Abstract Initial saturations of hydrocarbons and water, that exist in porous media, control reserves in place and, in many cases, the deliverability/recovery of these reserves. Hence, their accurate determination is essential for proper economic and reservoir engineering evaluation and optimization. Electric logging techniques are commonly used to estimate initial fluid saturations, but may suffer from problems with accurate determination of the log calibration constants for a given reservoir rock, as well as the accurate determination of in-situ water resistivity in some situations. Advanced logging techniques, such as magnetic resonance, have been used in recent years to estimate the saturation of bound and free water. The use of these techniques is increasing, but cost and other factors have limited their widespread usage. Various types of reactive tracers and other in-situ techniques for the determination of initial fluid saturations have also been used to attempt to determine initial fluid saturations with varying degrees of success. Another family of techniques, on which this paper concentrates, is the actual measurement of in-situ initial or swept zone fluid saturations on samples of appropriately obtained, preserved, handled and analyzed core material. Different coring techniques, fluids and coring procedures will be discussed, along with the relative merits and advantages/disadvantages of each. Illustration of the results of the use of various techniques will be given with respect to their cost, effectiveness and accuracy of the data generated. Introduction Initial fluid saturations, defined as the fraction of the interstitial space in a pore system occupied by oil, water and gas, are key factors in the determination of initial reserves of actual and recoverable hydrocarbons in place and dominate reservoir flow properties due to the strong influence they exhibit on relative permeability. Surprisingly, in many reservoirs, initial fluid saturations are virtually unknown or improperly measured, resulting in gross over or under estimation of oil or gas reserves in place. The improper determination of these initial saturations may also greatly affect the potential for formation damage due to phase trapping, resulting in a poor appraisal of deliverability. In some cases, improper initial saturation estimates can lead to the bypassing of potentially productive pay zones, resulting in significant lost reserves or the erroneous completion of ineffective pay and wet or no production from the completed zone. WHY IS IT IMPORTANT TO HAVE PROPER KNOWLEDGE OF INITIAL FLUID SATURATIONS Improper determination of the initial oil, water or gas saturations existing in porous media may often lead to expensive mistakes in the development of a field. In some cases, large amounts of capital are invested where minimal reserves are present or marginal flow is obtained. In other cases, viable pay is overlooked due to a perceived belief, from improper saturation evaluations, that the pay will be wet or non-productive. The hazards involved with an inadequate understanding of initial saturation conditions can generally be grouped into three categories: Poor Initial Reserves Evaluation. Oil or gas in place is based on a simple volumetric calculation of hydrocarbon volume present in the effective porosity of the system.

Abstract A fast and accurate method for the group analysis of crude oils in porous media that describes petroleum components (especially heavy fractions) has been developed NMR structure group analysis is used as the tool for the characterization of crude oils. This method is proposed as an alternative to existing complicated and laborious methods of characterization of extracted oil samples. Currently, group analysis of heavy fractions of crude oils is being investigated by means of chromatographic method such as the SARA (saturates-aromatics-resins-asphaltenes) test. These methods are usually expensive and require considerable work from qualified personnel. Furthermore, these methods cannot be used for estimating the oil components in-situ. The basis of determining crude oil components using NMR is the difference of the nuclei mobility in the different hydrocarbons during the NMR testing period A combination of solvent extraction, NMR testing and data processing gives a series of NMR terms that are then used to specify hydrocarbon mixtures and their components both in the bulk phase and in unconsolidated porous media. Introduction NMR logging tools are currently used for determining reservoir properties such as porosity 12 , permeability 1,2,3,4, , as well as mobile and immobile fluids 5,7 . Recent developments in NMR research offer tools for separating water, oil and gas from the combined NMR signal 8,9 . Very little is known about the use of NMR logging tools for the in-situ characterization of crude oils 1 . With respect to heavy oil and bitumen formations, NMR logging has not been very successful in characterizing crude oil. The reason for the lack of such success is the fact that the spectra from most of heavy oil and bitumen formations cannot be detected by the NMR logging tools. It should be noted that high field NMR technology has solved such problems in the past, but such technology cannot be used down hole. A fundamental objective of the research performed in our laboratory is to extend the use of NMR logging tools to all heavy oil and bitumen formations. To this end, the NMR characteristics of heavy oils in porous media were investigated 10,11 . The objective of our work is to isolate the oil signal from the combine NMR spectrum of the formation and then shift it towards the relaxation time range that can be detected by the conventional NMR logging tools. Once this goal is achieved, NMR logs of heavy oil and bitumen formations can become successful in the in-situ analysis of oil. This objective was accomplished in the material presented in this paper through a series of experiments that addressed the following issues: Relaxation interactions in mixtures of simple organic liquids with water. Relaxation interactions in mixtures of simple organic liquids. Relaxation interactions in mixtures of simple organic liquids with solvents. Relaxation times of conventional crude oils with and without solvents present. Relaxation times of heavy crude oils and bitumen with and without solvents present. Relaxation times of heavy crude oils and bitumen with and without solvents in unconsolidated sands and with variable connate water saturation.

