bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanisms of Wetting Alteration by Crude Oils
Authors: Buckley J. S. , Liu Y. , Monsterleet S. 
Published: December 2007

SummaryPolar crude oil components can adsorb on mineral surfaces and alter their wetting properties. Extrapolating from laboratory observations of wetting alteration to reservoir conditions is difficult because of the chemical complexity of the crude oils, the variability of mineral surfaces, and the presence of brine. It is essential to recognize that the polar components of crude oils can adsorb by several distinct mechanisms, depending on factors that include brine composition and the solvent quality of the oil for its asphaltenes. In this article, several important mechanisms are identified. These have been demonstrated by experimental observations of contact angles between pure fluids on flat surfaces after exposure to crude oil. The consequences of these mechanisms for wetting alteration by different crude oils in porous media are examined.
Further Investigations of Why Gels Reduce Water Permeability More Than Oil Permeability
Authors: Liang Jenn-Tai , Seright R. S. 
Published: December 2007

Summary
In this paper, we investigate why some gels can reduce the permeability to water much more than to oil. This property is critical to the success of chemical-based water-shutoff treatments in production wells if hydrocarbon-productive zones cannot be protected during placement. We first briefly review previous findings and the validity of several possible explanations for this disproportionate permeability reduction. Next, we describe experiments that test the validity of a promising mechanism—the segregated pathway theory. This theory speculates that on a microscopic scale, aqueous gelants follow water pathways more than oil pathways. Our experimental results in cores support this mechanism for oil-based gels, but not for water-based gels. We also explore another interesting mechanism that involves a balance between capillary and elastic forces. Results from our experiments support this mechanism for flow in tubes and micromodels, but not in porous rock. Other mechanisms are also discussed.
Operating Electrical Submersible Pumps Below the Perforations
Authors: Wilson B. L. , Mack John , Foster Danny 
Published: December 2007

Summary
The electrical submersible pump (ESP) uses the flow of well fluid to cool the motor. This, traditionally, has been done by landing the ESP above the perforations or by using a shroud to redirect the fluid around the motor. This paper examines some of the advantages and disadvantages of ESP operation below the perforation. Several equipment options necessary for this type of operation are presented, along with an operator's field experience where below-perforation operation looked to be advantageous.
Application of Seismic Monitoring To Manage an Early-Stage Steamflood
Authors: Waite M. W. , Sigit Rusdinadar , Rusdibiyo A. V. , Susanto Toni , Primadi Hari , Satriana Denny 
Published: December 2007

Summary
Time-lapse seismic monitoring technology has recently been introduced to the Duri field reservoir-management process as a means of directly imaging changes in vertical and horizontal steam distribution over time. The technique consists of repeated acquisition of three-dimensional (3D) seismic surveys to measure steamflood-induced changes in the acoustic properties of hydrocarbon reservoirs. The resulting seismic images are processed, parameterized, and translated to relevant engineering parameters. In this case study, steam flow was monitored during the early stages of steam injection by mapping anomalous seismic-reflectivity response within the steam-flow layers. Seismic-reflectivity data and borehole information were combined by use of multivariate statistical analysis and image processing techniques to produce images of steamflood conformance at the flow-unit level. The images reveal important insights into steam-flow behavior and were used to design a conformance-improvement program for the case study focus area.
Well Design Using a Computer Model
Authors: Helmy Mohamed Wael , Khalaf Fouad , Darwish T. A. 
Published: December 2007

Summary
In this study, the theory of nonlinear optimization is used to develop a well-design computer model to determine the optimum directional parameters to minimize drilling depth and reduce drilling costs. The model uses the sequential unconstrained minimization technique (SUMT) to minimize drilling-depth objective function. Also, the model is used to calculate well surveys, simulate bit walk, and determine optimum lead angle to kick a well off. The minimum drilling depth is achieved at the minimum values for kickoff point, inclination, and angle-buildup and -dropoff rates. These minimum parameters reduce the dogleg severity, which, in turn, reduces the chances for operational problems like high torque and drag. The computer model has been validated by comparing a conventional design and an optimized design for a well drilled in the Gulf of Suez. The optimization model produced less drilling depth and lower inclination and dogleg severity.
Methodology for Numerical Simulation With Cycle-Dependent Relative Permeabilities
Authors: Larsen J. A. , Skauge Arne 
Published: December 2007

