bluuebunny/crossref_metadata_2025_split huggingface dataset:
Propagation of Chromium (III) Acetate Solutions Through Dolomite Rock
Authors: Jin H. , McCool C. S. , Willhite G. P. , Green D. W. , Michnick M. J. 
Published: December 2007

Abstract
Chromium(III)–polymer gel systems are often used in permeability modification treatments for flow control. Treatment of the carbonate rock matrix by these systems is of concern because rock-fluid interactions can lead to loss of chromium and thereby limit significantly the depth of penetration of a gel treatment. This paper describes a study of chromium retention in dolomite cores and demonstrates that precipitation of chromium is the principal retention mechanism. Displacement experiments were conducted in which chromium acetate solutions were continuously displaced at different flow rates through Baker dolomite cores. In some experiments, the cores were shut in and the resident fluid displaced and analysed to determine chromium retention during the shut-in period.
There was significant retention of chromium in the core in both continuous and shut-in experiments. In the continuous displacements, effluent concentration profiles were a function of flow rate, indicating that the retention was a rate-dependent process. The presence of KCl increased the retention rate. At the lowest flow rate used, effluent chromium concentration approached a steady-state value that was much smaller than the injected concentration. The retention capacity of the rock appeared to be infinite.
Chromium concentrations at various residence times were compared to values predicted from a kinetic model developed for precipitation from bulk solutions. The kinetic model fit the precipitation rate data well and is consistent with the conclusion that precipitation is the principal retention mechanism. However, the induction period observed in bulk solutions was not present in the data taken in the cores. Precipitation occurred faster in the cores than in the batch experiments. The experimental results indicate that chromium is precipitated at a relatively high rate when chromium acetate solution is in contact with dolomite core material. This loss of chromium will inhibit gelation and limit the depth of penetration of a gel system in dolomite matrix rock.
IOR: The Brazilian Perspective
Authors: Shecaira Farid S. , Branco Celso C. M. , de Souza Antonio L. S. , Pinto Antonio Carlos C. , de Holleben Carlos R. C. , Johann Paulo R. S. 
Published: December 2007

Abstract
The intent of this paper is to summarize the IOR evolution in Brazil and its perspectives for the future. First of all, a brief history of the oil industry in Brazil is presented, with special prominence to the establishment of the oil industry monopoly in 1953. Next, the main IOR efforts carried out by the industry are reported, beginning in the sixties with water injection in onshore fields, and subsequently with the use of several tertiary recovery methods. The gradual increase in oil production in offshore areas, as from the late seventies, changed the IOR panorama. Presently, water injection is the main IOR activity in offshore fields, which account for approximately 74% of the Brazilian daily oil output. The discovery of oil in deeper waters, as well as more recent facts, such as the enactment of the law breaking, in 1997, the mentioned Brazilian oil industry monopoly, added new components to the industry organization. These new facts can be of major importance in the future development of IOR activities in Brazil
Experimental and Field Results on the Use of Heavy Crude Injection to Control Gas Production in Light/Medium Crude Wells
Authors: Andarcia L. , Perez-Perez A. , Alvarez J. M. 
Published: December 2007

Abstract
Many heavy crudes show foaminess at surface conditions. The foam formed is usually very stable and can remain in an open vessel for several hours. This stability is especially obvious when taking fluid samples from producing wells. The emphasis of recent research on "foamy" crudes has been on explaining the unexpectedly large recovery efficiencies of these crudes by solution gas drive (so-called cold production). This work studies a different aspect of these crudes, namely their ability to reduce gas production in light/medium oil wells. As far as we know, this is the first application of foamy crudes to reduce produced gas-oil ratio (GOR). If successful, the technology should be less expensive than polymer gel or foam treatments (the competing technologies for lowering GOR) because no formulation is needed and there are no expensive chemicals involved.
The ability of foamy crudes to reduce gas production GOR is supported by experimental results. We conducted four experiments in sand packs under pressures and temperatures typical of Venezuelan light/medium crude oil reservoirs. The experiments were primary depletions done until a relatively large gas-oil ratio (GOR = 4000 scf/stb) was reached. At this point, we injected a slug of foamy crude through the producing side of the pack and continued the depletion. Slug sizes of the foamy crude ranged from 0.05 to 0.1 of pore volume. We monitored the experiments through the produced GOR, gas and oil rates and pressure profiles.
The experiments showed dramatic declines of GOR, ranging from the starting value of 4000 scf/stb to almost to the solution gas-oil ratio measured at the existing pressure. This represents a GOR reduction of up to 96%. The average of all tests had an incremental oil recovery of 8% after the injection of the foamy crude. As a result of the lab experiments, we began a pilot test in a mature medium oil field (Acema 200, San Tomé, Eastern Venezuela). The slug size was 150 bbl of foamy crude, which penetrated an average of 12 ft into the reservoir. After one month of monitoring, this field test showed an incremental oil recovery of up to 2000 bbl and a GOR reduction of 80%. The oil production rate increased by 328%, therefore the application cost of 5500 $ US was recovered by the second day of production. We measured a sudden increase of the GOR 3-1/2 months after the heavy oil injection.
Optimal Injection Strategies for Foam IOR
Authors: Shan D. , Rossen W. R. 
Published: December 2007

