bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Viscous Fingering on the Prediction of Optimum WAG Ratio
Authors: Juanes R. , Blunt M. J. 
Published: December 2007

Abstract
In miscible flooding, injection of solvent is often combined with water in an attempt to reduce the mobility contrast between injected and displaced fluids, and control the degree of fingering. Using traditional fractional flow theory, Stalkup estimated the optimum water-solvent ratio (or WAG ratio) when viscous fingering effects are ignored, by imposing that the solvent and water fronts travel at the same speed. Here we study how the displacement efficiency and the mobility ratio across the solvent front vary with the WAG ratio, when fingering is included in the analysis. We do so by computing analytical solutions to a one-dimensional model of two-phase, three-component, first-contact miscible flow that includes the macroscopic effects of viscous fingering. The macroscopic model, originally proposed by Blunt and Christie, employs an extension of the Koval fingering model to multiphase flows. The premise is that the only parameter of the model —the effective mobility ratio— must be calibrated dynamically until self-consistency is achieved between the input value and the mobility contrast across the solvent front. This model has been extensively validated by means of high-resolution simulations that capture the details of viscous fingering and carefully-designed laboratory experiments.
The results of this paper suggest that, while the prediction of the optimum WAG ratio does not change dramatically by incorporating the effects of viscous fingering, it is beneficial to inject more solvent than estimated by Stalkup's method. We show that, in this case, both the PVI for complete oil recovery and thedegreeof fingering are minimized.
Gas/Oil Nonequilibrium in Multicontact Miscible Displacements within Homogeneous Porous Media
Authors: Al-Wahaibi Y. M. , Muggeridge A. H. , Grattoni C. A. 
Published: December 2007

Abstract
Compositional simulation is usually used to predict the performance of multi-contact miscible (MCM) recovery schemes. One key assumption in most such simulations is that of instantaneous compositional equilibrium is achieved between phases in each grid block. This is despite the fact that most grid blocks are tens of metres long and at least a metre thick.
This paper investigates the non-equilibrium observed in series of multi-contact miscible displacements performed in the laboratory. For simplicity a two-phase, three-component (IPA/water/cyclohexene) liquid system that exhibits an upper critical point at ambient conditions was used. Both vaporising and condensing drives were performed in well-characterised homogenous glass-bead packs. The use of analogue fluids and bead-packs enabled visualisation of the displacements as well as the usual measurements of effluent composition against time and recovery.
Non-equilibrium was observed in the effluent from both the condensing and vaporising experiments. This increased with flow-rate but appeared to be independent of the permeability and the length of the bead-pack. Further experiments investigating the influence of gravity on vertical displacements indicated that non-equilibrium may also be a function of the viscous to gravity ratio.
Detailed simulation using a commercial compositional simulator was unable to predict this non-equilibrium unless the results were tuned to the experimental observed effluent profiles using alpha factors. This is despite the fact that all PVT data, relative permeabilities and other pack properties were taken directly from experiments. However good match was obtained from a layered model with the permeability distribution obtained from a unit mobility ratio miscible displacement in the same pack.
These results are consistent with physical dispersion being the underlying cause of the non-equilibrium. Viscous fingering is discounted due to the low mobility ratio (~2) of the displacements.
Multiscale Regularization of Flooding Optimization for Smart-Field Management
Authors: Lien M. , Brouwer D. R. , Mannseth T. , Jansen J. D. 
Published: December 2007