SummaryMultiphase flow involving saturation oscillations should be modeled with history-dependent, relative permeability functions. Earlier approaches have been based on two-phase flow. The main assumptions have been that the imbibition process is reversible. Moreover, scanning curves were developed only for saturations between some extreme values.Several tertiary oil recovery processes have shown cycle-dependent hysteresis for relative permeability. When saturation oscillations occur during three-phase flow such as water alternating gas (WAG), the two-phase hysteresis models will generally not be able to describe relative permeabilities obtained from corefloods. For three-phase flow, local hysteresis effects may also be important. New relative permeability representations that account for local hysteresis effects are presented.Hysteresis models for both wetting and nonwetting phase permeabilities have been developed. The new models account for reduced mobility and irreversible hysteresis loops during three-phase flow. The models depend on the initial saturation at the start of the given process. An algorithm is presented for implementing the nonwetting phase hysteresis model in a numerical simulator. The new three-phase models use experimental wetting and nonwetting relative permeabilities as input, and knowledge of relations between maximum nonwetting saturation and trapped nonwetting saturation.
Wellbore Two-Phase Flow and Heat Transfer During Transient Testing
Authors: Hasan A. R. , Kabir C. S. , Wang Xiaowei 
Published: December 2007

Summary
This paper presents a comprehensive wellbore/reservoir simulator to study pressure-transient behavior during two-phase flow in a vertical or deviated wellbore. We adapted a hybrid approach by modeling the wellbore numerically in which mass, momentum, and energy of the fluids are conserved, while treating the reservoir fluid flow analytically. Conductive heat transport occurs through the tubulars, cement sheaths, and formation. Both conductive and convective heat transport mechanisms are operative for the annular fluid, however. For an offshore well, convective heat transfer through seawater and air are also considered.
The simulator can be run in two modes. In forward simulation, transient pressure and temperature can be computed at any point in the wellbore, given the reservoir and completion parameters. Conversely, in a reverse simulation, bottomhole pressures (BHP's) can be computed given the pressure and temperature measurements at any other point in the borehole, including at the wellhead. However, the quality of reverse simulation derived solution is likely to suffer with increasing gas/oil ratio (GOR). Field data were used to show both features of the simulator.
Computational results show that the effect of heat loss through seawater is marginal for most offshore wells with a short submerged section (&lt;500 ft) because of the fluids’ short residence time. However, for wells with long submerged tubulars (&gt;2,000 ft), heat loss to the seawater becomes significant. Similarly, a deviated well loses more heat to the formation than its vertical counterpart because of increased residence time. Among major variables, thermal conductivity of the annular fluid plays a key role in heat retention and, therefore, in the wellhead temperature (WHT).
Two-Phase Zero-Net Liquid Flow in Upward Inclined Pipes: Experiment and Modeling
Authors: Amaravadi Sridhar , Minami Kazuioshi , Shoham Ovadia 
Published: December 2007

Summary
The effect of pressure on two-phase zero-net liquid flow (ZNLF) in upward inclined pipes has been studied experimentally and theoretically. Experimental data were acquired for four upward inclination angles, namely, 1,2, 5, and 9°, and for three system pressures of 14.7, 44.7, and 64.7 psia. A sequence of flow configuration was observed with increasing gas flow rate as follows: slug flow for low superficial gas velocities; protoslug for medium velocities; and pulsating, small-amplitude waves or roll waves at high velocities. At a particular velocity of gas, termed the blowout velocity, all the liquid was blown out of the pipe. An analysis of equilibrium stratified flow, at the limit of very low and zero liquid flow rates, has been carried out. It was found that, under these conditions, the flow is always unstable, resulting in intermittent or pulsating stratified flow. A model has been developed for the prediction of the blowout velocity, as well as average liquid holdup and pressure gradient under ZNLF conditions. A very good agreement was observed between the predictions of the proposed model and the experimental data.
The Triangle "U" Sussex Unit—A Case History Comparing Two Chemical Enhanced Waterflood Methods
Authors: Smith J. E. , Larsen Dan 
Published: December 2007

Summary
The Triangle "U" unit is located in Campbell County, Wyoming, in the Powder River basin. The field produces mainly from the Sussex A sandstone, with completions and limited production from the Sussex B. The flood recovered 12.8% original oil in place (OOIP) on primary before the waterflood, which began in March 1981. The Sussex A is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays, and the initial injection water source was fresh, leading to concerns about long-term injectivity. To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride (KCl) and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long-term performance of the two groups of injection wells shows that the wells treated with KOH injected 476,437 bbls/porosity-ft more water than the wells treated with cationic polymer, in 1.4 years less time. This is an 83% increase in cumulative water injection. After KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March 1997 is 36.4% OOIP, compared to the original waterflood projection of 26.6% OOIP. A total of 37.7% pore volume (PV) water has been injected, and the water/oil ratio (WOR) is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone.
Thermal and Mechanical Considerations for Design of Insulated Tubing
Authors: Pattillo P. D. , Bellarby J. E. , Ross G. R. , Gosch S. W. , McLaren G. D. 
Published: December 2007