Abstract
Miscible-gas foam field trials have employed a variety of injection strategies, with mixed results. Using simulation, we compare foam-injection strategies in homogeneous reservoirs with a variety of foam models.
The optimal injection strategy for overcoming gravity override with foam in a homogeneous reservoir is alternating injection of separate, large slugs of gas and liquid at fixed, maximum-allowable injection pressure. This strategy minimizes both gravity override and time of injection, with minimal rise in injection-well pressure. Injection of gas at maximum pressure can partially reverse the effects of gravity slumping of surfactant during injection of liquid. The process is remarkably insensitive to the detailed properties of the foam, as long as foam does not collapse abruptly and completely at a "limiting water saturation" Sw*.
An idealized model for the process reveals the mechanisms responsible for process success, why injection at fixed injection pressure is better than injection at fixed rate, and why details of foam behavior play a secondary role in sweep efficiency.
Extreme care is needed to exclude the effects of numerical artifacts in simulating such a process, especially if foam collapses abruptly and completely at Sw*. In that case numerical dispersion may produce plausible, but inaccurate, simulation results.
Estimation of Foam Mobility in Heterogeneous Porous Media
Authors: Kovscek A. R. , Bertin H. J. 
Published: December 2007

Abstract
It has been shown experimentally, both here and elsewhere, that foaming gas is a promising technique for achieving mobility control and diverting injected fluid to low permeability strata within heterogeneous porous media. However, the factors most important for diversion have not been stated and explored definitively. Gas mobility in the presence of foam depends critically on foam bubble size; bubble size may vary with permeability, porosity, surfactant type and concentration, and the velocity of liquid and gas. This paper adopts a local-equilibrium, scaling perspective to describe quantitatively foamed gas mobility within heterogeneous porous media. Conventional and percolation network scaling ideas are employed. The equations developed indicate, for instance, that porosity plays an important role in setting gas mobility because it reflects the relative abundance of foam germination and termination sites per unit volume of porous media. Liquid velocity is also important because gas mobility is inversely proportional to this factor. Predictions are checked via comparison to new experimental results. The experimental system is composed of a 0.395 porosity, 5.35 μ2 synthetic sandstone and a 0.244 porosity, 0.686 μ2 natural sandstone. The cores are arranged in parallel and communicate through common injection and production conditions. Nitrogen is the gas phase and a classical alpha-olefin sulfonate (AOS 1416) in brine is the foamer. Three types of experiments were conducted. First, gas alone was injected into the system after presaturation with the foamer solution. Second, gas and foamer solution were coinjected at an overall gas fraction of 90% into cores presaturated with surfactant. Each core accepted a portion of the injected gas and liquid according to the mobility within the core. Lastly, gas and foamer solution were coinjected into the individual, isolated porous media in order to establish baseline behavior. The results show that in-situ generation of foam is an effective method for improving the sweep efficiency of lower permeability strata. The results also confirm predictions that foamed gas can be more mobile in lower permeability porous media.
Reservoir Management of the El Furrial Field – Venezuela under Enhanced Oil Recovery Process
Authors: Araque Isaura Echeverría , Auxiette S. A. Gerard 
Published: December 2007

Abstract
El Furrial field, is located in the north of Monagas State and was discovered in 1986. It originally contained around 7.5 billions STOIIP. The field is approximately 13 km long and 7 km wide. It produces from two main formations identified as the Naricual and Cretaceous Formations. The gross thickness of the two reservoirs is more than 2100 ft. The oil composition in the Furrial Field changes rapidly with depth from that of a conventional oil (28 °API) at the top of the formation to that of an immovable tarmat, at the base of the reservoir. Mainly as a result of the increasing asphaltene content of the crude.
PDVSA has devoted intensive engineering studies to define the optimum development strategy and to maximise final recovery. As a result of these studies, production mechanisms were identified early and a reservoir pressure maintenance program was defined to increase the recovery and to sustain production. Simultaneously with the implementation of a waterflood project, engineering studies were continued to determine the feasibility of a gas-injection alternative. These studies showed that complement to the water-injection program and it will increase cumulative oil recovery by around 7.5 % OOIP.
Additional mechanistic studies concerning the WAG process for the downdip flanks have been done. The results from these shows increase in the recovery factor by about 7 to 10 % OOIP, due to the miscible gas effect.
The studies involve, extensive laboratory work, geostatistical and deterministic reservoir descriptions and cross-sections compositional and black-oil miscible simulation models, to define the best recovery process. At this moment water and gas injection processes are already implemented and are at present injecting about 458 MBWPD and 393 MMSCFD. A mechanistic WAG pilot project is ongoing.
Alternatives of Gas Injection as an Enhanced Recovery Method in Advanced Gas Market Environment
Authors: Palasthy G. , Kristof P. , Tóth T. 
Published: December 2007

