bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Polymer Adsorption and Flow Behavior on Two-Phase Flow in Porous Media
Authors: Zheng C. G. , Gall B. L. , Gao H. W. , Miller A. E. , Bryant R. S. 
Published: December 2007

Summary
To determine the effect of water-soluble polyacrylamide polymer adsorption and flow behavior on oil recovery, relative permeability and mobility were determined from flow experiments at various polymer concentrations. A selective reduction of the relative permeability to water with respect to the relative permeability to oil was observed for both Berea and reservoir sandstone cores. Adsorbed polymer layer increases water wettability. Relative permeability reduction could be attributed to both wettability change and pore-size restriction due to the adsorbed polymer layer. An empirical model was proposed to correlate the relative permeability reduction and the amount of polymer adsorption. Depletion-layer effect results in a reduced polymer viscosity in porous media with respect to bulk solutions. Modification of the existing shear-rate model allows for accurate prediction of this effect. The integration of the new models in UTCHEM provides a more accurate tool for engineering design of polymer applications.
Simplified Phase-Equilibrium Calculations in Integrated Reservoir and Surface-Pipeline-Network Models
Authors: Litvak M. L. , Wang C. H. 
Published: December 2007

Summary
Effective procedures for the integrated reservoir and surface facility compositional simulations have been developed. Multiphase compositional fluid flow equations in reservoirs, well tubing strings, and surface pipeline network systems are solved simultaneously. The procedures have been implemented in the commercial compositional reservoir and surface facility simulator: VIP.
The equation of state is applied for the phase-equilibrium calculations. A new equation-of-state (EOS) interpolation procedure has been developed (as an option) for simplified phase-equilibrium calculations in integrated compositional simulations. The EOS interpolation procedure can be effectively applied for phase-equilibrium calculations in reservoirs, well tubing strings, pipelines, and/or separators. Saturation pressure, recovery factors of hydrocarbon components, and compressibility factors are determined as tabular functions of pressure, temperature, and fluid compositions. The equation of state is applied for the automatic generation of these functions in an initialization step of a reservoir simulation.
The effectiveness and accuracy of the new simplified phase-equilibrium procedure have been confirmed in many full-field compositional models and pattern models. The new option significantly reduces the central processing unit time required for the simulations and it matches results of fully compositional simulations in the tested models.
The developed procedures for the integrated reservoir and facility compositional simulations have been applied in many reservoir studies. Their applications in the integrated reservoir and surface facility model of the giant Prudhoe Bay oil field have been demonstrated.
Development of Sycamore Sandstone Sholom Alechem Field, Stephens and Carter Counties, Oklahoma
Authors: Clark N.E. , Wall L.J. 
Published: December 2007

This paper covers various drilling problems and completion techniques in the 9,000-acre Sholom Alechem field of Stephens and Carter counties, Oklahoma. Oil and gas production is from the Sycamore formation at 8,000 ft deep. Although normally a limestone, this Mississippian age reservoir is a calcareous sandstone at Sholom Alechem.

Introduction
The cumulative crude oil production per acre or per acre-foot in Stephens and Carter counties is as great as any other sizeable area in Oklahoma. Recent Sycamore sandstone development in a previously neglected formation, the Sholom Alechem field of Stephens and Carter counties (Fig. 1), has added significantly to this cumulative production. production. The Sholom Alechem field (Fig. 2) is located in the eastern half of Township 1 South, Range 4 West, and Township 1 North, Range 4 West, Stephens County, and in the western part of Township 1 South, Range 3 West, Carter County. The Sycamore sandstone development, begun in 1972, includes 110 wells on an 80-acre spacing, involves 26 operators, and essentially has been completed. The Sycamore formation is found from 7,500 to 8,200 ft. Current daily production is 3,100 bbl and a total of 6,860,000 bbl has been produced from the Sycamore as of Oct. 31, 1976.
Ultimate production is expected to range from 10 to 12 million bbl of oil and 75 million Mcf of casinghead gas.

