bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prediction of CO2/Crude Oil Phase Behavior Using Supercritical Fluid Chromatography
Authors: Stadler M. P. , Stessman A. N. , Orr F. M. 
Published: December 2007

Abstract
In this paper, we describe a method for characterization of crude oils for predictions of phase behavior of CO2 /crude oil mixtures with an equation of state (EOS). The method includes the use of supercritical fluid chromatography (SFC) with CO2 as the carrier fluid. Pressure-composition diagrams calculated using the the Peng-Robinson EOS and this characterization scheme agree well with PVT observations.
The advantage of this technique is that it produces predictions of the phase behavior of CO2/crude oil mixtures with much less experimental effort than is required to perform PVT experiments.
Comparison of Polyacrylamide Retention in Field Application and Laboratory Testing
Authors: Zettlitzer Michael , Volz Hartwig 
Published: December 2007

ABSTRACT
Since 1975, RWE-DEA has carried out numerous successful polymer field projects. In the reservoir units where injection had been initiated in the late seventies, production is close to being terminated- or can be estimated rather precisely by extrapolation of the concentration-versus-time profile. Polyacrylamide loss is calculated on the basis of injection and production data and amounts to 15 to 24 pg/g- or 25 to 53 μg/m2, respectively. Taking into account several correction factors, characteristically specific field retention values are in the range of 8 to 14 μg/g- or 13 to 28 μg/m2, respectively.
Field retention values are compared to polymer retention values determined in laboratory flood tests on packs of crushed reservoir core material and surface sands. As a general trend, polymer losses observed in laboratory tests are higher than those experienced in field applications. Possible interpretations are discussed.
Fluid Characterization of Three-Phase CO2/Oil Mixtures
Authors: Khan S. A. , Pope G. A. , Sepehrnoori Kamy 
Published: December 2007

ABSTRACT
The formation of three phases with CO2/oil mixtures at temperatures below about 120°F is well established. Several West Texas crude oils form three phases at CO2 concentrations higher than about 55% and pressures ranging between 900 and 1300 psia. These phases include an oleic phase (L1), a gaseous phase (V), and a CO2-rich liquid phase (L2). Although some authors have published equation-of-state (EOS) calculations of this type of behavior and used parameter tuning to match their experimental data, they did not give a methodology for characterizing these fluids. This paper presents a reservoir fluid characterization scheme for three-phase CO2/oil mixtures. An analytical procedure has been developed to generate mole fraction and density distributions for the heavy oil fraction. These distributions are then used for calculating EOS properties of heavy fraction components and for lumping into pseudocomponents. A new correlation for CO2-hydrocarbon binary interaction coefficients was required to make accurate predictions of three-phase (L1-L2-V) regions as well as the liquid-liquid (L1L2) region at higher pressures. Results for four West Texas crude oils are presented to validate the fluid characterization scheme. The first two cases, at 83°F and 94°F, exhibit large three-phase regions and the pressure-composition behavior has been predicted with good accuracy. The other two cases, at 105°F and 110°F, exhibit small three-phase regions and very good agreement has been obtained between the experimental and predicted pressure-composition diagrams and between compositional simulations and slimtube displacement experiments. Furthermore, this fluid characterization scheme has been implemented on a workstation using an expert system shell and is fast and easy to use.
Differences in Gas/Oil and Gas/Water Relative Permeability
Authors: Berry J. F. , Little A. J. H. , Skinner R. C. 
Published: December 2007