Abstract
Smart fields can provide enhanced oil recovery through the combined use of optimization and data assimilation. In this paper, we focus on the dynamic optimization of injection and production rates during waterflooding. In particular, we use optimal control theory in order to find an optimal well management strategy over the life of the reservoir that maximizes an objective function (e.g. recovery or net present value). Optimal control requires the determination of a potentially large number of (groups of) well rates for a potentially large number of time periods. However, the optimal number of well groups and time steps is not known a-priori. Moreover, taking these numbers too large slows down the optimization process and increases the chance of achieving a sub-optimal solution. We investigated the use of multi-scale regularization methods to achieve grouping of the control settings of the wells in both space and time. Starting out with a very coarse grouping, the resolution is subsequently refined during the optimization. The regularization is adaptive in that the multi-scale parameterization is chosen based on the gradients of the objective function. Results for the numerical examples studied indicate that the regularization may lead to significantly different optimum strategies, but may result in a similar cumulative oil production.
Influence of Initial and Residual Oil Saturation and Relative Permeability on Recovery from Transition Zone Reservoirs in Shallow Shelf Carbonates
Authors: Byrnes A. P. , Bhattacharya S. 
Published: December 2007

Abstract
Early work characterized the relationship between initial oil (Soi) and residual oil saturation to waterflood (Sorw) and recent work has investigated theoretical oil recovery in transition zones. This study details experimental results for shallow-shelf carbonate lithologies and explores model application in thin carbonate reservoirs, such as those of the Midcontinent U.S., where production is often primarily from the transition zone.
Understanding Soi, Sorw, and relative permeability (kr) in transition-zone dominated reservoirs is fundamental to understanding recovery, and planning and managing IOR and EOR operations in these reservoirs. Drainage and imbibition oil-water relative permeability measurements were performed on Pennsylvanian-age oomoldic limestones and Mississippian-age moldic porosity mudstone to grainstone lime-dolomites. For these rocks, Sorw increases with increasing Soi due to enhanced trapping by emplacement of oil in fine pores. The Land-defined trapping characteristic, C, increases with increasing porosity resulting in less trapping with increasing porosity. This relationship, coupled with increasing "irreducible" water saturation (Swrri) with decreasing porosity and permeability, results in a systematic increase in Sorw with decreasing porosity/permeability and Soi. As Soi decreases with depth in the transition zone, proper modeling of kr requires a family of kr curves that reflect changes in kr with changing Soi. Utilizing a family of kr curves in recovery analysis shows that both oil and water recovery are greater than predicted from models utilizing kr curves with a constant Soi and Sorw. Oil recovery is higher because Sorw(Soi) is lower and water recovery is higher because Sw increases with proximity to the oil-water contact and as Sorw(Soi) is lowered.
These results validate and expand on use of the Land equation in shallow-shelf carbonates and help to explain both the high oil recovery and the high water production rates that are often evident in these reservoir systems.
Favorable Attributes of Alkali-Surfactant-Polymer Flooding
Authors: Zhang D. L. , Liu S. , Yan W. , Puerto M. , Hirasaki G. J. , Miller C. A. 
Published: December 2007

Abstract
A laboratory study of the alkali-surfactant-polymer (ASP) process was conducted. It was found from phase behavior studies that for a given synthetic surfactant and crude oil containing naphthenic acids, optimal salinity depends only on the ratio of the moles of soap formed from the acids to the moles of synthetic surfactant present. Adsorption of anionic surfactants on carbonate surfaces is reduced substantially by sodium carbonate but not by sodium hydroxide. The magnitude of the reduction with sodium carbonate decreases with increasing salinity.
Particular attention was given to a surfactant blend of a propoxylated sulfate having a slightly branched C16-17 hydrocarbon chain and an internal olefin sulfonate. In contrast to alkyl/aryl sulfonates previously considered for EOR, alkaline solutions of this blend containing neither alcohol nor oil were single-phase micellar solutions at all salinities up to and even exceeding optimal salinity with representative oils. Phase behavior with a West Texas crude oil at ambient temperature in the absence of alcohol was unusual in that colloidal material, perhaps another microemulsion having a higher soap content, was dispersed in the lower phase microemulsion. Low interfacial tensions existed with the excess oil phase only when this material was present in sufficient amount in the spinning drop device. Overall solubilization of oil and brine for this system was high, leading to low interfacial tensions over a wide salinity range and to excellent oil recovery in both dolomite and silica sand packs. These experiments were performed with surfactant concentrations as low as 0.2 wt%. It was necessary that sufficient polymer be present to provide adequate mobility control and that salinity be below the value at which phase separation occurred in the polymer/surfactant solution.
A one-dimensional simulator was developed to model the process. By calculating transport of soap formed from the crude oil and injected surfactant separately, it showed that a gradient in local soap-to surfactant ratio develops during the process. This gradient increases robustness of the process in a manner similar to that of a salinity gradient in a conventional surfactant process. Predictions of the simulator were in excellent agreement with the sand pack results.
Laboratory Investigation of the Effect of Solvent Injection on In-Situ Combustion
Authors: Cristofari J. , Castanier L. M. , Kovscek A. R. 
Published: December 2007