History
Oil originally was found in this area by Humble Oil and Refining Co. in 1923. The discovery well was the Jennings No. 1, located in the SW SW of Section 28-T1S-R3W, Carter County. The producing formation was the Pennsylvanian Deese sand at 3,400 ft. Early development was slow because the wells were low-volume producers and remained slow in the 1930's and 1940's, producers and remained slow in the 1930's and 1940's, because of the Depression and World War II. In Aug. 1947, Stanolind Oil and Gas Co. discovered Springer sand in their Sims No. 1 located in the NE SE of Section 2-T1S-R4W, Stephens County. The well produced 118 B/D of low-gravity oil from 4,800 ft. Rapid development continued for the next 5 years, with additional Deese and Springer sands discovered and developed. Much of this development was done on a 10-acre spacing. During the next 15 years, shallow development was limited to drilling a few edge and infill wells, plus beginning several secondary recovery projects, primarily waterfloods of the Sims and Deese projects, primarily waterfloods of the Sims and Deese sands.
JPT
P. 35
An Evaluation of the Robertson-Stiff Model Describing Rheological Properties of Drilling Fluids and Cement Slurries
Authors: Beirute R.M. , Flumerfelt R.W. 
Published: December 2007

Abstract
This paper evaluates the Robertson-Stiff rheological model for cement slurries and drilling muds. The model is compared with the Herschel-Bulkley model and is found to be an improved model for cement slurries. The Robertson-Stiff equations for volumetric flow rates in narrow annuli and tubes are shown to be limited to fluids with no yield stress. This paper develops more general equations that include the Robertson-Stiff results as special cases.

Introduction
In a recent paper, Robertson and Stiff presented a new model for describing the rheological behavior of drilling fluids and cement slurries. The principal advantages claimed for this model areit provides better fits of rheological data than other three-constant viscous models, andit gives explicit relations for the velocity fields, wall shear rates, and flow-rate/pressure-drop relations for flow in tubes and annuli.
The latter advantage is not possible with comparable models such as the possible with comparable models such as the Herschel-Bulkley model. In this paper we provide an independent evaluation of the model with regard to these characteristics.
First, we checked the accuracy of the model in fitting cement-slurry data and found that it does provide a good match to the experimental data. Fig. provide a good match to the experimental data. Fig. 1 shows the experimental data for a cement slurry along with fitting curves for the Robertson-Stiff and Herschel-Bulkley models. It can be seen that the Robertson-Stiff model is somewhat superior to the Herschel-Bulkley model in representing the data. This is also true in Fig. 2, which represents results for a different cement slurry of higher yield. Here again, the performance of the Robertson-Stiff model is somewhat better. Based on these observations, as well as others not presented here, we agree with the authors that their model is an improved model for cement slurries.
With regard to the claim that the model provides explicit relations for the wall shear rate and pressure-drop/flow-rate relation, we have found pressure-drop/flow-rate relation, we have found certain errors in the Robertson-Stiff analysis that invalidate this claim and make their final equations applicable only in certain special cases.
The basic error in their paper is that Robertson and Stiff overlooked the existence of a plug flow region in the center of the pipe or narrow annulus. Because of this, the equations derived are strictly valid only for the case of fluids with zero yield stress. Since most drilling fluids and cement slurries show some finite yield stress, the equations provided by Robertson and Stiff are of limited provided by Robertson and Stiff are of limited application. In the remainder of this paper we derive the correct relations for the model; the Robertson-Stiff relations appear as special cases.
SPEJ
P. 97
Fluid/Rock Interactions Between Xanthan/Chromium(III) Gel Systems and Dolomite Core Material
Authors: McCool C. S. , Green D. W. , Willhite G. P. 
Published: December 2007

SummaryGelation of chromium(III)/xanthan systems in dolomite core material for in-depth matrix rock treatments was investigated. The gels contained approximately 2,000 ppm xanthan and the dolomite core material was obtained from a San Andres dolomite reservoir in Texas and had permeabilities ranging from 4 to 10 md. Compositional changes in the gelant caused by interactions with the dolomite core material resulted in small permeability reductions for gelants prepared with chromium chloride, chromium acetate and a chromium diamine salt. The primary cause of incomplete gelation in the dolomite material was attributed to the increase in gelant pH that resulted in precipitation of chromium.
Modeling and Optimizing Oil and Gas Production and Gathering Systems: Cerro Fortunoso Field Case
Authors: Galliano G. R. , Degiorgis G. L. , Lopez M. L. , Fornes Adriana 
Published: December 2007