Summary
Of the several options for controlling temperature in a well, vacuum-insulated tubing (VIT) has proven useful in a number of applications. Use of VIT, however, necessitates unique design considerations, from both a thermal and mechanical perspective.
This paper describes the application of VIT for a particular purpose—to minimize temperature change, and associated annular fluid-expansion pressures, in a deepwater well design. The specific application, however, lends background to more general design considerations associated with VIT. Thermally, the importance of heat loss at the couplings to the overall design is discussed, using both numerical analysis and experimental results previously reported in the redesign of wells for the Marlin tension-leg platform (TLP). Mechanically, a detailed examination of the loads to which VIT may be subjected also uncovers special considerations.
Measurements and CFD Modeling of Drag-Reduction Effects
Authors: Koskinen Jukka , Manninen Mikko , Pättikangas Timo , Alopaeus Ville , Keskinen Kari I. , Kolehmainen Eero 
Published: December 2007

Summary
Computational-fluid-dynamics (CFD) modeling of drag reduction (DR) by polymer additives dissolved in hydrocarbon was carried out in pipe flows and in a rotating shear viscometer. A two-layer turbulence model was applied that described turbulence damping by the molecules of drag-reducing additives (DRAs) in the near-wall regions. The von Karman constant in the near-wall region was used as the model parameter. Extensive measurements of the DR effect for a rotating viscometer were performed at different Reynolds numbers, apparent molar masses, and DRA concentrations. The model with only one fit parameter was able to reproduce the experimental results in both pipe flows and the rotating viscometer. Experimental results were used in relating the model parameter to the relevant physical properties.
High-Power/High-Frequency Acoustic Stimulation: A Novel and Effective Wellbore Stimulation Technology
Authors: Wong Sau-Wai , van der Bas Fred , Zuiderwijk Pedro , Birchak Bob , Han Wei , Yoo Kwang , van Batenburg Diederik 
Published: December 2007

Summary
Local impairment of formation permeability often causes reduced production because of the interaction of the reservoir with drilling and completion fluids. The problem may be further compounded by impairment caused by fines migration during production.
High-frequency sonic and ultrasonic waves have been used in many industrial applications to remove contaminants, such as dirt, oil, and grease from parts that are immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high-frequency acoustic waves. The influence of high-frequency waves is limited to the near-wellbore environment because of high attenuation. Dedicated experiments under realistic downhole conditions have been carried out in both linear and radial configurations. We have examined the acoustic power needed to remove near-wellbore formation damage caused by fines and particles plugging pores as well as drilling-induced damage. Specific issues related to well completion and the envelope of acoustic stimulation are presented. The laboratory results have led to the design and construction of a slim, high-power, and high-frequency (above 10 kHz) downhole acoustic tool for field deployment.
This paper outlines the concept and presents key experimental results to support the claim. Key features of a prototype downhole tool are also described.
A Streamline-Based Method for Assisted History Matching Applied to an Arabian Gulf Field
Authors: Agarwal Bijan , Blunt Martin J. 
Published: December 2007

Summary
A streamline-based history-matching method is presented that overcomes two of the major limitations of previous approaches: (1) it uses a three-phase compressible streamline simulator for the forward simulation, and so its application is not limited to incompressible waterfloods; and (2) geological constraints, such as regions of differing facies, can be honored. Permeability, porosity, and anisotropy can all be modified using the methodology of Assisted History Matching.1–3 In this paper, the technique is extended with suggested modifications to the reservoir description computed assuming tracer-like flow. This allows the engineer to direct the parameter changes through interactive code.
The method is applied to history matching the full-field model for the Southwest Fateh Mishrif field located in an offshore concession in the Emirate of Dubai. The Southwest Fateh Mishrif is a carbonate reservoir containing a highly undersaturated oil. There are currently 42 active producers and 27 active water injectors. First production occurred in 1972, and waterflooding commenced in 1975 prior to the field average reservoir pressure falling below the bubblepoint, with present injection rates of 320,000 BWPD.
Critical and Sub-critical Oil/Gas/Water Mass Flow Rate Experiments and Predictions For Chokes
Authors: Schüller R. B. , Munaweera S. , Selmer-Olsen S. , Solbakken T. 
Published: December 2007