ABSTRACT
Correlations used to predict three phase relative permeability from two phase data often assume gas relative permeability is a function of gas saturation and not dependent on the liquid phase displaced. To test the validity of this assumption and to investigate the applicability of ambient condition gas/liquid relative permeability data, unsteady state displacements were conducted at ambient and reservoir conditions. All tests were performed on a composite constructed from four reservoir sandstone core plugs with similar lithological and petrophysical properties.
In-situ saturation monitoring, used throughout the ambient condition experiments, provided distributed saturation histories along the length of the composite. Good agreement between experimental observations and numerical predictions of pressure, effluent production and saturation histories indicates history matching via coreflood simulation is a valid method to obtain drainage gas/liquid relative permeability data free of sample scale capillary pressure end effects. Also, increased confidence may be placed in the results of history matching the reservoir condition displacements where distributed saturation data are not available.
History matched relative permeability data from ambient and reservoir condition tests show gas/water relative permeability data are suppressed compared to gas/oil data over a similar liquid saturation range. The good agreement between history matched ambient and reservoir condition gas/liquid data suggests ambient condition unsteady state displacements provide similar drainage relative permeability data when interpreted using coreflood simulation incorporating capillary pressure and the appropriate boundary conditions.
The Use of Well-to-Well Tracer Tests To Determine Geostatistical Parameters of Permeability
Authors: Ghori S. G. , Heller J. P. 
Published: December 2007

ABSTRACT
Tracer tests have been widely used in the petroleum industry to determine qualitative information about underground reservoirs, such as the existence of flow barriers, directional flow paths, etc. This paper describes how well-to-well tracer tests can be used to obtain quantitative information about the geostatistical parameters (variance and correlation scale) of permeability. Both theoretical and experimental results are presented.
In the theoretical work, a catalog of tracer production curves for different sets of geostatistical parameters for five-spot flooding patterns is produced. This catalog is computed with the help of a new numerical technique that is stable and devoid of any numerical dispersion. The effects of variance of the natural logarithm of permeability (ranging from .14 to 2.25), dimensionless correlation scale (ranging from .2 to .5), and of numerous realizations are quantified. The general effect of areal heterogeneity is that multiple peaks appear in the output tracer concentration curve, even when the flow is confined to a single layer. An increase in variance generally increases the number of prominent peaks in the output concentration profile, decreases the time between the emergence of peaks, and increases the time span of the occurrence of the tracer. An increase in correlation scale generally decreases the number of peaks. By using a sufficient number of permeability realizations, an attempt is made to assess variance and correlation length of the permeability field from the tracer and output concentration curves.
In the experimental work, a slab of rock (Arizona flagstone) representing a quarter of a five-spot pattern was selected. A simple minipermeameter was used to measure areal permeability on grids of points on both the top and bottom surfaces of the rock. A tracer test was performed and the tracer output concentrations were measured at six intervals along the depth of the rock at the production well. Six different types of concentration curves were obtained, showing that downhole sampling of the tracer would be important in achieving adequate information about the reservoir rock. Permeabilities measured with the minipermeameter were used as input into the simulator and the numerical production curves were compared with the experimental profiles. The occurrences of similar patterns of multiple peaks confirms the numerical technique and strongly suggests that well-to-well tracer tests in oil fields and aquifers could be used to estimate the geostatistical parameters of the permeability field.
Early CO2 Flood Experience at the South Wasson Clearfork Unit
Authors: Burbank D. E. 
Published: December 2007

ABSTRACT
This paper describes the implementation and performance of the industry's first Clearfork CO2 flood - Shell's South Wasson Clearfork Unit (SWCU) located in the Permian Basin of West Texas. CO2 injection began in 1986 using a high water-alternating-gas (WAG) ratio (8:1), low volume (8% hydrocarbon pore volume) flood,- or "CO2 augmented" waterflood. The intent of the flood was to increase our understanding of the Clearfork formation before committing to a larger scale CO2 flood.
The performance of the "CO2 augmented" waterflood has met expectations. After 3-1/2 years of CO2 injection, enhanced oil production had increased to 450 BOPD,- or 7% of Unit production. CO2 injectivity was comparable to water injectivity, and no significant decrease in the WAG water injectivity was observed. Encouraged by the success of the CO2 augmented waterflood, a 2:1 WAG CO2 flood was approved and implemented in the northern half of the CO2 flood area in the spring of 1990.
Through 1991, roughly 3% of a hydrocarbon pore volume of CO2 has been injected at SWCU, and the cumulative enhanced oil recovery matches the- original projections. The performance of the CO2 flood to date has been influenced by reservoir heterogeneity, injection pattern modifications, waterflood operating practices, and gas processing constraints.
Interpretation of a CO2 WAG Injectivity Test in the San Andres Formation Using a Compositional Simulator
Authors: Roper M. K. , Cheng C. T. , Varnon J. E. , Pope G. A. , Sepehrnoori Kamy 
Published: December 2007