Abstract
In Hungary, the oil prices in the range of $20 makes EOR projects commercially viable. Because of their structures and fluid properties, the oil reservoirs in Hungary are suitable for gas injection EOR methods. This EOR potential is well supported by favourable infrastructure in the local oil industry/surroundings.
The paper presents the EOR application for a large reservoir in the Pannonian basin. The Szeged-Móravóros is undersaturated fractured reservoir with Triassic dolomite, Miocene sandstone and conglomerate at the depth of 2630-2450 meters below the sea level. The OOIP derived from material balance is 11.56 million cubic meter and oil gravity is 817 kg/m3.
The initial pressure was pr=331 bar, initial temperature was tr=140 °C. In the period of the natural depletion between 1975-1980, the cumulative oil production was 1,27 million cubic meter. In this period, because of the limited water influx, the reservoir pressure dropped below the bubble point and secondary gas cap started to increase. The pressure dropped to pr=244 bar.
In 1980, water injection was started to maintain the reservoir pressure. The aim was to increase the reservoir pressure above the bubble point pressure. With this water injection from 1980 to the present time, the oil recovery is 36.4 % with a cumulative oil production of 4.21 million cubic meter. The current reservoir pressure is 250 bar.
For studying the further recovery enhancement, laboratory and reservoir simulation studies were carried out to evaluate different gases. Natural gas, nitrogen, and CO2 were selected for the gas injection near the structure top. In Hungary, large CO2 reserves are available 50-250 km distance from the oil field. The natural gas resources are easily available because of the developed gas distribution network and the production of nitrogen by stripping from the air can be also easily realised. At the optimal pr=250 bar pressure, the displacement process is not miscible in the reservoir, and the recovery increment is not sensitive to the type of injected gas or its quality. The reservoir simulation shows the recovery increment is about 12 %.
We have selected nitrogen gas as an injection gas based upon economic and environment evaluations. The paper describes how we arrived at this conclusion in a country where there is a well-developed natural gas market. The paper also includes discussion about the methods and criteria used to select the process.
Multi-Scale Iterative Techniques and Adaptive Mesh Refinement for Miscible Displacement Simulation
Authors: Trangenstein John A. , Bi Zhuoxin 
Published: December 2007

Abstract
Many enhanced oil recovery processes in reservoir engineeringinvolvelocalized phenomena that could be due to several features, such asinjection fronts, wells or reservoir heterogeneity.In order to reach sufficientaccuracy in field-scale simulation, the localized phenomena need to be resolvedand modeledin appropriate scale-dependent ways.Our approach to treating thelocalized phenomena is to usehigh-resolution discretization methods incombination with dynamicallyadaptive mesh refinement(AMR).The purpose ofadaptive mesh refinement is to concentrate thecomputational work near theregions of interest in the displacement processes, which may evolve constantlyin space.Adaptive mesh refinement requires appropriate techniquesfor datacommunication in a hierarchy of dynamically adaptive mesh.The selection ofappropriate scaling rules as well as computationallyefficient data structuresis essential to the success of the overallmethod.
We have exploited the object-oriented features of C++ for the AMR programstructure and data management, while numerically intensive routines areimplemented in FORTRAN.It turned out that adaptive mesh refinement cansignificantlyreduce the computational cost required to obtain a desired levelofaccuracy in the simulation.However, the emphasis here is on the developmentof efficienttechniques for solving linear systems that arise in thenumericaldiscretization of an elliptic equation for the incompressiblepressurefield. We use a conjugate gradient algorithm preconditioned bymultiplicative domain decomposition between refinement levels, in whichadditivedomain decomposition and incomplete Cholesky factorization were employed as"smoothers".In this paper, the combined adaptive mesh refinement technique hasbeenapplied to a single-phase tracer transport model for miscibleflooding.Numerical results demonstrating the effectiveness of the methodarepresented and discussed.
Simulations of Chemical and Microbial Enhanced Oil Recovery Methods
Authors: Delshad Mojdeh , Asakawa Kazuhiro , Pope Gary A. , Sepehrnoori Kamy 
Published: December 2007