Abstract Co-injection of water and bitumen into sand packs have been conducted to study the flow of emulsion in porous media. It was found that the most important factor in the formation of emulsion is the wettability of the medium. An oil wet medium is more favorable for emulsification than a correspondent water wet one. When the wettability of the sand pack was not changed, the degree of emulsification is ependent on the flow rate of water, being higher at higher rates. Considering that the initial state of the Clearwater ormation in Cold Lake is water wet, and that it may have changed over to oil wet state during the course of cyclic steam stimulation operation, the emulsification condition may be changed correspondingly. This change should have a strong impact on productivity as well. It is therefore very important to understand the effect of wettability on emulsification. Introduction Recently, Vittoratos 1 identified that a production cycle in Imperial Oil Resources Limited (lORL)'s cyclic steam timulation (CSS) operation in Cold Lake can be classified into a number of stages, one of which being a single phase emulsion production. He also argued that it was formed insitu, nd flowed through the porous media to the well bore ased on the produced fluid samples it is a water-in-oil mulsion which has a higher viscosity than bitumen. The implication of this high viscosity is that it might reduce the rate of bitumen recovery. It is, therefore, important to study he flow of emulsion in porous media. Bennion et al 2 performed a number of co-injection experiments with bitumen taken from an unspecified field and produced water into preserved core samples from the same field. Their results indicated that emulsion was produced in the co-injection experiments. The water volume fractions in the produced emulsion were between 0.1 and 0.2 at different flowing fractions. Considering that emulsion is a thermodynamically unstable entity, and that inside the undisturbed reservoir water and bitumen have geological time to phase separate, it is very likely that the initial state of the two are separated. The produced bitumen, however is always in the form of emulsion3. At some stage of movement of water and bitumen from their initial state to the well head, emulsification must have taken place. There are some believes that it could have taken place at the perforations. If, however, we accept Vittoratos 1 argument that emulsions are actually formed in the reservoir, then emulsification must have occurred during flow of the separated phases into the well bore. It is under these assumptions that we designed co-injection experiments to study the factors causing emulsification. Initially we were quite surprised that the measured volume fraction of water in the produced emulsion from these experiments was much lower than field observations. In fact for most of the experiments, the level of emulsification was so low that it was quite obvious that a single phase emulsion flow assumption as envisaged by Vittoratos, was definitely not applicable to describe the system.

