Papers by George Hirasaki
Journal of Chemical Physics, Apr 28, 2018
The role of internal motions and molecular geometry on 1 H NMR relaxation times T1,2 in hydrocarb... more The role of internal motions and molecular geometry on 1 H NMR relaxation times T1,2 in hydrocarbons is investigated using MD (molecular dynamics) simulations of the autocorrelation functions for intramolecular GR(t) and intermolecular GT (t) 1 H-1 H dipole-dipole interactions arising from rotational (R) and translational (T ) diffusion, respectively. We show that molecules with increased molecular symmetry such as neopentane, benzene, and isooctane show better agreement with traditional hard-sphere models than their corresponding straight-chain n-alkane, and furthermore that spherically-symmetric neopentane agrees well with the Stokes-Einstein theory. The influence of internal motions on the dynamics and T1,2 relaxation of n-alkanes are investigated by simulating rigid n-alkanes and comparing with flexible (i.e. non-rigid) n-alkanes. Internal motions cause the rotational and translational correlation-times τR,T to get significantly shorter and the relaxation times T1,2 to get significantly longer, especially for longer-chain n-alkanes. Site-by-site simulations of 1 H's along the chains indicate significant variations in τR,T and T1,2 across the chain, especially for longer-chain n-alkanes. The extent of the stretched (i.e. multi-exponential) decay in the autocorrelation functions GR,T (t) are quantified using inverse Laplace transforms, for both rigid and flexible molecules, and on a site-by-site bases. Comparison of T1,2 measurements with the site-bysite simulations indicate that cross-relaxation (partially) averages-out the variations in τR,T and T1,2 across the chain of long-chain n-alkanes. This work also has implications on the role of nano-pore confinement on the NMR relaxation of fluids in the organic-matter pores of kerogen and bitumen.
Journal of Magnetic Resonance, Jul 1, 2003
Carr-Purcell-Meiboom-Gill (CPMG) measurements are the primary nuclear magnetic resonance (NMR) te... more Carr-Purcell-Meiboom-Gill (CPMG) measurements are the primary nuclear magnetic resonance (NMR) technique used for evaluating formation properties and reservoir fluid properties in the well logging industry and laboratory sample analysis. The estimation of bulk volume irreducible (BVI), permeability, and fluid type relies on the accurate interpretation of the spin-spin relaxation time ðT 2 Þ distribution. The interpretation is complicated when spinÕs self-diffusion in an inhomogeneous field and restricted geometry becomes dominant. The combined effects of field gradient, diffusion, and a restricted geometry are not easily evaluated analytically. We used a numerical method to evaluate the dependence of the free and restricted diffusion on the system parameters in the absence of surface relaxation, which usually can be neglected for the non-wetting fluids (e.g., oil or gas). The parameter space that defines the relaxation process is reduced to two dimensionless groups: D à and s à . Three relaxation regimes: free diffusion, localization, and motionally averaging regimes are identified in the ðlog 10 D à ; log 10 s Ã Þ domain. The hypothesis that the normalized magnetization, M M à , relaxes as a single exponential with a constant dimensionless relaxation time T à 2 is justified for most regions of the parameter space. The numerical simulation results are compared with the analytical solutions from the contour plots of T à 2 . The locations of the boundaries between different relaxation regimes, derived from equalizing length scales, are challenged by observed discrepancies between numerical and analytical solutions. After adjustment of boundaries by equalizing T à 2 , numerical simulation result and analytical solution match each other for every relaxation regime. The parameters, fluid diffusivity and pore length, can be estimated from analytical solutions in the free diffusion and motionally averaging regimes, respectively. Estimation of the parameters near the boundaries of the regimes may require numerical simulation.