ABSTRACT
It has been well documented that tertiary carbon dioxide WAG cycle injectivity during displacements above the minimum pressure for dynamic miscibility cannot be reliably predicted on the basis of viscosity ratios and waterflood injectivity performance alone. Approximate analytical models based upon gravity-free displacement with nondispersive plug flow of constant composition slugs in noncommunicating radial layers have been used to interpret injectivity during reservoir tests as a function of relative permeability, flow geometry, effective wellbore radius, and layering. We examine compositional simulation as an alternative for incorporating the additional effects of phase behavior, dispersive mixing, gravity, capillary forces, viscous instability, crossflow, and more realistic representations of reservoir heterogeneity in injectivity calculations for field test interpretation. We show how simple modifications can be made to an existing finite-difference equation-of-state simulator to allow for detailed modeling with these mechanisms of reservoir-scale cross-sections that incorporate geostatistical representations of reservoir heterogeneity and radial flow near injection and production wells.
The compositional model is applied to simulate and interpret an injectivity test conducted in the Mabee Field in the San Andres Formation, Martin County, Texas. Injectivity during the field test was significantly greater than initial waterflood injectivity during all WAG cycles, increased during each CO2 cycle, and was greater than would be anticipated from other field tests in the San Andres formation- or from available laboratory data. Compositional simulation of the field test indicates that the reservoir response during the first cycles of CO2 and brine injection, including the initial increasing CO2 injectivity trend and higher brine injectivity after the first CO2 cycle, are consistent with measured relative permeability, phase behavior, and reservoir characterization data, but that the observed injectivity increase during the second cycle of CO2 injection cannot be attributed to either the near-wellbore condition of the reservoir at the start of the test- or to the presence of thief zones that are statistically consistent with measured core data and well logs. Injectivity is a key variable in determining the economic incentive associated with a proposed CO2 project, and an important implication of this study is the validation of compositional simulation as a means for interpreting field tests and developing improved predictions of reservoir injectivity performance. Another important conclusion is that geostatistical techniques can be used successfully to characterize high heterogeneity in carbonate reservoirs for injectivity calculations.
Steamdrive in a Layered Reservoir: An Experimental and Mathematical Study
Authors: Gümrah Fevzi , Palmgren C. T. S. , Bruining Johannes , Godderij R. R. G. G. 
Published: December 2007

Abstract
We have studied steamdrive in layered reservoirs with scaled laboratory experiments. In spite of the frequent occurrence of stratification we have found no reference to previous laboratory studies of steamdrive in thin layered structures. The scaled transparent model was designed to investigate the influence of viscous, gravitational and capillary forces as well as the heat transfer mechanisms. Temperatures are measured by thermocouples and an infrared camera. Heat transfer rates to adjacent formations are measured by heat flux sensors. Visual observations make it possible to follow the evolution of the steam condensation front (SCF), which separates the steam zone from the liquid zone.
We have interpreted the results with an interface model. The interface model combines heat losses to the adjacent rock and fluid flow without the introduction of empirical relations for the SCF, which is essential to describe the behaviour in layered systems. For gravity stable situations the interface model is not valid but in this case a simpler model is adequate. We show the agreement between theory and experiments.
Some Insights Into the Low-Temperature and High-Temperature In-Situ Combustion Kinetics
Authors: Moore R. G. , Belgrave J. D. M. , Mehta Raj , Ursenbach Matt , Laureshen C. J. , Xi Kejia 
Published: December 2007

