bluuebunny/crossref_metadata_2025_split huggingface dataset:
Representing Steam Processes With Vacuum Models
Authors: Stegemeier G. L. , Laumbach D. D. , Volek C. W. 
Published: December 2007

Abstract
Scaled models of steam processes have contributed significantly to the design and implementation of many field projects. These models provide a means of answering pertinent questions, including the effect of (1) injection rate, (2) production pressure, (3) completion interval, (4) pattern size and type, (5) aquifers, (6) heterogeneities, and (7) steam quality.
Parameters are presented for scaling up physical-model results to full scale and for relating one oil field to another. These relationships are generated by casting the governing equations in dimensionless form. A set of similarity parameters then are determined by inspectional analysis. In physical models, unfortunately, it is not possible to match all similarity parameters. Consequently, based on engineering judgment, a set containing a reduced number of parameters, called scaling parameters, is generated that generally can be matched between scaled model and field prototype.
Techniques to implement this scaling are discussed, including a description of the laboratory models, typical materials, and procedures for conducting the experiments. Results of model studies for Mt. Poso and Midway Sunset prototypes are presented.
Semi-Analytical Model for Thermal Effect on Gas Well Pressure-Buildup Tests
Authors: Fan L. , Lee W. J. , Spivey J. P. 
Published: December 2007

Summary
This paper presents a semi-analytical wellbore/reservoir model1 that can describe general wellbore effects, especially the thermal effect, on high-temperature gas well pressure-buildup tests. A numerical simulator has been developed from the model. Using different combinations of wellbore and reservoir parameters, the simulator generated curve shapes that differed with wellbore thermal effects. Many of the curve shapes have been observed in the field.2,3 Using the results from this paper, engineers can distinguish between general wellbore effects and reservoir behavior in the pressure data, which will make the interpretation more accurate. Also, with the help of the simulator developed from the model, engineers can effectively design gas well pressure-buildup tests by running the simulator to determine the minimum time required to obtain the data not distorted by the wellbore effects.4
The governing equations of the wellbore model are based on mass, momentum, and energy balances for single-phase gas in one-dimensional space. The gas pressure/volume/temperature correlation was also used. Different flow regimes (laminar, transitional, and turbulent) inside the wellbore are modeled for calculating the friction factor. As one boundary condition, a simple analytical reservoir model was connected to the wellbore model at the bottomhole using Duhamel's principle. Heat-loss effects account for forced-convectional heat transfer inside the tubing, heat conduction between tubing and formation, natural convection and radiation heat transfer of annular fluid, and transient heat flow in the formation. Pressure, temperature, velocity, and gas properties inside the wellbore can be predicted at any depth during an entire pressure-buildup test. Variable wellbore storage, momentum, and thermal effects can be simulated.
Estimation of Hydrocarbon Viscosity With Multiple-†e, Dual-†wMRIL Logs
Authors: Chen Songhua , Georgi D. T. , Olima Oscar , Gamin Hector , Minetto J. C. 
Published: December 2007

SummaryWe report a case study of using nuclear magnetic resonance (NMR) multiple-te, dual wait-time (tw) log acquisitions for quantitative characterization of San Jorge Basin reservoir oil viscosity. Previously, dual-tw logs have been used to discern gas and oil from water, while dual-te logs have been used as a qualitative light oil indicator. Although theoretically simple, quantitative determination of viscosity from dual-te logs is complicated by several factors, including poor signal-to-noise ratio, difficulties in separating oil from water, and the uncertainty of internal gradient strength. In the present study, multiple-te acquisitions of dual-tw logs were used to isolate the oil from the water signal. The values of viscosity of the reservoir fluids can be estimated from either intrinsic T2 or T1. In estimation of the apparent T2, we used a model that does not explicitly require knowledge of the internal gradient, thereby minimizing the effects arising from the uncertainty of the internal and tool gradient strengths. Because Tj and intrinsic T2 are estimated independently, the degree of agreement between the two values provides an indication of the reliability of the two estimates. The main example in the study of four pay zones was thought to contain viscous oil. However, our analysis indicated that the viscosity values of the oil are less than 5 cP. The predictions have been substantiated by production of light hydrocarbons from the three zones that have been perforated. Further, a good agreement is obtained for the viscosity estimates based on NMR log data and laboratory pressure/volume/temperature (PVT) analysis.
Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability
Authors: Mott R. E. , Cable A. S. , Spearing M. C. 
Published: December 2007

SummaryWell deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region.This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators.
A Method of Analyzing Performance of Gravel-Pack Completions in Seria Field, Brunei
Authors: Jones R.W. , Thorp G. 
Published: December 2007

A method of evaluating gravel-pack completions has been developed that allows the use of small samples of observed data with large variance to be checked against theoretically derived values-in this case, the normalized productivity indices. The results give insight into the mechanics of productivity indices. The results give insight into the mechanics of impairment and lend support to previously suspected causes of impairment.