Interpretation of the Change in Optimal Salinity With Overall Surfactant Concentration
Society of Petroleum Engineers Journal, Dec 1, 1982
Background. For chemical flooding formulations, optimal salinity changes with overall surfactant ... more Background. For chemical flooding formulations, optimal salinity changes with overall surfactant concentration when the phase behavior is observed in test tubes. Applying these observations to the mathematical simulator is questionable because chromatographic mechanisms during displacement through porous media result in different compositions. Purpose. This work sought the mechanism for the observed change so that calculated optimal salinity can be expressed through the appropriate intensive variable rather than overall surfactant concentration. Method. Association of the alcohol has been described by partition coefficients for distribution of the alcohol among brine, oil, and surfactant. The alcohol was isopropanol (IPA), 1-butanol (NBA), or tertiary amyl alcohol (TAA) in the systems in which they were included and was used to represent a disulfonate in the system with Petrostep® petroleum sulfonate. Association of sodium and divalent ions with surfactant has been described by the Donnan equilibrium model, which experimental observations show can be applied to microemulsions as well as to micelles. Conclusions. For the seven systems investigated, the change in optimal salinity is a function of (1) the alcohol associated with the surfactant and (2) the divalent ion fraction of the associated counterions.
Mechanisms for contact angle hysteresis and advancing contact angles
Journal of Petroleum Science and Engineering, Dec 1, 1999
Mixed-wet crude oil/brine/mineral systems typically show a large contact angle hysteresis between... more Mixed-wet crude oil/brine/mineral systems typically show a large contact angle hysteresis between the water-receding angle during primary drainage and the water-advancing angle during imbibition. Also, the water-advancing angle may have values that range from 50° to 180°. This investigation uses atomic force microscopy (AFM) to characterize mica surfaces that have first been equilibrated in 0.01 M NaCl, pH 6 brine
Study of Vuggy Carbonates using X-Ray CT Scanner and NMR
All Days, Sep 29, 2002
Most existing permeability correlations for carbonates assume that vugs do not contribute to perm... more Most existing permeability correlations for carbonates assume that vugs do not contribute to permeability. This may not always be the case, since vugs may be connected in some formations and contribute to the permeability. The objectives of this work are to identify vug connectivity by using X-ray CT scan and thin-section images of carbonates and to improve the NMR correlation for carbonates system. Six carbonate samples from Yates West Texas field were studied. Porosity and permeability of each sample were measured. The pore size distribution of these rocks is characterized by mercury porosimetry and NMR T2 measurements. Thin sections in the horizontal and vertical directions were prepared from the end pieces of the samples and were analyzed by using optical microscope. CT scanning of the core materials shows that porosity varies significantly along the core length. Some samples also show very distinct preferentially flow path, which affected the oil recovery. As revealed by the thin section analysis, the permeability of the samples studied is controlled either by the intergranular porosity or by the small channel that connects different vugs. The results of capillary pressure and NMR T2 measurement shows multimodal pore throat and pore body size distributions. The permeability is estimated by using effective medium approximation. All parameters used in effective medium approximation are derived from NMR T2 distribution by fitting with trimodal Weibull distribution. A better understanding of the contribution of vugs to permeability of carbonates is developed from this study.
International Journal of Greenhouse Gas Control, Aug 1, 2013
The alkanolamine absorption process is viewed favorably for use in the separation of carbon dioxi... more The alkanolamine absorption process is viewed favorably for use in the separation of carbon dioxide (CO 2 ) from point emission sources such as coal-fired power plants. At present, natural gas sweetening is the most important application for this technology. However, on a number of accounts such as the feed conditions of gas, its composition and process economics; natural gas sweetening and carbon capture are very different applications. Current technology is optimized toward providing a high performance for the former. As a part of this two-part study, we have used the process simulation software ProMax ® to perform a detailed analysis on the effect of stripper operating pressure on factors like reboiler energy duty, absorber and stripper column sizing and parasitic power loss. We have examined the performance of monoethanolamine (MEA), diethanolamine (DEA) and diglycolamine (DGA) which are all commercial absorbents that can be reliably modeled in ProMax ® . In part I of this study, we have analyzed the performance of strippers operated at pressures ranging from 150 kPa to 300 kPa. In this part of the study, we examine the performance of vacuum strippers operating under low vacuum at pressures of 30 kPa, 50 kPa and 75 kPa. Since vacuum strippers operate at lower temperatures than conventional stripper configurations, it is possible to use waste heat in the reboiler. In this study, we explore this possibility and consider 5 scenarios in which varying fractions of the reboiler steam are provided from waste heat sources located outside the turbine system. As with the cases presented in Part I, our comparisons of different configurations are based on energy consumption and column dimensions required for 90% CO 2 capture (separation + compression) from a 400 MW coal-fired power plant. CO 2 separated from the flue gas is compressed to a pressure of 16 MPa, typically maintained in the pipelines. On the basis of our findings, we report that vacuum stripping is an attractive alternative to conventional stripping. It is particularly attractive if significant sources of waste heat outside the turbine system can be located. We also conclude from our work that DEA and DGA have a superior performance than MEA when vacuum strippers are used. Use of vacuum strippers will certainly result in increased capital costs due to the need for larger equipment. However, in the view of potential savings in operating costs mainly by reduction in parasitic power loss; the increased capital expenditure may be justifiable.
