoir rocks based on the concept of electrical facies in accordance with their response to the wireline log attributes. The results showed excellent matching of the estimated absolute permeability and relative permeability endpoints to the core data prior to the application of the hydraulic unit method and multi-variate regression on each data group.The individual electrical facies showed the unique petrophysical characteristics each other, and their distribution frequency in each sedimentary zonation exhibited distinguishing feature possibly reflecting the sedimentary environment.The proposed approach lead to the great success on the description of the carbonate reservoir, of which petrophysical characteristic is so complicated that accurate enough estimation of the pointwise petrophysical properties could not be obtained by simple application of the ordinary hydraulic unit method nor multi-variate regression. The methodology is totally general and is considered to be applicable for a variety of reservoirs.

Transport in sandstone: A study based on three dimensional microtomography

High resolution imaging of the microstructure of Fontainebleau sandstone allows a direct comparison between theoretical calculations and laboratory measurements. While porosity, pore‐volume‐to‐surface ratio, permeability, and end point relative permeability are well predicted by our calculations, we find that electrical resistivity and wetting phase residual saturation are both overestimated.

Water/Oil Relative Permeability Endpoints of Intermediate-Wet, Low-Permeability Rocks

Summary The relative permeability endpoints of low-permeability, intermediate-wet mudstones increased with flow rate. This was because of both a decrease in capillary end effect and an increase in capillary number. Hence, conventional analysis will incorrectly describe field behavior. We recommend an improved methodology. We imaged steady-state saturation profiles at the end of different rate floods on one sample. We analyzed these profiles, which were axially nonuniform, to obtain capillary-end-effect-corrected data for each flow rate. The saturation distributions were also radially nonuniform. We characterized core-scale heterogeneity using a miscible flow test and examined the influence of heterogeneity. We conducted long-term tests on three short samples to study the higher-capillary-number regime. These tests displayed the existence of a critical capillary number, where the water relative permeability endpoint increased dramatically. The corresponding rate was over a magnitude smaller than flow rates traditionally recommended to eliminate capillary end effects.