Introduction
Brunei Shell Petroleum (BSP) Co. Ltd.'s Seria field produces from shallow, unconsolidated, depleted produces from shallow, unconsolidated, depleted sands. The majority of wells require sand control during their production lifetime, and over the years many gravel packs, both openhole and inside packs, have been placed. The productivities achieved by the various gravel-pack repair techniques have been difficult to analyze due to the few reliable data points and wide range of values.
Therefore, a statistical test was used to compare actual productivity indices (PI's) before and after gravel packing with theoretically derived PI's. The effects on productivity of different types of gravel packing and different gravel sizes also were compared. packing and different gravel sizes also were compared.To do tills it was necessary to establish theoretical values for the specific PI's (RB/D/psi/ft) of the various pack configurations using Seria reservoir data and completion sizes.
The changes in well productivity as a result of gravel packing were calculated theoretically for the various gravel-pack types and placement methods by considering the individual pressure drops through the sequential resistances to flow imposed by gravel and liner and by considering these resistances as apparent skin factors in the flow equation.
The equations were developed using typical Seria field reservoir data and completion sizes.

Gravel-Pack Types
There are two basic types of gravel packs used in BSFs Seria field: openhole gravel packs (OHGP) and inside gravel packs (IGP).

Openhole Gravel Packs
An OHGP consists of a slotted liner or wire-wrapped screen in an open hole, packed around with gravel. The openhole section normally is underreamed to increase the effective wellbore radius and pack thickness. This is achieved simply in a new completion; in an existing completion this requires milling a window in the casing, sidetracking, underreaming, and then gravel packing. This is referred to as a sidetracked underreamed gravel pack (STUGP). pack (STUGP).OHGP's allow completions with little apparent PI impairment and not too severe PI decline with continuing production. It will be shown later that in practice severe pack impairment does occur but practice severe pack impairment does occur but largely is offset by the increase in effective wellbore radius as a result of the underreaming.
JPT
P. 496
Reservoir Characterization of Ekofisk Field: A Giant, Fractured Chalk Reservoir in the Norwegian North Sea-History Match
Authors: Agarwal B. , Hermansen H. , Sylte J. E. , Thomas L. K. 
Published: December 2007

SummaryThe Ekofisk reservoir is a high porosity, low matrix permeability naturally fractured chalk. Fluid flow is largely governed by the distribution, orientation, and interconnectivity of the natural fracture system associated with complex structure and reservoir distribution. Because of the impact heterogeneity has on preferential fluid-flow direction, significant attention was given to capturing as much of the intrinsic heterogeneity as possible, both laterally and vertically, in the new three-dimensionally geological model. A non-uniform simulation mesh was defined for the fluid-flow model with a grid size of 450 ft × 450 ft in the crestal area of the field and increasing towards the flanks. A flow-based upscaling technique was then applied to preserve the heterogeneity from the geological to the fluid-flow model. Because of the complexity of the Ekofisk field, with its numerous faults and fracture networks, anisotropy was one of the primary attributes calibrated to achieve an individual well and field history match. However, faults and fault sealing factors, vertical permeability, pseudorelative permeability curves, bubblepoint pressure correlations, local permeability, and rock compressibility were also key parameters in the history match, and are presented in this paper. A brief discussion on the preliminary implementation of water-induced compaction is included.
Chemical Transport in Porous Media With Dispersion and Rate-Controlled Adsorption
Authors: Satter A. , Shum Y. M. , Adams W. T. , Davis L. A. 
Published: December 2007

Abstract
Because of the importance of chemical flooding operations, the mechanisms of chemical dispersion and adsorption in porous media are of increasing interest to the petroleum industry. This paper presents a mathematical model for simulating presents a mathematical model for simulating chemical transport phenomena in porous rocks; these phenomena include dispersion and either Langmuir phenomena include dispersion and either Langmuir equilibrium or rate-controlled adsorption.
The accuracy of this numerical model was verified by comparing the calculated results with those obtained by analytical solutions for a number of limiting cases. The effects of dimensionless dispersion, adsorptive capacity, flow rate, and kinetic rate groups controlling dispersion/adsorption mechanisms were investigated. The utility of the model was demonstrated further by matching experimental results. When adsorption of a chemical is rate-controlled or time-dependent, core flood data obtained at times much shorter than reservoir residence times can lead to a serious underestimation of chemical requirements for the field projects.
Computer Design of Dense-Phase Pipelines
Authors: Gregory G.A. , Aziz K. , Moore R.G. 
Published: December 2007