All Days, Sep 26, 2004
This paper was selected for presentation by an SPE Program Committee following review of informat... more This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian,
Society of Petroleum Engineers Journal, Dec 1, 1970
An Electrostatic Approach to the Association of Sodium and Calcium With Surfactant Micelles
SPE reservoir engineering, Mar 1, 1986
Summary Association of sodium and calcium with surfactant micelles was measured and electrostatic... more Summary Association of sodium and calcium with surfactant micelles was measured and electrostatic models were used to interpret the experimental results. It was hypothesized that the association of calcium with micelles having sulfonate or sulfate anionic groups can be described by electrostatics alone—i.e., specific chemical associations were not considered. Interpretation of data obtained with ultrafiltration (UF) membranes that separate free electrolyte solution from micelles supports this hypothesis. Two parameters estimated for the electrostatic model were the lengths of the hydrophilic groups and the specific areas of surfactants on the surfaces of micelles. The Donnan equilibrium model was used to calculate the exchange of sodium and calcium and to make a comparison with mass-action models.
All Days, Oct 1, 2000
This paper introduces a new magnetic resonance fluid (MRF) characterization method. The MRF metho... more This paper introduces a new magnetic resonance fluid (MRF) characterization method. The MRF method is based on two key ingredients-a new microscopic constituent viscosity model (CVM) and a new multifluid relaxation model. The CVM provides a link between nuclear magnetic resonance (NMR) relaxation times and molecular diffusion coefficients in hydrocarbon mixtures such as crude oils. The multifluid relaxation model accounts for the T 2 decay of spin-echo signals that arises from intrinsic spin-spin interactions, surface relaxation, and attenuation due to molecular diffusion of fluid molecules in a magnetic field gradient. The MRF method exploits the fact that the molecular diffusion coefficients of brine, oil, and gas molecules typically have values that are well separated from one another. Thus, the diffusion attenuation of a suite of measured NMR signals contains sufficient information to allow differentiation of brine, oil, and gas. The method involves the simultaneous inversion of a suite of spin-echo measurements with the new MRF multifluid relaxation model. The application of the MRF method to magnetic resonance logging data can provide a detailed formation evaluation. The information provided includes total porosity, bulk volume of irreducible water, brine and hydrocarbon saturation, hydrocarboncorrected permeability, and oil viscosity. This paper discusses the theory underlying the CVM and validates the model by testing its predictions on hydrocarbon mixtures including live and dead crude oils. The robustness and accuracy of the multifluid inversion is demonstrated by a Monte Carlo simulation of a model carbonate rock that contains brine, oil, gas, and oil-base mud filtrate (OBMF). The MRF method is applied to suites of spin-echo measurements acquired in the laboratory on partially saturated rocks and shown to provide accurate fluid saturation and oil viscosity estimates. Since the completion of this work, field test results have shown that the MRF method provides a powerful and unique new formation evaluation tool.
