bluuebunny/crossref_metadata_2025_split huggingface dataset:
SWAG Injectivity Behavior Based on Siri Field Data
Authors: Berge Lars Inge , Stensen Jan Åge , Crapez Bénédicte , Quale Eileen A. 
Published: December 2007

Abstract
Injection of water and gas in combination, in most cases injected in an alternating scheme (WAG), is one of the most successful IOR methods applied in the North Sea. Simultaneous water and gas injection (SWAG) has so far gained less experience. Simulations show in general an IOR potential of the same magnitude as WAG. Field limitations may in some cases be in favor of SWAG injection. The main contributions to increased recovery come from improved sweep, oil swelling and reduced residual oil saturation.
SWAG has recently been implemented on the Siri Field on the Danish Continental Shelf and represents the first reported full field application of its kind in the North Sea. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The Siri Field has performed SWAG injection from the production start in 1999.
SWAG injection on Siri and experiences has previously been reported1. Reservoir studies predict field recovery improvements with combined water and gas injection. Injection of a two-phase mixture of water and gas represents some new challenges. One relates to injectivity. Combined water and gas injection may result in lower injectivity than for single-phase injection. Injectivity is therefore important in connection with practical implementation of SWAG. A discussion of injectivity behaviour and interpretation of Siri data will be presented. For the Siri Field, hydraulic fracturing of the injectors proved unavoidable due to unexpected low permeability in the injection zone. Above the fracturing pressure, the injectivity can be strongly dependent on the gas fraction of the injection mixture.
Producer/Injector Ratio: The Key to Understanding Pattern Flow Performance and Optimizing Waterflood Design
Authors: Hansen C. E. , Fanchi J. R. 
Published: December 2007

Abstract
This paper presents new analytical relationships describing pattern waterflooding that have not been reported previously. The relationships fill a significant gap in the existing steady-state flow theory for two-phase, isotropic reservoir systems. The new equations, which include modifications for reservoir heterogeneity and skin effect, represent a general, comprehensive pattern flow theory that unifies previous works while greatly extending the range of applicability to all patterns and mobility ratios. These relationships facilitate understanding that is not provided by existing waterflooding theory of the absolute and relative flow performance of the various patterns in all mobility systems. A rational, analytical approach to waterflood optimization is presented here.
Disproportional Permeability Modification by Alcohol-Containing Polymer Solutions: Laboratory Studies and Field Experiences
Authors: Lakatos I. , Lakatos-Szabó J. , Kosztin B. , Palásthy Gy. 
Published: December 2007

Abstract
Gas production from gas fields and underground gas storage is usually accompanied by substantial water production. The high water production and necessity of on-site water liquidation often deteriorate the recovery efficiency and hamper maintaining an environmentally friendly production. During the past decades intensive R&D activity has been made to develop a viable well treatment method, however on account of the inverse mobility ratio in gas/water system, the conventional water shut-off or profile correction methods could not be used successfully under field conditions. According to some proposals the most promising procedure might be the injection of a high salt-containing polymer solution into the wells utilizing the reversible swelling/shrinking properties of the adsorbed polymer layer. If this mechanism works properly, a disproportional permeability modification is resulted and hence, the water productions is significantly decreased.
In contrast to mentioned technical solution the new idea is to use a "poor" solvent for preparation of the treating solution. The concept is based on the fact that the "solvent power" worsens as the alcohol content in the aqueous phase is increasing. A detailed laboratory study has been made in order to optimize the alcohol type and concentration, and different polymers were used as model to demonstrate the feasibility of the theoretical considerations. Complex rheological measurements served to study the flow properties of treating solutions and to determine the molecular conformation in bulk and adsorbed states. Sophisticated hydrodynamic measurements were carried out to demonstrate the disproportional permeability modification in gas/water systems and in different porous media. Finally, the general procedure was up-scaled to field conditions and the technology was tailored to individual well conditions. In the frame of the pilot test four gas wells operating at the largest Hungarian gas field were treated with alcohol-containing polymer solutions. The pilot tests were supported with sophisticated reservoir engineering supervision and the results were evaluated meticulously by academic and practical experts. According to the available data two treatments proved already positive, one of them showed outstanding performance. At the present time the observations are continued and new treatment project is planned by the operator. The paper outlines the whole innovation process and gives a concise summary of the lessons to learn.
Effect of Capillary Pressure, Salinity, and Aging on Wettability Alteration in Sandstones and Limestones
Authors: Chattopadhyay Sruti , Jain Vivek , Sharma M. M. 
Published: December 2007