ABSTRACT
The classical concept of in situ combustion kinetics assumes the high-temperature combustion of a coke-like phase which has been deposited by thermal cracking reactions occurring ahead of the high-temperature front. Although this model appears adequate to describe the behaviour of low-pressure, high-air flux tests on most oils under dry and normal-wet conditions, its limitations are apparent when evaluating the performance of most high-pressure experiments, especially those carried out at high oxygen concentrations and low oxygen fluxes. A comprehensive program on low- and high-temperature oxidation kinetics was therefore undertaken with the aim of understanding the mechanisms associated with in situ combustion.
Accordingly, the highlights of findings from a ramped-temperature oxidation study on Athabasca Oil Sands is presented in this article. The results have significantly expanded the knowledge of in situ combustion kinetics, but perhaps the most important observation arising from the work is the recognition of the significance of the low-reaction rate region existing at the temperatures intermediate between those associated with low-temperature oxidation and high-temperature combustion reactions. The kinetics in this temperature range are characterized by decreasing oxygen uptake and energy generation rates with increasing temperature. This behaviour is analogous to the negative temperature gradient region described in conventional combustion literature. The ability of an oil to transcend the negative temperature gradient region appears to dictate its ultimate in situ combustion behaviour, and it appears that many field projects and tests utilizing high pressures and oxygen-enriched air operate in the low-temperature oxidation mode because of this phenomenon.
Gel Placement in Heterogeneous Systems with Crossflow
Authors: Sorbie K. S. , Seright R. S. 
Published: December 2007

ABSTRACT
Early water breakthrough can be a serious problem during waterflooding of heterogeneous reservoir formations. One possible remedy to this problem is to place a gel block in the high-permeability layer, thus diverting displacing brine into the less-permeable layers in- order to sweep the remaining oil from these zones. In such a treatment, the gelant material must be placed in the correct location within the reservoir so that gel does not impair reservoir performance. In this paper, we study the dynamics of gel placement in heterogeneous (stratified) reservoir systems. The details of the gel placement are strongly affected by the level of communication between reservoir layers, which is characterized by the closeness of the system to vertical equilibrium (VE) conditions. We show that in viscous-stable injection of gelant in systems close to vertical equilibrium, considerable volumes of injected material can crossflow into the low-permeability layers, and subsequent gel formation can seriously reduce the performance of the continuing waterflood. Results from a range of experimental displacements in well characterized layered beadpacks are presented, along with supporting numerical simulations, which help to understand the mechanisms and benefits when performing gel treatments in reservoir systems with free crossflow. The central role of viscous crossflow in such systems is demonstrated. Since we consider only viscous forces in this work, the layered experimental packs are scaled only by the viscosity ratio (displacing to displaced), the geometry of the packs, the aspect ratio and the degree of vertical communication (closeness to VE). Thus the conclusions from the experimental and simulation results are directly applicable to similarly scaled viscous-dominated systems at the reservoir scale. Some analysis is also presented of the mechanism of disruption of slugs by viscous fingering in layered systems.
Twenty-Five Years of Oil Recovery by Steam Injection
Authors: Khan Jamaludin , Parag Dhanpaul 
Published: December 2007

ABSTRACT
Thermal oil recovery was first started in 1966, in Trintopec's operations, with a small cyclic pilot project in the Palo Seco field. Twenty-five (25) years of thermal recovery, comprising cyclic and flood operations, have witnessed vigorous growth and dynamic expansion to the extent that, by 1991, the thermal recovery statistics are as follows:
Steamflood operations exist in all the Company's major land fields, viz., Palo Seco, Central Los Bajos, Guapo, North Fyzabad and Apex-Quarry/Coora/Quarry. Total production from thermal recovery averages 9100 bopd, representing 55% of Trintopec's current land production. A total of approximately 40000 bspd is being supplied by 23 steam generators to more than 150 steam injectors.
This paper presents highlights of Trintopec's experiences in the design, implementation and operation of thermal oil recovery schemes. New concepts, innovations, modelling and monitoring techniques over the past twenty-five (25) years are outlined, and, in addition, projections for the future are indicated.
North Cross (Devonian) Unit CO2 Flood: Status Report
Authors: Mizenko G. J. 
Published: December 2007