Statistical analysis on parameters that affect wetting for the crude oil/brine/mica system
Journal of Petroleum Science and Engineering, Apr 1, 2002
ABSTRACT
All Days, Apr 8, 2013
An important economical factor affecting Enhanced Oil Recovery (EOR) is the adsorption of surfact... more An important economical factor affecting Enhanced Oil Recovery (EOR) is the adsorption of surfactants on the rocks. Sacrificial agents may be used to reduce the adsorption of surfactants. An alkali (traditionally, sodium carbonate or sodium hydroxide) is often used as sacrificial adsorption agent; however, sodium carbonate is not an effective sacrificial agent in the presence of anhydrite in the rocks due to the reaction between sodium carbonate and sparingly-soluble anhydrite. Therefore, it is essential to develop a sacrificial adsorption agent that can act effectively in the presence of anhydrite. In this work, sodium polyacrylate is evaluated as a sacrificial agent, and is compared to many other conventional or recentlyrecommended sacrificial agents, and has shown advantage over all of them for the case of presence of anhydrite. Some experiments have been conducted to demonstrate the ineffectiveness of sodium carbonate as sacrificial agent in the presence of anhydrite. Effect of molecular weight of sodium polyacrylate is tested, and it is found that increase in molecular weight results in decrease in adsorption of surfactant until a certain molecular weight of polyacrylate is reached after which molecular weight has no further effect on reducing adsorption of surfactant. Addition of polyacrylate was shown to reduce adsorption of a selected anionic surfactant on different outcrop minerals, including Carlpool dolomite, industrial calcite, kaolinite, Berea sandstone, and Indiana limestone. To prove the point further, application of polyacrylate was tested with two different anionic surfactants. Adsorption of polyacrylate itself is measured in the presence and absence of surfactant and showed to be independent of the presence of surfactant. The effect of concentration of divalent ions and salinity in the brine on effectiveness of sodium polyacrylate as sacrificial agent has been evaluated on different minerals/rocks. Finally, dynamic adsorption data has been presented in different concentrations of sodium polyacrylate. All these experiments demonstrate the advantage of using sodium polyacrylate as sacrificial adsorption agent for anionic surfactants even in the presence of anhydrite in the rock.
The Role of Noncondensable Gas in Steam Foams
Journal of Petroleum Technology, 1988
Summary. Field tests suggest that a steam-foam drive is more effective when nitrogen, methane. or... more Summary. Field tests suggest that a steam-foam drive is more effective when nitrogen, methane. or the like is added to the formulation. A plausible explanation is that foam lifetime is longest when transport of noncondensable gas limits mass transfer between steam bubbles. On the basis of this hypothesis, a method to estimate the amount of noncondensable gas to be included is presented. Introduction The displacement efficiencies of steam-injection processes in heavy-oil reservoirs are high, residual oil saturations in some steam-swept zones are around 10%. Their vertical and/or areal conformance. by contrast, can be poor: because gases are more mobile within pore space than liquids are, steam tends to override or to channel through oil in a formation. One way to decrease steam mobility is to inject foam-forming components along with the steam. Foam lamellae are generated in situ. Gas relative permeability is reduced and gas apparent viscosity is increased. the degree depending on the average foam bubble size inside the pore space. In laboratory studies, foams reduce steam mobility up to 40-fold. That they enhance steam drives has also been demonstrated in several field tests. By diminishing steam mobility, foam augments the viscous pressure gradient in the reservoir. Heated oil flows more readily, the steam zone expands more rapidly, and volumetric sweep improves. A steam-foam formulation must contain steam and at least one surfactant. Polymer, sodium chloride, and noncondensable gases are additives that have been tested in field operations. Polymer has been added only once. Sodium chloride, by contrast. has been used in all Shell Oil Co.'s field tests. Salt was originally included because it enabled sodium dodecylbenzene sulfonates and alpha olefin sulfonates (AOS's) to decrease steam mobility. Since then, its role in the transport of surfactants through reservoirs has also become known. Noncondensable gas has been another ingredient of steam foams. Foams whose vapor phases consist of steam alone can be generated, but their lifetimes are short. Consequently, even though a foam can control steam mobility, improve injection profiles, and recover additional oil without noncondensable gas, its efficiency is enhanced by inclusion of a material with limited solubility in water and a boiling point much lower than water's. The noncondensable gas appears to lengthen bubble lifetimes (and thus decrease average foam bubble size) by suppressing mass transfer caused by condensation and evaporation of water: this