Fines Migration in Two-Phase Flow

Summary Fines migration is a recognized source of permeability reduction andproductivity decline in consolidated and unconsolidated cores. Previousinvestigations have shown that salinity, flow rate, pH, and temperaturesignificantly affect the process. The presence of residual oil saturation(ROS), fractional flow of oil and water, polarity of oil, and core wettabilityare other factors whose effects have not been studied systematically. Thisexperimental study investigates the effect of these factors. Both oilsaturation and the wettability condition of the core are shown to affect theextent and rate of permeability impairment significantly. Wettabilitydeterminations made from end point relative permeabilities clearly show thatoil-wet cores sustained slower and less damage than water-wet cores. Introduction Formation fines may be defined as unconfined solid particles made up of clayminerals or non-clay species deposited over geologic time or introduced duringcompletion or drilling operations. Fines are always present in sandstonereservoirs. and their migration with flowing fluids can cause permeabilityimpairment. More detailed knowledge of fines mobilization, migration, andplugging processes is necessary for a complete understanding of the problem. Toinvestigate the potential for fines migration, "water-shock"experiments are carried out. These involve a sudden change from salt to freshwater in flow through a sandstone core sample. The major factors affecting thefines-migration process are salinity, flow rate, pH. temperature, rate ofsalinity change, and adsorption of organic material from oil. In this study, additional factors that come into play when two fluid phases are present in acore are investigated. Coreflooding Apparatus Core samples (about 2.54 cm [1 in.] in diameter and 8.0 cm [3.1 in.] long)were cut along the bedding plane from blocks of Berea sandstone. The cores wereplaced in a Hassler core holder. The difference between core fluid pressure andthe confining pressure was kept at a minimum of 2.1 MPa [300 psi]. Multiplepressure taps along the length of the core were used for measuring pressuredrops across the inlet section (Section 1, 1.5 cm [0.6 in.] long), middlesection (Section 2, 5.1 cm [2 in.] long), and outlet section (Section 3, 1.7 cm[0.7 in.] long). For thin-core studies, the cores were carefully cut in slicesperpendicular to the bedding plane. Experiments on these cores were conductedby "spotting" them in epoxy. Two accumulators with internal pistonswere used for on-line storage of mineral-oil/crude-oil and brine. In this way, it was possible to avoid flowing brine or crude through the pumps. Three setsof transducers (nine transducers in all) of increasing pressure range (0 to 69,0 to 1380, and 0 to 6900 kPa [0 to 10, 0 to 200, and 0 to 1,000 psi]) were usedto monitor different sections of the core to record differential pressure withbetter accuracy. The different fluids used in the experiments were brine (3%NaCl), mineral oil (Sontex 55TM, viscosity 10.0 mPa-s at 24C [10 cp at 75F]), Crude Oil 1 (mixture of 65.0% crude oil and 35.0% toluene, viscosity 6.85 mPa-sat 24C [6.85 cp at 75F, asphaltene content 3.5%), Crude Oil 2 (viscosity 22.9mPa-s at 24C [22.9 cp at 75F], asphaltene content 6.5%). Toluene Extract 1(3.0% asphaltene). Toluene Extract 2 (6.5% asphaltene). and pentane extract. Polar pentane extracts were prepared by mixing crude oil in excess pentane, separating the lighter pentane-soluble part from the heavier pentane-insolublepart by centrifuging (at 10,000 rev/min for 20 minutes), and collecting the topfraction by decanting. The bottom fraction was recovered with toluene and isdescribed as the toluene extract. Experimental Results The experiments can be divided into the following categories:single-phase experiments,two-phase experiments with nonpolar oil,two-phase experiments with polar crude oil,two-phase experiments withpolar compound extracts,steady-state two-phase experiments, andscanning electron microscope (SEM) study. For the purpose of this discussion.the single-phase permeability ratio (PR) is the ratio of freshwaterpermeability to brine permeability. The two-phase PR is the ratio of freshwatereffective permeability to brine effective permeability. The two-phase PR(absolute) is the ratio of freshwater effective permeability to brine absolutepermeability. A damage time (DT) is defined as the PV of fresh water injectedafter which the PR remains unchanged. A particle discharge time (PDT) isexpressed as the PV's injected after which no particles were observed in theeffluent. Porosity values for the cores ranged from 19.0 to 21.0% and PV'sranged from 8.0 to 9.0 mL. except in the thin-core studies. DT ranged from 1.35to 13.0 PV. Sor, Swr, and oil recovery were also calculated. JPT P. 646⁁

Organic acids in reservoir waters—Relationship with inorganic ion composition and interactions with oil and rock

Though the existence of organic acid anions in reservoir waters is well documented, their influence on the multiphase water-rock-oil interactions is not well understood. An overview of several projects directed at some of these aspects is presented. The ionic composition of formation waters from the Norwegian Continental Shelf is analysed by multivariate data analysis to discover correlations between organic acid anion concentrations, inorganic ion composition and reservoir conditions. The effects of realistic levels of aqueous acids are investigated experimentally for migration relevant systems. The partitioning of organic acids between oil and water phases is determined, and their influence on end-point relative permeabilities and breakthrough and irreducible saturations of oil in reservoir type rocks is measured. The effects of organic acid anion levels on mineral dissolution is investigated for two types of sandstone cores, showing significant effects for a mixed sandstone.