Abstract We adapt methods, that have been empirically validated in the analysis or short-term traded securities, to evaluate long-term natural gas direct-sale contracts, We examine a sample contract from the perspective of the producer, and analyse it as a series of commodity forward and option contracts. The assessment of contract value is based on the gas price forecast, the volatility in that forecast, and the valuation of risk caused by that volatility. The method we present allows the gas producer to quantify these elements, and to evaluate the variety or terms encountered in natural gas direct-sale agreements, including features such as load factors and penalty charges. The analysis uses as inputs a probabilistic price forecast and a determination of a price of risk for gas prices. Once the forecast volatility is derived from the probabilistic forecast, the forward contracts imbedded in the long-term gas contract can be valued with a risk discounting model, and optional aspects can be evaluated using the Black-Scholes option pricing method. Introduction Long-term gas sales agreements with "independent power producers" (IPPs) developing gas-fired power plants or cogeneration (steam and electricity) projects provide a good illustration of contract terms and evaluation problems encountered by natural gas producers IPPs will contract a 10 to 20 year gas supply using a price structure similar to that which the electrical utilities in turn offer the IPPs for power: an initial price with fixed annual escalation. In addition, volume "load factors" are incorporated in contracts to provide volume flexibility to the purchaser for shutdowns, outages, and seasonal gas demand peaks. The problem for the producer is to determine the uncertain structure for the prices ot gas delivered over the proposed contract period, and to judge whether a proposed pricing formula and other contract features, such as volume load factors, provide adequate compensation for the long-term commitment of gas. Intuitively, producers know that the volume terms of a contract will be invoked by the buyer to his advantage, for example reducing contract lakes to minimums when spot natural gas terms are favourable. Clearly, the more volume flexibility that is in a contract, the lower the value for the producer. Unfortunately, the elect that these features have on the contract value cannot be easily determined using conventional discounting methods. The solution to these problems lies in understanding that long-term fixed-price fixed volume sale agreements have the same essential features as a series of commodity forward contracts, and that the optional volume terms (load factors) have characteristics of commodity options. Assessment of a contract must be based on the forecast of gas prices, on the price forecast volatility, and on the valuation or the risk associated with that price forecast uncertainty. Simple discounting methods may not be useful in quantifying and valuing forward prices, and are certainly not useful in the valuations of the options, which are often imbedded in contracts. However, analytical methods, used and validated in the analysis of short-term traded stock options, may be applied to this problem

Abstract Series of tests were carried out to examine the effect of several factors on the mobility of carbon dioxide/foaming agent coinjected in cores. These factors include the permeability of the porous media, the f low rate, the temperature, and the pressure. The latter two were selected so that the state of the injected carbon dioxide was varied from a gas to a liquid, to a supercritical low density fluid, and to a supercritical dense fluid. Alipal CD-128 was selected for the flow tests in oil-free cores. The mobility of the injected carbon dioxide was appreciably reduced at all the test conditions in the relatively less permeable Berea core (0.757 μm 2 ). In the more permeable glass bead packs (3.5 and 20.2 μm 2 ) the foaming agent was most effective at the supercritical test temperature and pressure (~45 ºC and 13.79 MPa). i.e. when carbon dioxide was a dense fluid. A flow rate dependency of the mobilities was observed at many test conditions: A minimum flow rate was sometimes required, presumably to generate a foam. In other cases the injection rate affected the rate at which the mobilities were reduced to their steady values but had little effect on the level of these steady values. Introduction Horizontal gas injection enhanced oil recovery schemes have two inherent disadvantages: Viscous instability and gravity override. The first is caused by the fact that the injected gas is more mobile than the reservoir oil, hence it tends to finger through the oil instead of sweeping it in a piston-like manner. Gravity override is caused by the density of the injected gas being less than that of the oil, thus the gas tends to rise over the oil and does not sweep the reservoir uniformly. Both these factors decrease the sweep efficiency of horizontal gas floods and consequently lower oil recovery. The work described in this paper is directed towards controlling injected gas mobility through the use of foams. The objectives of this research include gathering data on the mechanics of foam flow in porous media under a variety of conditions likely to be encountered during enhanced oil recovery operations. The topics discussed here include the effects of the physical state and flow rate of Injected fluids on foamed gas mobilities, and foam flow through stratified cores. The flow of foams in porous media is a topic that has recently come to prominence In the petroleum engineering community. The reason for this is the potential of using foams as mobility control and sweep improvement agents to increase the yield of oil from gas flooding operations. There are several recent reviews 1,2,3 of the various aspects of the use of foams in enhanced oil recovery. For the purpose of the present work, a quick summary will be made of the results of research efforts dealing specifically with the rheology of foam. There does not appear to be up to now a model that can quantitatively describe the rheology of foams in porous media over a wide range of conditions, but progress in this field is being made 4,5 .