mechanism quickly destroys steam foams outside porous media. Field data that reveal how noncondensable gas affects the steam foams used to recover heavy, oils are reviewed here. Included are heretofore unpublished data acquired during Shell's steam-foam-drive pilots in the Kern River field, CA, as well as data already recounted in the literature. Collectively, these suggest that a steam foam is more effective when noncondensable gas is present. To explain these findings, mass transfer between the bubbles of a bulk steam foam is analyzed when it is limited by the transport ofenergy (condensation and evaporation of water alone).surfactant (surface elasticity effects), andnoncondensable gas. Under conditions representative of steam-foam zones in shallow reservoirs, bubble lifetime is found to be short when the transport of energy controls mass transfer. Moreover, surface elasticity is unlikely to slow the collapse of bubbles composed of pure steam, regardless of whether desorption from the gas/liquid interface or diffusion through lamellae limits the transport of surfactant. Instead, foam lifetime appears to be longest when the transport of noncondensable gas limits mass transfer. This analysis may need to be modified to describe correctly steam foams in porous media, where bubbles are supported by a solid. Nevertheless, the lower mobilities observed with noncondensable-gas-containing foams probably result because noncondensable gas increases foam stability. From this hypothesis the thermodynamics of steam bubbles is developed to show how the amount of noncondensable gas to be included can be estimated from reservoir temperature and pore size. In hot, permeable reservoirs, only small concentrations are needed. How Noncondensable Gases Affect Steam Foams Steam Foam Circulating Fluids. At Shell, steam foams were first designed to clean viscous oil wells. Experiments conducted in heated visual cells showed that steam-foam stability was increased by small amounts of N2. Without noncondensable gas, the foams were coarse-textured and thus ill-suited for lifting particles or sand aggregates. Longer-lived, finer-textured foams could be generated when N2 was incorporated. Subsequent field testing, with air as the noncondensable gas, verified these laboratory findings. During one test, the supply of aito the foam was cut off. The foam immediately collapsed to a sudsy froth that could not lift solids out of the wellbore.…
Ion Exchange With Clays in the Presence of Surfactant
Society of Petroleum Engineers Journal, Apr 1, 1982
The transport of sodium and calcium through porous media in the presence of clays and surfactant ... more The transport of sodium and calcium through porous media in the presence of clays and surfactant has been calculated. The exchange of the cations with both the clays and the surfactant micelles is assumed to result entirely from electrostatic association. The results show that a system in which the preflood, slug, and drive have the same sodium and calcium concentration can have a significant increase in the calcium concentration in the surfactant bank and a significant decrease in calcium concentration in the drive because of ion exchange. A process with a salinity gradient design can have a decrease in calcium concentration in the surfactant bank compared with the injected slug because of ion exchange.
Structural interactions in the wetting and spreading of van der Waals fluids
Journal of Adhesion Science and Technology, 1993
The structural interactions for the submonolayer of a van der Waals (vdW) fluid have been modeled... more The structural interactions for the submonolayer of a van der Waals (vdW) fluid have been modeled with the two-dimensional vdW equation of state (Hill-deBoer isotherm). The cohesion and co-area parameters can be estimated from the critical temperature and pressure of the bulk fluid. The difference in the standard state chemical potentials is estimated from the substrate/ fluid/vapor Hamaker constant calculated with the Lifshitz theory and an interaction distance of a single molecule with the substrate. For the systems studied, this interaction distance was approximately equal to the distance from a flat substrate to the middle of a molecule lying flat on the substrate. The resulting adsorption or disjoining pressure isotherm is assumed to describe the submonolayer part of the isotherm until it intersects the isotherm predicted from the Hamaker-Lifshitz theory. The composite isotherm is used to predict the equilibrium film thickness, film pressure, initial spreading coefficient, equilibrium spreading coefficient, and contact angle. Good agreement was observed for all systems with polytetrafluoroethylene (PTFE) as the substrate and for fluids which do not hydrogen-bond with water as the substrate. This agreement gives confidence that this model represents the structural interations of fluids that have only vdW interactions. It is possible to model the interaction of a monopolar liquid with a polar substrate. The acid-base component of the interaction energy from the van Oss, Chaudhury, Good theory was added to the model. With this addition, the model can predict the film pressure and spreading of benzene and chloroform on water.