Abstract
Oil recovery in petroleum reservoirs is greatly affected by fluid -rock and fluid-fluid interactions. These surface chemical interactions directly control rock wettability, capillary pressure curves and relative permeabilities. Centrifuge coreflow tests (Berea sandstone and Texas Cream limestone) were performed with a range of fluids under different conditions to identify the factors influencing the residual wetting and non-wetting phase saturations and oil recovery. Results of the tests conducted with Prudhoe Bay and Moutray crude oil show that remaining water (Swr) and residual oil saturation vary systematically with Bond number for both sandstone and limestone samples. Differences in the shape of the wetting phase capillary desaturation curves are observed during primary and secondary drainage. This suggests that the distribution of fluids in the rock during secondary drainage is different from primary drainage due to a change in wettability of the core from a water-wet state to mixed-wet state. These trends were not observed with decane. Both limestone and sandstone cores become more susceptible to wettability alteration as the salinity is increased. The wettability index(Aw-Ao, water Amott-oil Amott) decreases from 0.56 (0.3% brine) to 0.2 (20%brine) in a limestone core with Prudhoe Bay crude oil. Aging the samples for 20-30 days with Moutray crude oil shows results in a change in the wettability of the cores. The oil recovery increases by 10-15% to more than 95% in both Berea and limestone cores. These results show that with time the crude oil changes the wettability of the core from strongly water wet to mixed wet, which leads to a higher oil recovery. Experiments with samples of sandstone and limestone aged with Prudhoe Bay crude oil and brine of different salinities also show similar trends.
A New Approach to the Determination of Polymer Concentration in Reservoir Rock Adsorption Tests
Authors: Mezzomo R. F. , Moczydlower P. , Sanmartin A. N. , Araujo C. H. V. 
Published: December 2007

Abstract
An alternative method for measuring polymer concentration in core effluents during dynamic polymer adsorption determination tests in laboratory scale was developed. Laboratory tests were made by injecting polyacrylamide solutions at different concentrations in a water saturated sandstone core. Core effluent was measured for the shear rate necessary to cause a constant and high (70% of full scale) torque on a rotational rheometer. The measured shear rate was converted to concentration values by using a calibration curve. Polymer concentration was also determined by spectrophotometry for comparison.
The curve obtained by the proposed isotorque method showed greater reliability and lower variations than the spectrophotometric method. The isotorque method, besides being simple in terms of laboratory work, is able to give better adsorption values as input for polymer flooding simulations.
Sorbed Polyacrylamides: Selective Permeability Parameters Using Surface Techniques
Authors: Córdova M. , Mogollón J. L. , Molero H. , Navas M. 
Published: December 2007

Abstract
The adsorption of polyacrylamides on siliceous surfaces was studied by X-ray Photoelectron Spectroscopy (XPS), Scanning Electron Microscopy (SEM), Atomic Force Microscopy (AFM) and contact angle.
XPS allows to determine the amount of homopolyacrylamide (PAM) adsorbed directly on mineral surface. The XPS results showed a correlation factor of 0.99 when they were compared to those obtained using the conventional technique of N-Bromination of amides. The experimental work involved in XPS determinations was found to be simple, rapid and suitable for mechanistic studies on non-consolidated rocks and sandstone cores. PAM and hydrophobic modified polyacrylamide (PAMHM) layers adsorbed on Berea discs were compared using SEM. The PAMHM polymer showed higher affinity for clay minerals and it covers the mineral surfaces with a film, largely reducing the surface roughness compared to PAM. AFM studies conducted on muscovite mica showed how the surface coverage increases with concentration of polymer. The AFM results demonstrated that hydrophobic modification of PAM increases significantly mineral coverage and attenuate surface roughness.
The roughness reduction and total Berea surface coverage by PAMHM suggests an enhanced lubrication effect that could make the flow of a nonwetting fluid (oil) easier. PAMHM slighty increases surface water-wet condition as supported by additional contact angle measurements. This behavior could enhance oil recovery by improving oil mobility and reducing water mobility. The combination of these two effects, demonstrated in static adsorption tests, supports the PAMHM potential for selective permeability reduction in siliceous formations.
Petrophysical Characterization of Permian Shallow-Water Dolostone
Authors: Holtz M. H. , Jackson John A. , Jackson Katherine G. , Major R. P. 
Published: December 2007

Abstract
The complex interplay between depositional facies and diagenesis in dolostones presents numerous challenges for calculating petrophysical properties from wireline logs. Complex pore geometries and mineralogies control rock petrophysical properties, and equations for calculating porosities and saturations must therefore be tailored to specific pore geometry-mineralogy combinations. The complex mineralogy of some dolostone reservoirs, moreover, has profound effects on wireline log measurements. If dolostone reservoirs are divided into petrophysical-mineralogical facies of similar depositional and diagenetic textures and, thus, similar pore geometries and mineralogy, empirical equations that apply specifically to that geologically identified petrophysical-mineralogical facies can be developed so that porosity and water saturation can be calculated accurately.
We present some examples from Permian shallow-water dolostone reservoirs of the Permian Basin, southwestern United States, that demonstrate analytical approaches for calculating petrophysical properties in these complex rock types. The four general petrophysical-mineralogical facies that characterize Permian shallow-water dolostone reservoirs are (1) subtidal, muddominated dolostone; (2) subtidal, grain-dominated dolostone; (3) dolomitic and siliciclastic peritidal rocks; and (4) diagenetically altered, subtidal dolostone.
Microbial and Waterflooding of Fractured Carbonate Rocks: An Experimental Approach
Authors: Zekri Abdulrazag Y. , El-Mehaideb Reyadh A. 
Published: December 2007