Summary
Cerro Fortunoso field produces a heavy and viscous oil and a separator gas which contains 95% of CO2. In 1996 a decision was made to reinject the gas to maintain pressure and prevent environmental damage. A technical team used a network simulator to model both the current oil gathering and the future gas reinjection systems. A parallel study was conducted to analyze the effect of non-Newtonian performance on predicted pressure drop. Although deviation was found to be slight, the non-Newtonian effect should be properly included in design calculations. Besides, as the gas will be reinjected near its critical point, thermodynamics becomes extremely important.
Modeling Nonlinear Interactions Among Near-Well Flow Restrictions in Well-Deliverability Prediction and Simulation
Authors: Hwang M. K. 
Published: December 2007

Summary
This work describes simulation of well productivity reduction due to near-well flow restrictions. The flow restrictions considered include: mechanical skin, partial completion, altered formation due to residual completion fluid or liquid dropout, and non-Darcy flow effects. It addresses two specific issues. The first is how to predict changes in well performance induced by changes in near-well parameters, as needed in history matching and well test analysis. A subset of this issue is how to estimate the impact of using well parameters to simplify simulation models such as partial completion skin and non-Darcy flow skin, instead of using more layers and solving the non-Darcy flow equation. The second issue is how to accurately preserve well productivity in a large grid block, as in the case of well productivity reduced by liquid dropout in a gas condensate reservoir model.
To resolve these issues, this work uses direct simulation and heuristic total skin equations developed for one-dimensional and two-dimensional multilayered cases with crossflow. The equation correctly represents the effects of nonlinear interactions among near-well flow restrictions on well productivity, resulting in an effective total skin that is much larger than the conventional linear sum of individual skin components. Numerical examples show the total skin equation can be used to predict well performance and to accurately preserve well productivity in a field-scale gas condensate reservoir model. The latter use of the equation shows a feedback mechanism, wherein the total skin is used to adjust the coarse-grid well productivity.
Fluid Placement Model for Horizontal-Well Stimulation
Authors: Eckerfield L. D. , Zhu D. , Hill A. D. , Robert J. A. , Bartko K. M. 
Published: December 2007

SummaryAcidizing is a common method used to stimulate horizontal wells. The acidizing process is fundamentally different when applied in a horizontal well compared with application in a vertical well. The fluid distribution in a horizontal well is affected by a longer wellbore length, a broader variation in the reservoir properties along the wellbore, and possibly different mechanical means by which to place the fluids in the wellbore. A comprehensive fluid placement model linked with a reservoir acidizing simulator is essential to precisely design acidizing treatments for horizontal wells.In this paper we present a model of fluid placement in a horizontal well. The model predicts the placement of injected fluids by tracking the interfaces of different fluids in the wellbore. It is capable of tracking multiple interfaces for multiple injection stages in horizontal wells. For injection with coiled tubing, the model allows tubing tail movement during injection. It also handles simultaneous injection from the annulus and from a tubing string. The fluid distribution generated from the model can be used as input information in a reservoir acidizing model for sand-stone acidizing design. Both analytical and discretized solutions of the model are presented in the paper. Examples in the paper illustrate the effects of such factors as velocity of tubing movement, annular injection, and a nonuniform distribution of flow into the reservoir on fluid placement in an acidizing treatment.The fluid placement model can help to determine optimum tubing tail locations and optimal injection volumes of acids, to select the most appropriate diverting methods, and, hence, to maximize the benefits of an acidizing treatment.
Reservoir Characterization Constrained to Well-Test Data: A Field Example
Authors: Landa J. L. , Horne R. N. , Kamal M. M. , Jenkins C. D. 
Published: December 2007