Effects of Capillary Pressure on Coalescence and Phase Mobilities in Foams Flowing Through Porous Media
SPE reservoir engineering, Aug 1, 1988
Summary The stability of foam lamellae is limited by capillary pressure. Consequently, as the fra... more Summary The stability of foam lamellae is limited by capillary pressure. Consequently, as the fractional flow of gas in a foam is raised at a fixed gas velocity, the capillary pressure in a porous medium at first increases and then approaches a characteristic value, here called the "limiting capillary pressure." If the gas fractional flow is increased after the limiting capillary pressure has been attained, coalescence coarsens foam texture, the liquid saturation remains constant, and the relative gas mobility becomes proportional to the ratio of gas-to-liquid fractional flow. The limiting capillary pressure varies with the surfactant formulation, gas velocity, and permeability of the medium.
Pulse Tests and Other Early Transient Pressure Analyses for In-Situ Estimation of Vertical Permeability
Society of Petroleum Engineers Journal, Feb 1, 1974
Formation vertical permeability is often the dominant influence in water or gas coning into a wel... more Formation vertical permeability is often the dominant influence in water or gas coning into a well, in gravity drainage of high-relief reservoirs, and in interlayer crossflow in secondary recovery projects. The advantages of either conducting a projects. The advantages of either conducting a pulse test or analyzing the early transient pressure pulse test or analyzing the early transient pressure response of a constant-rate test compared with previous techniques are simplicity of interpretation, previous techniques are simplicity of interpretation, short duration of test, and minimum interference from conditions some distance from the test well. The pulse test has a further advantage over the constant-rate test in that the rate does not have to be kept constant during the short flow period. Presented are the development of the theory and the curves of the dimensionless response time used in interpreting field data obtained by these techniques. The vertical permeability is determined with the pulse test from the time to the maximum pressure response and with the constant-rate test pressure response and with the constant-rate test from the extrapolated time to zero pressure response from the inflection point. Applications of the techniques to layered systems and to an oil zone with underlying water are demonstrated with results of numerical simulations. The vertical-permeability pulse test has been used to estimate the vertical permeability of a low-permeability zone in the Fahud field, Oman. Introduction The formation vertical permeability is often a dominant influence in reservoir recovery processes with vertical fluid flow such as water or gas coning, gravity drainage of high-relief reservoirs, the rising steam process, and displacement by water or gas in a heterogeneous formation. How reliably numerical reservoir simulators can predict the recovery performance of these processes depends upon how performance of these processes depends upon how accurately the significant reservoir parameters are estimated. Furthermore, in simulating a reservoir in two dimensions, the validity of the assumption of vertical equilibrium is based on the value of the vertical permeability. With the previously mentioned recovery processes, the reservoir cannot be modeled as a homogeneous reservoir with a single fluid. A well that has fluid coning or that is producing by gravity drainage will often have a fluid contact intersecting the well and thus dividing the reservoir into zones of differing mobility and compressibility. Reservoir stratification on a microscopic scale will result in a vertical permeability that is less than the horizontal permeability that is less than the horizontal permeability; but stratification on a macroscopic permeability; but stratification on a macroscopic scale will divide the reservoir into zones of differing permeabilities. Thus the design and interpretation permeabilities. Thus the design and interpretation of a vertical-permeability test for most practical reservoir situations will require that the reservoir zonation be represented. Transient pressure techniques for estimating in-situ vertical permeability have been introduced by Burns and by Prats. Both techniques require injection or production at a constant rate from a short perforated interval and measurement of the pressure response at another perforated interval pressure response at another perforated interval that is isolated from the first by a packer. The interpretation technique of Burns required a computer-generated type curve or a single-phase numerical reservoir simulator. This type-curve approach is applicable for an anisotropic, homogeneous, infinite reservoir model, and the numerical simulator with a regression analysis program is needed for finite or layered reservoir models. The technique presented by Prats did not require a computer program because the result of the analysis was presented on a single graph. The horizontal and vertical permeabilities could be estimated from the slope and the intercept of the pressure response and, the appropriate value from the graph. The method of Prats was based on an infinite, anisotropic, Prats was based on an infinite, anisotropic, homogeneous reservoir model.The pulse test and early transient analysis techniques presented here were developed to provide a simple means of interpretation for layered provide a simple means of interpretation for layered systems.