Abstract
Fractures and fractured zones require special reservoir development plan. They may improve or hider the oil production. Conductive fracture rocks may provide the required permeability to drain an oil saturated low permeability rock matrix. Low sweep efficiency of many oil reservoirs may be the result of channeling of injected water through high permeability zones that normally associated with fracture system in heterogeneous reservoirs. In this case substantial amount of work focused on improving the distribution of injected water in the wellbore through different treatments: using gelling agents, cements, cross-linked polymer and emulsions. Other alternatives such as microbial and surfactant based methods have been proposed. This paper presents the results of research conducted on thermophilic bacteria that were obtained from UAE local environment. Coreflooding experiments were conducted on single fractured cores to show the effectiveness of microbial treatment. Different fracture angel orientations 45°, 90°, and 180° of the axis of the flow were investigated. The effect of matrix permeability on the treatment was also studied. A comparison between water flooding and microbial flooding of fractured systems were investigated. Non-invasive imaging technique such as Scanning Electron Microscopy (SEM) was employed to visualize changes on the surface of the fracture as a result of bacteria flow through the system.
Seismic-Based Gas-Water-Contact, Porosity, and Permeabilities for Condensate Reservoirs: Tested and Corrected by History Matching
Authors: Kasap Ekrem , Lumay Viloria , Xue Fangian J. , Corbett Chip , Nishikiori Nobuo , Tomonori Shibata 
Published: December 2007

Abstract
Seismic attributes are an essential source of information on lateral variation in rock properties. Quantitative use of seismic attributes in predictive models is challenging, because the seismic data are of limited resolution and influenced by rock mechanical properties, porosity, pore fluid type, bed thickness, and dip angle.
An integrated study was conducted to optimize the coupled gas production from Fields A and B, offshore Gulf of Mexico. Field B formation characterization results are discussed here. Structural static models were constructed from depth-converted seismic horizon interpretations. The models were porosity populated by integrating seismic amplitude-based areal porosity heterogeneity with well log and core data using geostatistical techniques. All other necessary petrophysical parameters were correlated to porosity. Static models were then converted to numerical models, which were used to predict historical data.
Field B has Upper, Middle, and Lower sands, which were produced from dual completions. The Upper sand is thick enough to be resolved on the seismic data. The gas-water contact (GWC) was reliably determined and verified by history matching. The matching production data, tubing head pressure (THP), and static reservoir pressure revealed, however, that seismic amplitude overestimates porosity above the GWC, and underestimates it in no-gas aquifer zones. This effect is amplified in permeability because of its exponential relationship to porosity. THPs and well tests were used to correct for permeability.
The Lower sand reservoir quality deteriorates quickly in most parts of the reservoir, and the seismic resolution was less than desired. Here, in addition to pore volume and permeability, the GWC needed corrections to match historical data. From these findings, we concluded that seismic-based areal heterogeneity is a valuable source of data for predictive reservoir models when supported by the dynamic production and well test data.
Inferring Interwell Connectivity From Well-Rate Fluctuations in Waterfloods
Authors: Alejandro Albertoni , Lake Larry W. 
Published: December 2007

Abstract
This paper presents a practical technique to quantify communication between wells in a reservoir using only production and injection rate data. The technique combines a constrained multivariate linear regression analysis with diffusivity filters to provide information about permeability trends and the presence of transmissibility barriers. The method was developed and tested using a numerical simulator and then applied to a waterflooded field in Argentina. The simulation results indicate that the connectivity between wells is described by coefficients that only depend on geology and relative position between wells; they are independent of injection/production rates. The results of this work can be used to improve the performance of an existing waterflood by suggesting how well patterns might be changed or managed. They could also be used to model flow in the reservoir.
Characterization Of Estuary-Shoreface Type Reservoir Using Outcrop Analogue And Modeling Of Flow Using A Nonuniform Coarsened Grid
Authors: Merchan Sergio A. , Srinivasan Sanjay , Meyer Rudi 
Published: December 2007