Abstract The partial differential equations governing immiscible carbon dioxide drivefor moderately heavy oil have been developed for partial equilibrium among thegas, oil and water phases. Different sets of scatting criteria, based on the afore mentioned partial differential equations, have been developed. In order toconstruct scaled models with different operating conditions. A set of similarly groups are derived by dimensional and inspectional analysesfor the displacement of moderately heavy 0il by carbon dioxide with partialequilibrium. New dimensionless groups for the interface mass transferparameters were obtained. Different sets of scaling criteria are derived and Compared Introduction Immiscible CO 2 flooding for moderately heavy oil is an importantrecovery method for thin, marginal or otherwise poor heavy oil reservoirs, thatare unsuitable for thermal recovery methods. Up to now, the only high pressurescaled model for this process has been reported by Rojas (1). Farouq Ali and Rojas (2) presented carbon dioxide/brine injection strategiesfor heavy 0il recovery From thin formations. Experiments were conducted in ascaled model with Alberfeldy-Lloydminster heavy oils (1000 - 5000 mPa.sl. usinga small slug (20% hydrocarbon pore volume) of subcritical carbon dioxide in arectangular scaled model, designed to Simulate a thin format ion. They reported that the Injection of alternate slugs of carban dioxide (at 5.5MPa & 21–23 C) and brine (the WAG - Water Alternating Gas-process) yieldedthe best results: highest incremental recovery and lowest carbon dioxiderequirement. It was found that a high rather than a low WAG ratio should beused in the field. The oi1 recovery can increase up to 48% of the oil-in-place.An increase in oil viscosity caused a reduction in oil recovery and an increasein carbon dioxide requirements. Scaling of the immiscible CO 2 flooding for moderately heavy oil withpartial equilibrium among oil, gas and water phases is the aim of thispaper. LITERATURE REVIEW Background to Scaling Immiscible CO 2 Flooding A set of scaling groups were derived by Rojas (1) using dimensional andinspectional analyses for the displacement of heavy 0il by carbon dioxide andwater assuming that instantaneous equilibrium was attained in thereservoir. After relating the capillary and diffusive forces, and considering that modeland prototype have the same mortology, the same fluids, and are operated at thesame conditions of pressure and temperature the following scaling groups werecompletely satisfied Geometric factors: Mortology factor: Ratio ofgravitational to VISCOUS Forces: Water-gas ratio of slug volumes, when amoderate Injection rate for CO 2 brine floods was used. Background to the Nonequilibrium Processes When mass transfer is considered in a reservoir model. It is assumed that localinstantaneous equilibrium is attained in the reservoir under all conditions.But there is a need to consider interfacial mass transfer that occurs whencarbon dioxide is injected into a heavy 0il reservoir, since initially, theyare not in thermodynamic equilibrium, and mass transfer phenomena occur.