Abstract
Application of cyclic solvent injection into heavy and viscous crude oil followed by in-situ combustion of heavy residues is explored from a laboratory perspective. The solvent reduces oil viscosity in-situ and extracts the lighter crude-oil fractions. Combustion cleans the near well region as well as thermally stimulates production. Both solvent injection and in-situ combustion are technically effective. The combination of the two methods has, however, never been tried to our knowledge.
Hamaca (Venezuela) and West Sak(Alaska) crude oils were employed. First, ramped temperature oxidation studies were conducted to measure the kinetic properties of the oil prior to and following solvent injection. Pentane, decane, and kerosene were the solvents of interest. Second, solvent was injected in a cyclic fashion into a 1-m long combustion tube. Then, the tube was combusted. Hamaca oil presented good burning properties in all cases. The pentane extracted lighter components of the crude preferentially depositing effective fuel for combustion. West Sak oil, however, did not exhibit stable combustion properties following solvent injection, even when metallic additives were added to enhance the combustion. We were unable to propagate a burning front within the combustion tube. Nevertheless, the experimental results show that this combined solvent-combustion method is applicable to a broad range ofoil reservoirs
A Model to Predict Gas Hydrate Equilibrium and Gas Hydrate Saturation in Porous Media Including Mixed CO2-CH4 Hydrates
Authors: Bhangale A. Y. , Zhu T. , McGrail B. P. , White M. D. 
Published: December 2007

Abstract
Phase equilibrium of gas hydrates is altered in porous media as compared to bulk systems. Inside porous media, the thermodynamic potential of chemical components changes due to molecular interactions with pore walls and due to the energy required to maintain capillary equilibrium. A pore-freezing model was developed that can be used to predict gas hydrate equilibrium for pure CH4, CO2 and mixed CH4-CO2 systems in saline pore waters for any given pore size distribution. The important feature of this model is that it takes into consideration salting out phenomena, i.e. increase in salt concentration due to gas hydrate and ice formation. It also gives the gas hydrate saturation in porous medium. A new EOS developed for prediction of bulk gas hydrate equilibrium conditions, based on van der Waals – Platteeuw model, is used in the pore freezing model and can also be used to calculate heats of formation of these hydrates for a given pore size and pressure. The results obtained from the model are compared with experimental results.
Oil Recovery From Fractured Carbonates by Surfactant-Aided Gravity Drainage: Laboratory Experiments and Mechanistic Simulations
Authors: Adibhatla B. , Mohanty K. K. 
Published: December 2007

Abstract
Waterflooding recovers little oil from naturally fractured carbonate reservoirs if the matrix is oil-wet and fracture intensity is high. Laboratory experiments and mechanistic simulations have been conducted to understand the injection of dilute anionic surfactant solutions into oil-wet, fractured reservoirs. In this process, surfactant diffuses into the matrix, lowers IFT and contact angle, which decrease capillary pressure and increase oil relative permeability enabling gravity to drain the oil up. The rate of oil recovery increases with an increase in matrix permeability, a decrease in initial gas saturation, a decrease of fracture height or spacing, and an increase in wettability altering capabilities of the surfactant. Increasing the surfactant concentration does not necessarily enhance the oil recovery rate, because IFT and wettability alterations are not related to surfactant concentration linearly. Adsorption of anionic surfactants on calcite can be suppressed with an increase in pH and a decrease in salinity.
Investigation of Pore-Scale (Local) Mixing
Authors: Jha R. K. , Bryant S. L. , Lake L. W. , John A. 
Published: December 2007