Summary
In this paper we present a method to integrate well test, production, shut-in pressure, log, core, and geological data to obtain a reservoir description for the Pagerungan field, offshore Indonesia. The method computes spatial distributions of permeability and porosity and generates a pressure response for comparison to field data. This technique produced a good match with well-test data from three wells and seven shut-in pressures. The permeability and porosity distributions also provide a reasonable explanation of the observed effects of a nearby aquifer on individual wells. As a final step, the method is compared to an alternate technique (object modeling) that models the reservoir as a two-dimensional channel.
Successful Drilling Practices: An Experiment in Cooperation
Authors: Brett J. F. , Gregoli M. K. , Gahan B. C. 
Published: December 2007

SummaryThis paper presents the results of a Gas Research Institute funded study to test the following hypothesis:"Broad-based benefit is created when drilling organizations systematically cooperate to identify and share successful practices"To this end, 11 separate successful drilling practices studies (SDP) were commissioned with the following goals: identify the most successful drilling practices for each of the study areas; document these practices in enough detail (in the form of a complete drilling operations plan) to ensure practical application; disseminate the successful practices; and measure the benefit derived from using the successful drilling operations plans.The studies focus on the following 11 drilling environments:Greater Green River basin (two studies: South Moxa arch Dakota formation and Wamsutter Almond formation), Arkoma Basin (two studies: Choctaw thrust and Jackfork plays), Cotton Valley Reef play in east Texas, Deep Austin chalk (Texas), Valverde basin (Straw and Penn sands, Texas), Anadarko basin (Watonga-Chickasha trend Morrow/Springer formations), South Texas Gulf coast (Wilcox Lobo trend), Deepwater (Green Canyon area), and Extended-reach (South Pass area) drilling in the Gulf of Mexico.This paper outlines the methodology used to develop these SDP studies, and the benefits reported by operators who have used them. Evidence presented shows that broad-based benefit can be created when drilling organizations systematically cooperate to identify and share successful practices, and that the benefit ranges from 3 to 20% of total drilling costs, with an average benefit on the order of 10%.
Effects of Grid Systems on Predicting Horizontal-Well Productivity
Authors: Wan Jing , Penmatcha V. R. , Arbabi Sepehr , Aziz Khalid 
Published: December 2007

SummaryWe compare horizontal-well performance for different grid types using a conventional formula for the well index. These results are also compared with the results of explicit well modeling, which does not require a well index. To assess the accuracy of numerical solutions, examples chosen are those for which exact analytical solutions are also available. These analytical solutions are for horizontal wells in brick-shaped homogeneous (isotropic or aniso-tropic) reservoirs (or drainage volumes). When a horizontal well extends through the full length of the reservoir, the problem be-comes two-dimensional with uniform influx along the well. On the other hand, if the well is completed in only a part of the reservoir (partially penetrating) a three-dimensional (3D) solution is needed. The 3D solution also predicts the influx profile along the well, with higher influx at the two ends. Because the conventional well index calculation does not account for the 3D nature of flow, the flow rate of the well may be incorrect. We have found that the well index obtained with the default procedure in most simulators (Peaceman's method) needs to be increased for the numerical simulator to predict the productivity of horizontal wells correctly.The correct well index can be obtained for any well if a suitable analytical solution is available. When such solutions are not avail-able, reference solutions can also be obtained by explicitly mod-eling the well with blocks that are of the same size as the well. In this case, there is no need for a well index. However, our analysis shows that for correct results the grid-aspect ratio for blocks rep-resenting the well and surrounding blocks has to be close to 1.
Effect of Gas Enrichment Above the MME on Oil Recovery in Enriched-Gas Floods
Authors: Johns R. T. , Sah Pashupati , Subramanian S. K. 
Published: December 2007

SummaryThe interaction of phase behavior and flow, in the presence of dispersive mixing, is examined for one-dimensional four-component enriched-gas displacements. Numerical and analytical solutions demonstrate that oil recovery may be substantially increased by gas enrichment above the minimum enrichment for miscibility (MME). The level of increase is dependent on the level of dispersive mixing and the size and shape of the two-phase region.A critical gas enrichment (CGE) above the MME is defined that separates the multicontact miscibility (MCM) region into two regions: MCM1, when the gas lies within the region of tie-line extensions, and MCM2, when the gas lies outside. For enrichments below the CGE (in MCM1), oil recovery can increase significantly with enrichment. Above the CGE (in MCM2), oil recovery is not as sensitive to enrichment for the cases studied. Displacements in the MCM1 region exhibit a combined condensing and vaporizing mechanism, whereas displacements in the MCM2 region are purely condensing.
Behavior and Effect of SARA Fractions of Oil During Combustion
Authors: Kok M. V. , Karacan C. O. 
Published: December 2007