Abstract The introduction of the notion of pseudo-pressures allows rigorous, analytical solutions to a wide range of gas flow problems. However, in order to apply pseudo-pressure based solution techniques a number of cumbersome procedures are invoked to take reservoir pressures and convert them into pseudo-pressures. These include dimensionless cahier look up, numerical integration and regression analysis. To then convert the corresponding pseudo-pressures back to their analogous reservoir pressures, graphical and/or regression techniques need to be employed. This paper, then, examines the use of a semi-analytical approach to real gas pseudo-pressure/pressure conversion and calculations and its application to well test analysis. The semi-analytical approach to real gas pseudo-pressures allows a simple, direct and exact solution for converting pseudo-pressure to pressure and vice versa, No numerical integration, graphical or regression techniques are needed and the approach is well-suited for desktop or minicomputers. It is applicable to a wide range of reservoir pressure up to 10,000 psia and reservoir temperatures up to 460 °C. Well test analysis have then been carried out on a number of published buildup, drawdown and deliverability tests using the semi-analytical approach. Comparison have been test interpretation results using traditional pseudo-pressure calculations and analyses from the semi-analytical approach. Introduction By combining mass and momentum balances the flow of a real gas in porous media can be modeled using the following fundamental non-linear, second-order partial differential equation:<Equation Available In Full Paper> This particular form of the equation assume flow is isothermal, laminar and single-phase through a horizontal, homogeneous, porous media. Early on, only complex numerical solutions to equation 1 were possible gradients (V 2 p=0) is assumed to be constant. A chance of variable, allowing more rigorous, analytical solutions to the gas flow equation without the limiting assumptions made above, was developed by Al-Hussain. In their 1996 paper they introduced the potion of real gas pseudo-pressure, a(p), when: Equation (Available in full paper) This, in effect, allowed the variation of pressure dependent gas viscosity and super compressibility to be accommodated in analytical solutions of equation 1. That is, the assumption of constant gas viscosity or product, etc, were no longer needed for simple yet precise solution of pressure, time and space in real gas flow problems. If reservoir permeability is assumed to be independent of pressure and the definition of real gas pseudo-pressure is introduced into equation 1, a partially linearized flow equation for real gases can be obtained as follows: This equation has proven quite useful in providing closed form solutions for transience flow test and deliverability analysis. However, applications of equation for well test purposes require that pressure data be translated into real gas pseudo-pressure form. To date, three techniques have been presented that convert reservoir pressure to real gas pseudo-pressure. These included: (i) numerical integration, (ii) cable look up and interpolation, and (iii) curve fit approximations. This paper will examine briefly these existing methods of determining m(p) as a function of pressure and introduces a semi-analytical approach to the m(p)-p relationship.

Abstract Dispersion and migration of clay fines have been recognized as a source of permeability impairment and production decline in many reservoir formations. This paper discusses the results of laboratory experiments which indicate that the frequently observed permeability loss from fines movement appears to be a function of fluid dynamics in porous media. The results of the study confirm previous findings that fines movement is rate sensitive. Further, it is shown that for every reservoir rock and its gross properties, there appears to be a threshold or critical hydraulic flow rate beyond which particle movement becomes a pore-plugging problem. The onset of fines movements probably occurs before the critical rate and pore-plugging starts after the attainment of the critical rate. A careful determination of the said critical volumetric rate for each reservoir member can be used to program production operations which can be free of serious fines movement problem and productivity decline. Field tests are currently being implemented to evaluate the validity of this laboratory procedure. References and illustrations at end of paper. Introduction Reservoir rocks contain varying amounts of very small particles of loose solid materials such as quartz grains, feldspars and migratable clay minerals (authigenic kaolinite, dickite, illite). These particles which are commonly located on the interior surfaces of porous matrix are called "formation fines". Dispersion and migration of these particles have been recognized as a source of permeability impairment and production decline in many reservoir formations (1–10). The frequently observed permeability decline appears to be a function of fluid dynamics in porous media. The fluid velocity, in turn, is highly dependent upon gross properties of the reservoir rock, including wettability, pore geometry, particle morphology and interstitial fluids and their ionic environments. Prevention or control of permeability impairment induced by mechanical-hydraulic flow forces has not been seriously addressed by the industry, and hence, the necessity for this paper. The case for kaolinite and illite fines movement occasioned by high liquid velocities is examined in this study. Large field stimulation data (11–15) support the claim that millions of dollars are spent annually on "clay stabilizers" that may not offer effective control of certain fines movement problems. This paper presents the results of clay stabilization experiments which show the ineffectiveness of some chemical stabilization methodologies for kaolinite, illite and quartz fines. This paper discusses an effective method of fines movement control based on the principles of flow dynamics and proper production engineering procedures. The conclusions of this study are based on certain theoretical deductions and analysis of laboratory experimental core flow tests. These results are easily scaled to realistic field rates and serve as a strong basis for completion designs. The results of the study confirm the findings of previous researchers that fines movement and associated pore plugging are rate sensitive. For every reservoir rock, there is a threshold (critical) volumetric flow rate beyond which particle movement becomes a pore-plugging problem. This paper discusses how this rate can be established as well as how sustained production can be achieved by this simple fluid dynamics control.