Abstract
Local displacement efficiency in miscible floods is significantly affected by mixing taking place in the medium. Despite decades of research on mixing and dispersion, there remain questions about the amount of mixing occurring at pore-scale (hereinafter local). This study has investigated the local mixing experimentally as well as computationally.
We developed a thin electrical-conductivity probe to measure local solute concentration to quantify local mixing. Miscible tracer displacement experiments were carried out in a homogeneous sand pack. Local solute concentrations measured at several radial and axial positions using the probe indicate non-zero local mixing. The core scale mixing is the same as the local mixing for the homogeneous pack.
Local mixing is also investigated by solving the Navier-Stokes and convection-diffusion equations in two dimensional packing of circular disks. The computational studies qualitatively support the experimental observations for the homogeneous sand pack and explain the mixing mechanism inside the pore body. Mixing results from velocity variations in pore throats and bodies and molecular diffusion. The converging-diverging flow around sand grains causes the solute front to stretch, split and rejoin. In this process, the area available for diffusion increases by an order of magnitude. Diffusion tends to reduce local variation in solute concentration inside the pore body. If the fluid velocity is small, diffusion is able to homogenize solute concentration inside each pore. Increasing the fluid velocity has the same effect on local mixing as decreasing diffusion coefficient by the same factor. In limit of very large fluid velocity (or no diffusion) local mixing tends to zero and core-scale mixing is entirely caused by variations in velocity.
Injection Strategies To Overcome Gravity Segregation in Simultaneous Gas and Liquid Injection Into Homogeneous Reservoirs
Authors: Rossen W. R. , van Duijn C. J. , Nguyen Q. P. , Vikingstad A. K. 
Published: December 2007

Abstract
We earlier presented a proof for the model of Stone (1982) for gravity segregation in steady-state, horizontal gas-liquid flow in homogeneous porous media using only the standard assumptions of the method of characteristics. We extend this method here to cases of co-injection of gas and liquid over only a portion of the formation interval, injection of water above gas over the entire formation interval, and injection of water and gas in separate zones well separated from each other.
If gas and liquid are injected at fixed total volumetric rates, the horizontal distance to the point of complete segregation is the same, whether gas and liquid are co-injected over all or any portion of the formation interval. The volume of reservoir swept by gas may be affected by these different injection strategies, however, and is not directly predicted by our model. At fixed injection pressure, the deepest penetration of mixed gas and water is expected when fluids are co-injected along the entire formation interval.
At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does co-injection, but again exactly where the two fluids are injected does not affect the distance to the point of segregation. At fixed injection pressure, injection of liquid above gas is predicted to give much deeper penetration before complete segregation. When injection pressure is limited, the best strategy for simultaneous injection of both phases would be to inject gas at the bottom of the reservoir and liquid over the rest of the reservoir height, with the ratio of the injection intervals adjusted to maximize overall injectivity.
These results apply equally to gas-liquid flow and to foam. Sample computer simulations for foam injection agree well with the model predictions if numerical dispersion is controlled.
A Novel 3D Field-Scale Reservoir Numerical Simulator for Predicting the Fines Migration and Production Performance
Authors: Ju B. , Dai S. , Fan T. , Wu H. , Li S. , Zhang M. 
Published: December 2007