Summary
In this study, saturate, aromatic, resin, and asphaltene fractions of two Turkish crude oils (medium and heavy) were separated by column chromatographic techniques. Combustion experiments were performed on whole oils and fractions by a thermogravimetric analyzer (TG/DTG) and differential scanning calorimeter (DSC) by using air and a 10°C/min heating rate. TG and DSC data were analyzed for the determination of weight loss due to possible reactions, and for reaction enthalpies of individual fractions, which have to be known for in-situ combustion technology utilization.
In-Situ Rheological Characterization of Drilling Mud
Authors: Maglione Roberto , Robotti Giovanni , Romagnoli Raffaele 
Published: December 2007

Summary
The rheological model of Herschel and Bulkley reported in 1926 can be applied to determine the characteristic parameters of a drilling fluid. In this paper, an in-situ characterization approach is proposed.
During flow tests at fixed drilling depths inside the well the pump rates and the relative stand pipe pressures (SPP's) are recorded. This allows one to determine in-situ the Herschel and Bulkley rheological parameters and the behavior of the drilling mud circulating in the well.
The results are compared to those obtained in the laboratory using a Fann VG 35 viscometer for the same drilling mud. It is found that the rheological triad from the viscometer data does not always coincide with the rheological triad from the in-situ drilling test. Thus, the calculated SPP using viscometer readings could lead to misleading errors for an actual process. This method could be useful not only to calculate and predict the SPP, but also to evaluate with accuracy the annular pressure drop in order to obtain the maximum allowable pump rates without fracturing the formations.
We discuss the sensitivity of the results in relation to the equivalent viscosity of the drilling fluids considered to some of the main practical drilling parameters, such as the flow velocity and pressure spatial distribution along the wellbore profile and, with reference to the mud structure, sensitivity to pressure and temperature.
Considering the drilling well essentially as a viscometer (WAV) enables one to investigate the performance of the drilling hydraulic circuit and also the effects of the true effective viscosity (here called equivalent viscosity) and of the rheological behavior of the muds in all types of wells, and overall in deep wells with great accuracy.
A General Correlation for Predicting the Hydrate-Free Zone of Reservoir Fluids
Authors: Østergaard K. K. , Tohidi B. , Danesh A. , Todd A. C. , Burgass R. W. 
Published: December 2007

Summary
A new correlation for predicting the hydrate-free zone of reservoir fluids, from black oil to lean natural gas, has been developed. The method correlates the hydrate dissociation pressure against the specific gravity and the concentration of the hydrate-forming components in the fluid, as well as the temperature of the system. The effect of nitrogen and carbon dioxide on the hydrate-free zone has also been taken into account. The correlation has been developed using hydrate phase boundaries for 31 fluids generated by a well-proven comprehensive thermodynamic model. Hydrate phase boundaries for 13 independent reservoir fluids calculated by the new correlation and the thermodynamic model have been compared, showing a maximum error of 1.0 K in the calculated potential hydrate-forming temperature.
A Study of Two-Phase, Non-Darcy Gas Flow Through Proppant Pacs
Authors: Jin L. , Penny G. S. 
Published: December 2007

Summary
Through a systematic experimental study it is found that the effect of liquid phase on non-Darcy gas flow through proppant packs cannot be characterized by Forchheimer correlation alone. An empirical equation that uses liquid-to-gas ratio to predict the effective permeability or conductivity of a proppant pack under two-phase, non-Darcy flow conditions is proposed in the paper. The effective permeability of a proppant pack at different conditions can then be calculated taking both non-Darcy and two-phase flow effect into account. A simplified physical model is developed to calculate a mobile liquid saturation at two-phase flow conditions.