Sensitivity Coefficients for History Matching Oil Displacement Processes
Society of Petroleum Engineers Journal, Feb 1, 1975
An improved estimate of the reservoir parameters is made during the history-matching phase of a r... more An improved estimate of the reservoir parameters is made during the history-matching phase of a reservoir simulation study by determining the set of parameters that result in the best match of the simulated performance with the observed performance. Often, the process of determining which parameters are to be adjusted is a trial-and-error process. Graphs of the sensitivity coefficients for comparing the cumulative oil recovery with the reservoir parameters are presented to determine the relative significance of parameters are presented to determine the relative significance of the parameters and to provide guidelines for the magnitude of change to the parameters. The sensitivity coefficients are based on a one-dimensional system with dip, incompressible fluids, and polynomial relative-permeability curves. The recovery efficiency can be expressed as a function of the dimensionless cumulative injection with the gravity number (gravity/viscous-forces ratio), mobility ratio, and relative-permeability exponent as parameters. The sensitivity of the cumulative oil recovery (at a given value of cumulative injection) to the movable pore volume, mobility ratio, permeability, and the exponent of the relative-permeability curve permeability, and the exponent of the relative-permeability curve can be calculated from the expression for the recovery efficiency. The graphs of the sensitivity coefficients can be used to determine the relative significance of the parameters, if a unique set of parameters can be determined, and how much they should be adjusted. parameters can be determined, and how much they should be adjusted Introduction When the simulated oil-recovery performance differs from the observed performance history, the engineer must determineif the history match is satisfactory, orif not, which reservoir parameters are to be adjusted and how much. The purpose of this parameters are to be adjusted and how much. The purpose of this discussion is to provide guidelines for the engineer in choosing the parameter(s) to be adjusted and to determine the magnitude and direction of the change. This will be accomplished by first illustrating the sensitivity of water or gas displacement performance to the reservoir parameters so that the critical parameter(s) can be identified, and then graphically presenting the magnitude of the sensitivity coefficients to determine the magnitude of change in the parameter value necessary to achieve a match. The following guidelines will be limited in scope to two-phase displacement processes with negligible interfacial mass transfer (e.g., waterflood, natural water drive, gas injection, or gas-cap expansion). Processes such as solution gas drive or vaporizing gas drive will not be presented. The results will be expressed in terms of the gross fluids produced or injected rather than time. The analysis and results are based on a one-dimensional system. Although the recovery performance of a multidimensional system will be different from that of a one-dimensional system, the relative sensitivity of the recovery performance to the parameters should not differ significantly for most recovery processes. Examples of exceptions that cannot be represented with the one-dimensional system are where well coning is significant or where permeability barriers exist between the injection well and production well. production well. The reservoir parameters that are investigated arethe movable pore volume of the displacement process, SVp;the mobility ratio of the displacing fluid to the displaced fluid, M, where the mobilities are evaluated at the maximum saturation of each phase;the permeability, which is represented as a factor in the gravity number, N(G) if the formation is dipping; andthe shape of the relative permeability curve, expressed in terms of a single parameter, n. ASSUMPTIONS AND MODEL OF THE DISPLACEMENT PROCESS The following assumptions are made about the displacement process. process.The saturations, relative permeabilities, porosity, and permeability are averaged over the reservoir thickness. permeability are averaged over the reservoir thickness.The areal displacement is modeled with a linear system. SPEJ P. 39
Energy & Fuels, Jul 29, 2009