This paper demonstrates the importance of performing simultaneous temperature and pressure profile calculations when designing pipelines for single dense-phase fluids. The sensitivity of the pressure and temperature profiles to design parameters is examined and discussed in detail. profiles to design parameters is examined and discussed in detail. Introduction
The pressure and temperature changes for single-phase flow along a pipeline are described by the following differential equations:
dp p dv g dZ 2fv2p--- + -- v ---- +p --- ----- + ------- = 0,.......(1)dL gc dL gc dL gcd
dh 1 dv g dZ 1 dQ---- +--- v --- + --- ---- + --- --- = 0,......(2)dL gc dL gc dL w dL
where the following functional relationships must be specified.
p =f(p, T)......................................(3)h =f(p, T)......................................(4)=f(p, T)......................................(5)f =f(N Re, k/d).................................(6) wheredvpN Re = ----.......................................(7)
The expressions for p, h, and may be either analytical or graphical, and their complexity depends on the type of fluid being considered. Many different expressions for the friction factor, f, are also available; some are general and some are for specific pipeline and fluid systems.
For hand calculations, Eqs. 1 and 2 must be integrated over the length of the pipeline to obtain analytical expressions for pressure and temperature as functions of length, flow rate, fluid properties, and pipe-to-sod interactions. This poses problems for the general case becausethe equations are nonlinear and coupled,the fluid properties depend on pressure and temperature in a complex manner, andthe friction factor is a nonlinear function of viscosity, density, and velocity.
Thus, to obtain the analytical expressions, various simplifying assumptions must be made. This procedure has resulted in many design equations that apply to particular systems and are useful when the inherent assumptions are valid. However, in some cases, particularly when dealing with a fluid near the critical region particularly when dealing with a fluid near the critical region (i.e., dense fluid state), variations in the physical and thermodynamic properties are rather complex and no available integrated form of the equations can be used safely.
If adequate information is available about the relationships expressed by Eqs. 3 through 6, Eqs. 1 and 2 can be integrated numerically to any desired accuracy without making any simplifying assumptions. Clearly, this approach is only practical when a digital computer is available, but it is completely general and may be followed for any single-phase flow in a pipe (gas, liquid, or dense phase). This procedure is the basis of the computer program used to perform all calculations discussed later. Extension of the approach to multiphase gas-liquid flow in pipes and structure of the program are discussed elsewhere.
P. 40
Development of a New, Compact Electrostatic Coalescer Concept
Authors: Urdahl O. , Nordstad K. , Berry P. , Wayth N. , Williams T. , Bailey A. , Thew M. 
Published: December 2007

Summary
The demand for more cost-effective field developments has led to a substantial focus on separation equipment that reduces weight and deck space. Of particular concern are field developments with subsea production templates and multiphase transportation to existing field installations. Additionally, environmental aspects concerning the use of large amounts of chemical demulsifiers are crucial these days.
This paper presents a new compact electrostatic coalescer (CEC) that has the capability to reduce both weight and size, and to eliminate the use of chemical demulsifiers, in some cases.
The basic principle of Performance of the laboratory version of the CEC is discussed with respect to emulsion properties, flow rate, applied voltage, and residence time in the electric field. Performance is quantified using both a laser-particle and droplet-size analyzer and a Hamamatsu image-analysis system. Some results from a prototype test on live crude are also given.
Laboratory Monitoring of Surfactant Imbibition With Computerized Tomography
Authors: Chen H. L. , Lucas L. R. , Nogaret L. A. D. , Yang H. D. , Kenyon D. E. 
Published: December 2007

Summary
Oil production from fractured reservoirs can occur by spontaneous water imbibition and oil expulsion from the matrix into the fracture network. Injection of dilute surfactant can recover additional oil by lowering oil/water interfacial tension (IFT) or altering rock wettability, thereby enhancing countercurrent movement and accelerating gravity segregation. Modeling of such recovery mechanisms requires knowledge of temporal and spatial fluid distribution within porous media. In this study, dilute surfactant imbibition tests performed for vertically oriented carbonate cores of the Yates field were found to produce additional oil over brine imbibition. Computerized tomography (CT) scans were acquired at times during the imbibition process to quantify spatial fluid movement and saturation distribution, and CT results were in reasonable agreement with material-balance information. Imbibition and CT-scan results suggest that capillary force and IFT gradient (Marangoni effect) expedited countercurrent movement in the radial direction within a short period, whereas vertical gravity segregation was responsible for a late-time ultimate recovery. Wettability indices, determined by the U.S. Bureau of Mines (USBM) centrifuge method, show that dilute surfactants have shifted the wetting characteristic of the Yates rocks toward less oil-wet. A numerical model was developed to simulate the surfactant imbibition experiments. A reasonable agreement between simulated and experimental results was achieved with surfactant diffusion and transitioning of relative permeability and capillary pressure data as a function of IFT and surfactant adsorption.
Mars Debottlenecking Project
Authors: Curole M. A. , Turley A. J. 
Published: December 2007