Abstract
Sand fines release and migration is a universal problem in the production of oil from unconsolidated sandstone reservoirs which can result in both sanding problems and profound effects on oil recovery. A new three dimensional (3D) field scale mathematical model, differing from those used for conventional oil reservoir numerical simulator in that both the advanced theories of sand particle release and migration, is presented. And the model is solved by a finite-difference method and the line successive over relaxation (LSOR) technique. A numerical simulator is written in Fortran 90 and VC++ and it can be used to predict (1) the sand content in produced liquid, (2) the porosity and permeability changes caused by sand release and migration in formation, and (3) well production performances and residual oil distribution. A series of runs of oil field examples with five-spot patterns were made on the numerical simulator. The results show that sanding problems in the oil formation can accelerate the heterogeneity of the reservoir rocks, and has an obvious influence on production performances: water-drive process, water-cut trends, and oil recovery. In a conclusion, the new simulator improves the ability and accuracy for numerical simulating the development of the unconsolidated sandstone reservoirs.
Efficient Data Management on the Rig of the Future
Authors: Kirkman M. , Chapman P. , Greaves C. , Turnbull H. , Johnson D. 
Published: December 2007

Abstract
In 2000 BP identified an opportunity to collaborate with a major Norwegian operator and develop an initiative for updating the drilling data standards for contractor to operator rig-site data flows to speed and enhance decision-making. This led to the successful WITSML initiative for XML and Web Services standards in the Drilling and Completions domain1 This has seen rapid acceptance by all the major operators, service contractors and application vendors (www.witsml.org).
The WITSML initiative started with the objective to update the existing methods for drilling data exchange at the rig for the internet age, and to incorporate the lessons learned from its precursor, WITS 2. WITS was designed for point-to-point transfers whereas WITSML, which is based on a functional XML and web services approach, facilitates wider access to data. WITSML acquired early success at replacing the WITS standard; however, moving further into contextual and report data to create true application-to-application interoperability required the operator community to intervene.
The intervention by BP has been to stimulate the marketplace and create a foundation to drive additional functionality for data exchange and reporting in the rig based environment and is the subject of this paper.
The approach taken by BP has been twofold: enabling the acceptance of contextual data from data acquisition providers by promoting enhancements of a widely used daily reporting tool; enabling the storage of time-based data within BP's own custodial databases and the merging of contextual data with the same. The deployment of the first trials of these enhanced applications is discussed. These enhanced applications have been used in harmony with "Decision Support Centres" where the opportunities to use improved technology to enable rig-office team decision-making are explored.
The Central Role and Challenges of Integrated Production Operations
Authors: Ella R. , Reid L. , Russell D. , Johnson D. , Davidson S. 
Published: December 2007

Abstract
This technical paper endeavours to describe the central role of Integrated Production Operations (IPO) in exploiting hydrocarbon reserves through the production phase of an asset. It provides definition of the key characteristics of IPO, sets out business case criterion for investment in IPO, challenges current industry positions and paradigms on future field management and provides a generic roadmap for operators seeking to be early adopters of IPO as a platform around which to organize their Digital Oil Field of the Future 1 (DOFF) initiatives.
Facilitating Risk Management in E&P Using Collaboration and Data-Visualisation Tools
Authors: Cain G. , Deliac E. 
Published: December 2007

Abstract
Technological progress alone is insufficient in the E&P industry today given the wider administrative, legal and organisational challenges that E&P development Projects currently have to contend with. In particular, risk management has become fundamental to both operator and service provider companies.
This paper presents two E&P case studies that illustrate how the use of collaboration and data visualisation tools provided significant assistance and support to E&P risk management activities. The first case study concerns a deep offshore E&P development project where the risk management activity had become virtually impossible to coordinate because of a very aggressive project execution environment. The implementation of collaboration technology for the project's executive management team established and sustained risk visibility at the appropriate level, whilst allowing all risk-related information to be seamlessly integrated with the rest of the project execution plan. The second case study concerns the collection and monitoring of safety and risk performance indicators (RPIs) at operational E&P sites of a major oil company. We will describe how analysis and feasibility work led to the design and development of a methodological tool capable of collecting and organising a diversified set of RPIs and then presenting them in an innovative graphical form for analysis and prioritisation.
The added value for E&P projects is evident: risk management without risk.