ABSTRACT
The North Cross (Devonian) Unit CO2 flood, Shell's first, began in 1972. While fairly small by West Texas standards, the project provides an example of a successful, mature CO2 flood. Seventy-eight billion cubic feet (BCF) of pipeline CO2 have been injected into the reservoir. Recycled produced gas has augmented this to bring cumulative CO2 injection to 128 BCF- or nearly 70% of the hydrocarbon pore volume. Production performance has been excellent. Unit oil production increased from approximately 1400 barrels per day (BOPD) when CO2 injection began to its peak of over 2600 BOPD in late 1978 before declining gradually to approximately 1900 BOPD by the end of 1991. An estimated 11 million barrels of enhanced oil have been recovered through 1991 and ultimate EOR is expected to double to over 22 million barrels.
Country Risk Analysis: A Probablistic Approach
Authors: David Amiel 
Published: December 2007

ABSTRACT
The oil industry has been an internationally based industry that has been heavily dependent on outside financing sources. Historically, financing came from investment houses that, in most cases, participated in the projects as equity investors. However, investment companies can no longer satisfy the capital requirements of the current high level of exploration and development activities. The current trend is to involve commercial banks on a purely lending basis. Commercial banks, by their nature, are risk averse. In the case of oil and gas exploration and production they are asked to take not only technical risk and price risk but geopolitical risk as well. Methods have been developed by commercial banks to reduce technical and price risks to a point which enables them to be comfortable with a loan. However, geopolitical risks are more difficult to assess. The risks associated with many countries are the nationalization of the investment, new tax restricitions, restriction of currency movements, and/or revisions to the production sharing agreements.
Private and public services that rate country risks are available to the industry. The risk factor is used by the industry to determine whether or not to enter into activities in a certain country. Risk indices are based on political, economic and commercial factors, and are deterministic in nature. This paper shows that probability distribution analysis can better describe the risks and provide a more continuous rating system. The probablity approach can be incorporated into probablity reserve determination resulting in economic projections for specific countries or regions.
Applying Rigorous Decision Analysis Methodology to Optimization of a Tertiary Recovery Project: Rangely Weber Sand Unit, Colorado
Authors: Wackowski R. K. , Stevens C. E. , Masoner L. O. , Larson J. L. , Aslesen K. S. 
Published: December 2007

ABSTRACT
The intent of this study was to rigorously look at all of the possible expansion, investment, operational, and C02purchase/recompression scenarios (over 2500) to yield a strategy that would maximize net present value of the C02 project at the Rangely Weber Sand Unit. Traditional methods of project management, which involve analyzing large numbers of single case economic evaluations, was found to be too cumbersome and inaccurate for an analysis of this scope. The decision analysis methodology utilized a statistical approach which resulted in a range of economic outcomes.
Advantages of the decision analysis methodology included: a more organized approach to classification of decisions and uncertainties; a clear sensitivity method to identify the key uncertainties; an application of probabilistic analysis through the decision tree; and a comprehensive display of the range of possible outcomes for communication to decision makers. This range made it possible to consider the upside and downside potential of the options and to weigh these against the Unit's strategies. Savings in time and manpower required to complete the study were also realized.
Economics of Reusable Facilities
Authors: Antia D. D. J. 
Published: December 2007

ABSTRACT
Some of the different economic development strategies that can be used for reusable facilities in the UK, Norway, Netherlands and in some production sharing contracts are outlined. These strategies focus on an integrated decision analysis approach which considers development phasing, reservoir management, tax planning and where appropriate facility purchase, leasing, or sale and leaseback decisions.