Abstract
A methodology for constructing an analogue 3D model for clastic reservoirs in an estuary-shoreface depositional environment using outcrop information is discussed. Such analogue models provide valuable information related to reservoir architecture and rock properties that can be used to model sedimentary structures in the subsurface. A new approach for upscaling high-resolution models using nonuniform coarsened grid is introduced. Simulation results for a viscous dominated flow process show that nonuniform grids yield better results compared to uniform grids.
Sensitivity of Reservoir Simulations to Uncertainties in Viscosity
Authors: Hernández J. C. , Vesovic V. , Carter J. N. , Lopez E. 
Published: December 2007

Abstract
The paper examines the sensitivity of reservoir simulations to uncertainties in viscosity. The simulations are performed for three different oils, ranging from light to viscous, for three different geological terrains. In each case, the viscosity has been estimated by a number of currently recommended prediction methods and by recourse to the measured values. The preliminary results indicate that the results of reservoir simulations are sensitive to the fluid viscosity. The sensitivity increases with increase in the absolute viscosity of the oil, increase in heterogeneity of the reservoir and increase in uncertainty in viscosity. The results show, that in the worst case scenario examined (e.g. heavy, viscous oils, η &gt; 6 cp) a ±1% error in viscosity will produce a 1% error in the cumulative production. Overall, the preliminary results indicate that the common assumption in reservoir simulations, that the accuracy of fluid properties has a marginal influence on the reservoir performance, is false. Uncertainties in viscosity can lead to large errors in predicted production rates, thus unduly influencing the economics of reservoir exploitation.
Integrated Production Operation Models With Reservoir Simulation for Optimum Reservoir Management
Authors: Yang Daoyong , Zhang Qi , Gu Yongan 
Published: December 2007

Abstract
There has been an increasing interest in optimum reservoir management to maximize oil production from a reservoir given the present economic and technical limits. However, many reservoir management programs have failed because they do not consider wells, surface facilities and the reservoir as an integrated system. In fact, determination of optimum operation parameters for both producers and injectors is critical to the ultimate oil recovery under the existing reservoir and infrastructure conditions. On the other hand, production operation methods are usually not taken into account in reservoir simulation, which is traditionally used for reservoir management purpose. Also due to practical constraints, test runs are often limited to a few most plausible sets of model parameters, though the global optimum set should be used instead.
This paper presents a systems engineering approach, which integrates production operation models with reservoir simulation to achieve the global optimum parameters for both producers and injectors. More specifically, a reservoir simulator starts with a basic run, which provides a reference case. Then the simulated annealing algorithm is employed to solve multi-dimensional nonlinear global optimization problems. Finally, the optimum reservoir performance is obtained by executing the reservoir simulator with the global optimum parameters. Such integrated approach ensures that the displacement front can advance slowly and steadily at various stages of the field development such that the maximum oil production can be achieved. It is also found that the simulated annealing algorithm is efficient and stable in achieving the global optimum. Furthermore, this systems method is applied fieldwide to a water-alternating-gas (WAG) miscible flooding reservoir. The reservoir performance has been adjusted and controlled in an optimum range over five years. The reservoir pressure remains higher than the minimum miscible pressure (MMP) and distributes uniformly in the whole reservoir, in which appropriate production operation methods are implemented. The bottom-hole flowing pressure, injection pressure, oil rate, injection volume of water and gas, water-cut and gas-oil-ratio (GOR) are kept in a proper range. All these fieldwide data show that the integrated approach to optimum reservoir management presented in this paper can greatly improve the oil production.
Estimation of True Dispersivity in Field Scale Permeable Media
Authors: Mahadevan Jagannathan , Lake Larry W. , Johns Russell T. 
Published: December 2007

Abstract
Simulation studies (Solano et al.1; Stalkup2) show that oil recovery for enriched gas drives depends on the amount of dispersion in reservoir media. But the true value of dispersion, expressed as dispersivity, at the field scale, is unknown. This work investigates three types of dispersion in permeable media to obtain realistic estimates of dispersive mixing at the field scale.
The dispersivity from single-well tracer tests (SWTT), also known as echo dispersivity, is the dispersivity that is unaffected by fluid flow direction. Layering in permeable media tends to increase the observed dispersivity in well-to-well tracer tests, also known as transmission dispersivity, but leaves the echo dispersivity unaffected. A collection of SWTT data is analyzed to estimate echo dispersivity at the SWTT scale. The estimated echo dispersivities closely match a published trend with length scale in dispersivities obtained from groundwater tracer tests. This unexpected result—it was thought that transmission dispersivity should be greater than echo dispersivity—is analyzed with numerical simulation.
A third type of dispersive mixing is local dispersivity, or the mixing observed at a point as tracer flows past it. Numerical simulation results show that the local dispersivity is always less than the transmission dispersivity and greater than the echo dispersivity limits. It is closer to one limit or the other depending on the amount and type of heterogeneity, the autocorrelation structure of the medium's permeability, and the lateral (vertical) permeability. The agreement between the SWTT echo dispersivities and the field trend suggests that the field data are measuring local dispersivities. All dispersivities appear to grow with length.