Large quantities of natural gas hydrates are present in shallow marine sediments as well as in ar... more Large quantities of natural gas hydrates are present in shallow marine sediments as well as in arctic regions. This research is aimed at assessing production of natural gas from unconfined marine hydrate deposits. A multiphase, multicomponent, thermal, 3D simulator is used to simulate production of hydrates in the equilibrium mode. Three components (hydrate, methane, and water) and four phases (hydrate, gas, aqueous-phase, and ice) are considered in the simulator. Depressurization and warm water flooding of unconfined, horizontal and dipping reservoirs have been simulated. Production of methane from gas hydrate reservoirs depends on reservoir confinement, injection temperature, injection pressure, and production pressure. For unconfined horizontal reservoirs, depressurization is ineffective; thermal stimulation is necessary for gas production. Even warm water (temperature ≈ 30 °C) injection improves the gas production from hydrate reservoirs. Lower vertical permeability helps the gas production by heating a larger area of the reservoir for hydrate dissociation. As the well spacing decreases, the gas production rate increases. Depressurization alone is effective in dipping unconfined reservoirs, but much slower than warm water injection. As the injection point of the warm water moves down the reservoir, the start of the high gas recovery phase gets delayed, but the time for completion of gas recovery becomes shorter. Figure 13. (a) Hydrate saturation profile, (b) aqueous saturation profile, and (c) temperature profile for end injection case after 581 days.
Mathematical Simulation of Polymer Flooding in Complex Reservoirs
Society of Petroleum Engineers Journal, Oct 1, 1972
Simulation of polymer flooding in many complex reservoirs has requirements that preclude the use ... more Simulation of polymer flooding in many complex reservoirs has requirements that preclude the use of either three-phase stream tube or two-phase finite-difference simulators. The development of a polymer flooding model used in a three-phase, polymer flooding model used in a three-phase, four-component, compressible, finite-difference reservoir simulator that allows the simulation of a variety of complex situations is discussed. The polymer model represents the polymer solution as a fourth component that is included in the aqueous phase and is fully miscible with it. Adsorption of polymer is represented, as is both (1) the resulting permeability reduction of the aqueous phase and (2) the resulting lag of the polymer injection front and generation of a stripped polymer injection front and generation of a stripped water bank. The effects of fingering between the water and polymer are taken into account using an empirical "mixing parameter" model. The resulting simulator is capable of modeling reservoirs with nonuniform dip, multiple zones, desaturated zones, gravity segregation, and irregular well spacing and reservoir shape. Two examples are presented. The first illustrates the polymer flooding of a multizone dipping reservoir with a desaturated zone due to gravity drainage. The second illustrates the flooding of a reservoir with a gas cap and an oil rim with polymer injection near the oil-water contact. In this example, the effects of nonuniform dip, irregular well spacing and field shape, and gravity segregation of the flow are all taken into account. The two examples presented illustrate the versatility of the simulator presented illustrate the versatility of the simulator and its applicability to a wide range of problems. Introduction The design of a polymer flood for a complex reservoir requires a model that represents the reservoir features that have a significant effect on the performance of the flood. These features may include the presence of a gas cap or a desaturated zone due to gravity drainage in a dipping formation, the presence of an aquifer, irregular well spacing and reservoir boundaries, multiple zones, reservoir heterogeneities, and a well performance that is limited by state proration, injectivity, and productivity. These reservoir features are being productivity. These reservoir features are being represented by most compressible, three-phase, three-dimensional simulators. However, to model polymer flood projects, it is necessary to include a polymer flood projects, it is necessary to include a conservation equation for the polymer, and to represent the adsorption of polymer, the reduction of be rock permeability to the aqueous phase after contact with the polymer, the dispersion of the polymer slug, and the non-Newtonian flow behavior polymer slug, and the non-Newtonian flow behavior of the polymer solution.
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Papers by George Hirasaki