Abstract
Our chemical flooding simulator UTCHEM has been under development for many years and continues to evolve as a general purpose chemical simulator. We have extended the capability of this simulator to process advanced oil recovery methods which use surfactant, polymers, gels, alkaline chemicals, foam, and microorganisms as well as various combinations of these. We have developed and implemented a multiphase and multicomponent dual porosity model so in addition to targeting conventional oil reservoirs, the use of chemical methods in naturally fractured oil reservoirs can be evaluated. The model includes complex chemical phenomena previously modeled with UTCHEM for both fracture and matrix, e.g. the effects of reduced interfacial tension on phase trapping, surfactant adsorption, and so forth. In this paper we only discuss the dual porosity, foam, and microbial enhanced oil recovery models recently developed and implemented in UTCHEM.
An Effective Continuum Model for the Gas Evolution in Internal Steam Drives
Authors: Tsimpanogiannis Ioannis N. , Yortsos Yannis C. 
Published: December 2007

Abstract
We derive an effective continuum model to describe the nucleation and subsequent growth of a gas phase from a supersaturated liquid in a porous medium, driven by heat transfer. The evolution of the gas results from the reduction of the system pressure at a constant rate. The model addresses two stages before the onset of bulk gas ow, nucleation and gas phase growth. The problem arises in internal steam drives, for example of the type recently discussed in blowdown experiments in carbonate rocks (Dehghani et al., 1997, Dehghani and Kamath, 1999).
Important quantities characterizing the process, such as the fraction of pores that host activated sites, the deviation from thermodynamic equilibrium, the maximum supersaturation in the system and the critical gas saturation depend crucially on the nucleation characteristics of the medium. We use heterogeneous nucleation models in the form of pre-existing gas, trapped in hydrophobic cavities to investigate the nucleation behavior. Using scaling analysis and a simpler analytical model we show that the relevant quantities during nucleation can be expressed in terms of a simple combination of dimensionless parameters, which include rate effects. The subsequent evolution of the gas phase and the approach to the critical gas saturation are also described using numerical and analytical models.
The theory predicts that the maximum supersaturation in the system is a weakly increasing function of the decline rate. This function depends sensitively on the probability density function of the nucleation cavity sizes. It also predicts that the final nucleation fraction, thus the critical gas saturation, is a power law of the decline rate. The theory for both nucleation and phase growth is then compared with available experimental data and a good match is obtained by appropriate fitting of the nucleation characteristics of the medium.
Modeling of the Unusual GOR Performance in a Fractured Gas-Condensate Reservoir
Authors: Ghorayeb K. , Firoozabadi A. , Anraku T. 
Published: December 2007

Abstract
The Yufutsu gas-condensate field in Hokkaido, Japan, is an unusual reservoir. The fluid in the reservoir is heavier at the top, and the C7+ fraction decreases with depth despite pressure communication. Another unusual aspect of the reservoir is the decrease of the GOR from an initial value of around 1350 vol/vol to around 950 vol/vol in the first five years of production. In this work, we present the results of compositional simulation. The simulation is based on the initialization from a model that takes into account molecular, pressure, and thermal diffusion. The GOR predicted from the compositional simulation is in agreement with measured GOR.
Waterflood Prediction Of Partially Depleted Reservoirs
Authors: Higgins R.V. , Leighton A.J. 
Published: December 2007

Publication Rights Reserved
This paper is to be presented at the California Regional Meeting of the Society of Petroleum Engineers of AIME in Santa Barbara, Calif., on Oct. 24–25, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

Abstract
A method is presented to calculate the performance of waterfloods which are started when the oil saturation is high and enough gas still remains in the reservoir oil to affect appreciably the rate of oil recovery. The interest in this type of flooding stems from the rapid recovery compared to waterflooding after depletion by the expansion of the dissolved gas. The quick recovery influences the rate of return on the investment.
The predictions for five-spot or other pattern floods are obtained by summing the performances of the individual channels bounded by streamlines obtained from the potentiometric model for the pattern. The times and rates are calculated using the shape factors and volumes determined from the equipotentials and streamlines of the potentiometric model. The recovery calculations at all times include the changing oil, water, and gas saturations throughout the pattern as influenced by the oil, water, and gas permeabilities and the quantity of water that has been injected. The recovery as a function of time is determined by the progress of an oil bank created by the injected water and a second downstream oil bank formed by the displaced gas. The flow of oil and gas in the second oil bank is governed by the permeabilities to oil and gas in this section.
Several examples are presented in order that engineers may ascertain the relative order of the effect of time, recovery, and rates as functions of the viscosity of reservoir oil, initial gas saturation, and distance between wells. The data for the linear and five-spot patterns are presented.
By the use of the high-speed digital computer, a performance calculation can be made in about 1–1/2 minutes.