Summary
A large database on critical and subcritical flow through orifice-and cage-type chokes have been obtained in the Multiphase Flow Loop (MPFL) of Norsk Hydro Oil and Gas R&D Center in Porsgrunn, Norway. This work is an extension of the studies performed in 1999 (367 data points) by Schüller et al. (2003), making a total data set of 509 data points. The downstream separator pressure and temperature were kept at 8 bara and 50°C, respectively. The maximum upstream pressures were approximately 40 bara, giving a maximum pressure ratio of approximately 4.
The Hydro models (Schüller et al. 2003) show a very good agreement for prediction of mass flow rate, both for critical and subcritical flow conditions, with an average error of absolute values of 6.2% and a standard deviation of 8.9%. Comparisons with the models of Sachdeva et al. (1986) and Perkins (1993) show that the performances of these models are not as good as the Hydro model. The Sachdeva model and the Perkins model both have average errors greater than 22%, with standard deviations greater than 25%.
The Hydro models also seem to predict reasonably correctly the transition between subcritical and critical flow conditions.
Water Shutoff in Gas Wells: Proper Gel Placement Is the Key to Success
Authors: Wassmuth F. R. , Green K. , Hodgins L. 
Published: December 2007

SummaryThe objectives of water-shutoff treatments in gas wells suffering from water influx are to reduce water production and, at the same time, increase gas-production rates and producible gas reserves. Several field treatments, conducted under the umbrella of a research project focused on water abatement in gas wells, have demonstrated that a sequential gel/gas-injection technique in fractured gas reservoirs was successful in reducing water production and increasing gas production. Further efforts focused on improving gel placement in both fractured and matrix reservoirs to improve the treatment efficiency.Injectivity of the gelant was improved for injection into matrix reservoirs by either reducing the concentration of the highmolecular-weight polymer in the gelant formulation or by using a low-molecular-weight polymer.Gel placement was improved by displacing the gelant away from the near-wellbore region with semistable foam rather than with gas. Such displacement allows for improved gas production after the gel treatment.Laboratory-scale simulations were used to history match the coreflood results to calibrate the gelation and overdisplacement options in the simulations.Field-scale simulations demonstrated the merits of the proper gel-placement technique using a foam to displace the gelant away from the wellbore in matrix and fractured reservoirs.Optimized gel formulations in combination with the new over-displacement technique provide a treatment alternative for combatting 3D coning situations. This overdisplacement technique can also minimize the startup problems experienced in fractured gas reservoirs after gel treatments.
A Modified Spinning Drop Method for High-Temperature Applications
Authors: Handy L. L. , El-Gassier M. , Ershaghi I. 
Published: December 2007

Abstract
A constant-speed (3,600-rpm) spinning drop apparatus1 has been modified to measure interfacial tensions (IFT's) at elevated temperatures and pressures. The modification includes the addition of a temperature air bath and the development of a method to seal the fluids in the capillary tube. The modification described here is a very inexpensive and practical method that extends the application of the spinning drop to 302°F (150°C). This allows studies on the IFT properties of surfactant oil systems in high-temperature applications such as the use of additives in thermal recovery.
The air bath is made of a ¾-in. (1.9-cm) thick Marinite mix (an asbestos-free insulation) with a temperature rating as high as 600°C (1100°F). Uniform temperatures are maintained with flow mixing vanes. Temperature measurements are made with J-type thermocouples placed next to the capillary tubes. A schematic of the equipment is shown in Fig. 1.
The open ends of the capillary tubes are sealed with a high-temperature epoxy (Fig. 2). The epoxy used is Dexter Corp. product No. 9340. It hardens quickly and is capable of withstanding pressures up to 855.7 psi (5.9 MPa). The epoxy seal easily can be drilled out to permit the reuse of the tubes. During the placement of the fluids and the epoxy resin, an air gap is retained for thermal expansion of the fluids. The air gap also prevents direct contact between the fluids and the resin.
The Key to Predicting Emulsion Stability: Solid Content
Authors: Poindexter Michael K. , Chuai Shaokun , Marble Robert A. , Marsh Samuel C. 
Published: December 2007

Summary
Chemical demulsifiers are routinely added in the oil field to effectively resolve water-in-crude-oil emulsions. As used in the common bottle test, demulsifiers, in effect, probe or interrogate emulsion stability strength. Emulsion stability, in turn, is defined by no fewer than three parameters: water drop, oil dryness, and interface quality. All three parameters are direct outputs of the bottle test, and, collectively, all three provide a more complete picture of emulsion stability, as opposed to the use of any singular parameter.
By selecting a wide variety of demulsifiers and by performing a standardized bottle test, emulsion stability from a variety of sites can be quantified and compared. By coupling bottle test results with corresponding crude oil analytical data, fundamental questions concerning factors governing emulsion stability can be quantified. The results show that solid content, not asphaltene content or any other crude oil parameter investigated, is by far the best single predictor for gauging emulsion stability. Furthermore, statistical analysis through partition trees shows that emulsion stability is most aptly described using several crude oil parameters, as opposed to one single factor.