A Fully-Automated Relative Permeameter

Abstract This paper describes an automatic relative permeameter. Problems which are encountered in operating unsteady state relative permeameters are first identified. Solutions are then offered, by describing a fully-automated relative permeameter which employs a pseudo-constant pressure flow system, a unique production mandrel design, and an innovative fractionmeter / flowmeter system. The new apparatus offers a fast and accurate method of obtaining displacement data, with direct input into a computer for data analysis. Introduction The relative permeabilities of a porousmedia to simultaneous flow of two different fluids are fundamental parameters of major importance to the study of flow in petroleum reservoirs. They are also the most difficult properties to measure in the laboratory. Superficially, the determination of relative permeabilities is straightforward. With two phases flowing through a rock sample, the pressure drop and flow rates of each phase are measured. Darcy's law in the form Equation (Available In Full Paper) where Qa is the flow rate of the Han phase, k is the absolute permeability, kar, is the relative permeability, µa is the viscosity, A is the cross-sectional area, Pa is the pressure and x is the spatial coordinate, is then used to determine kar,. The relative permeability is a function of saturation; therefore, the saturations of both phases are required for each set of flow rates. The difficulty in experimentally determining relative permeabilities lies not in the basic concept, but in the simultaneous measurement of flow rate, pressure drop and saturation. There are two methods of obtaining relative permeability data: steady state and unsteady state. Only the unsteady state method is considered in this paper. The unsteady state method is based on interpreting an immiscible displacement process. The interpretation of this displacement process to obtain relative permeability data is performed by one of two analysis techniques: application of Buckley-Leverett frontal advance theory(l) or direct computer simulation. Application of Buckley-Leverett theory requires a number of experimental restrictions. For example, the pressure drop across the sample must be sufficiently large so that capillary effects, particularly at the outlet end of the core, are negligible. This method of calculation is based on estimating the saturation of the flooding phase, and measuring the fractional flow of this phase at the outlet face of the core. In this way the relative permeability can be related to the saturation. Because the experiment is performed rapidly, these measurements are not always easy to obtain. For this reason, actual reservoir fluids are not generally used; instead, fluids with viscosities which facilitate interpretation of the experiment are employed. Direct computer simulation is a more sophisticated and more meaningful method of extracting relative permeability data from displacement experiments, particularly' for vuggy samples(2). The method is applied by assuming that relative permeability is related to saturation by means of the following expressions (for a two-phase system, a and b): Equation (Available In Full Paper) where kir is the relative permeability, kire is the end point relative permeability (kare at Sbr and kbre at Sar), Si is the saturation, Sir is the residual saturation and ni is the saturation exponent.

Effect Of Temperature On Bitumen-Water End Point Relative Permeabilities And Saturations

Abstract This paper presents the results of an investigation on the effects of temperature on end point relative permeabilities for bitumen-containing systems. End point bitumen-water relative permeabilities and saturations were measured for constant rate floods through synthetic oil sand packs subjected to overburden pressure. A procedure was developed to obtain reproducible, clean, unconsolidated sand packs having porosities and absolute permeabilities of the same order of magnitude as rich oil sands. Bitumen and water displacement experiments were performed at constant temperatures and pressures representative of steamflood conditions. End point bitumen-water relative permeabilities and saturations were found to be independent of temperature in the range of 125 °C to 250 °C. The significance of this result can be important for reservoir engineers in predicting reservoir performance relative permeabilities for specific reservoir materials could be measured at some convenient temperature and be applied to the whole temperature range to which the reservoir is subjected to. Introduction The numerical ~imulation of thermal processes requires data on relative permeabilities and their dependence on temperature. However, reliable experimental data are not readily available. Thus, relative permeability is generally treated as an adjustable parameter for the history matching of past reservoir performance. Over the last thirty years, a number of laboratory studies have published conflicting results of temperature effects on two-phase relative permeabilities in porous media. Most experiments were performed on consolidated rocks, and only a few studies used reservoir cores and crude oils. Nakornthap and Evans(1) have summarized the temperature dependence of oil-water relative permeabilities reported in the literature. The general trend indicated that the oil and water relative permeability curves shifted to higher Water saturations. Using the unsteady State method, researchers working with heterogeneous porous media and oils of low to intermediate viscosity in the temperature range of up to about 150 °C reported that residual saturations and relative permeabilities were influenced by temperature(2–4). Other researchers working in the same temperature range with homogeneous sand cores and oils of intermediate viscosity reported the contrary(5,6). The only steady State relative permeabilities measured at elevated temperature (155 °C) were reported by Lo and Mungan(7). They found that temperature affected relative permeability curves in both water-and oil-wet systems similarly to the generally reported trends(1). They also indicated that, if the viscosity ratio remained constant, relative permeability curves were independent of temperature. The objective of this study was to determine the effect of temperature on relative permeabilities and saturations under controlled conditions using well-characterized systems. Twenty-five experiments were conducted on sand packs saturated with homogenized Athabasca bitumen and deionized water. The absolute permeabilities of the packs were measured at room and experimental temperatures. End point relative permeabilities and saturations were determined in the temperature range of 125 °C to 250 °C once a steady state condition with respect to the pressure drop across the pad bad been achieved. Experimental Apparatus and Procedures Apparatus The experimental apparatus was designed to measure two-phaserelative permeabilities under isothermal conditions up to 300 °C. A schematic diagram is shown in Figure 1.