Summary
The Mars installation consists of a four-block unit with a tension leg platform (TLP) installed in Mississippi Canyon Block 807. The discovery well was drilled in 1989. Development studies were conducted from 1990 through 1992 with project-fabrication funding occurring in the fall of 1993. A 24-well dual-casing-riser TLP in 2,933 ft of water was approved. The facility was designed originally to process 100,000 B/D oil and 110 MMscf/D gas. Maximum individual well rates were estimated at 11,000 B/D oil. During the fabrication phase of the project in 1995, it became clear that completion technology advances had increased individual well production potential far beyond the 11,000-B/D-oil benchmark, and the ultimate TLP production potential would exceed the topsides nameplate capacity. A study was undertaken to debottleneck the topsides to handle unconstrained production rates. The study evaluated all phases of the production facility impacted by increased production. This paper presents evaluated phases of the production facility debottleneck, summarizes modifications to the facilities at the TLP integration site, and reviews the use of several new and innovative technologies. Facilities systems debottlenecked included high-rate production flowlines, oil treating, compression units, dry-oil sales pumps, utility, flare, and gas dehydration.
Enhanced 2D Proppant-Transport Simulation: The Key To Understanding Proppant Flowback and Post-Frac Productivity
Authors: Smith M. B. , Bale A. , Britt L. K. , Hainey B. W. , Klein H. K. 
Published: December 2007

It has been assumed that along with fluid viscosity and pump rate, gravity dominates final proppant placement in hydraulic fractures. Results here, based on detailed multiphase-flow modeling, show that other factors such as slurry rheology (effect of adding proppant on slurry viscosity), fluid loss and layered fluid loss, and vertical fracture-width variations often are more important than gravity in controlling placement.AbstractThe goal of a hydraulic-fracture treatment is to create a large flow area exposed to the formation and connected to the wellbore along a conductive path. The only goal of hydraulic-fracture models is to predict this final proppant placement accurately. Most theoretical, modeling, and experimental efforts in this area have focused historically on understanding and predicting only gravity effects on proppant placement.However, for proppant-laden, viscous fluid or slurry flowing along a fracture, other forces are always more important than gravity, and can easily cause proppant to move upwards, both during pumping and fracture closure.A differential-fracture closure occurs when a fracture growing vertically penetrates zones with higher or lower closure stress. After shut-in, higher stress zones "close first." This forces any proppant-laden slurry covering these zones (at shut-in) to migrate to low stress zones where fracture width is greater, and can easily lead to "upward" proppant movement as fracture-closure stress generally decreases with depth. After shut-in of a propped fracture treatment all fluid must leak off into permeable formations penetrated by the fracture. Until closure, viscous fluid continues to transport proppant (possibly upward) toward fluid-loss layers, often corresponding to "pay." As proppant is introduced to fluid, the resulting slurry has a higher density and tries to move downward. However, solids also act to increase viscosity, and more viscous slurry prefers the wide middle of a fracture. This serves to keep proppant near the middle of the fracture, often in the pay zone.This paper discusses the combined effect of these forces on proppant placement in a context of post-frac analysis of several field treatments. Analysis used a fracture model including "rigorous," numerical, 2D material transport, and the often-unexpected results are compared with supporting evidence from post-frac well performance. In many instances, the combined effect of proppant-placement forces is beneficial, with more proppant placed across the pay than suggested by simple models. In other cases, post-shut-in proppant redistribution can (and did) cause catastrophic job failure.
Computer Simulations of Proppant Transport in a Hydraulic Fracture
Authors: Mobbs A. T. , Hammond P. S. 
Published: December 2007

SummaryEquations of motion of a slurry in a narrow slot, such as a hydraulic fracture, are presented and solved numerically to obtain an estimate of the amount of gravity-driven vertical motion of proppant that can occur within a fracture during placement.Two types of gravity-driven motion are studied: settling of heavy-proppant particles; and convective proppant transport, which refers to the motion driven by large-scale density differences between regions of different proppant concentration.Computer simulations are performed using realistic parameter values. In particular, the vertical motion of proppant in a slurry in which proppant particles are uniformly distributed across the fracture width (referred to as homogeneous flow) is compared with that in a slurry in which some unspecified, but rapid, process has caused all proppant to migrate across the fracture width into a close-packed sheet at the fracture center (referred to as sheet flow).In addition to considering a constant channel width, we also investigate the effects of an elliptic-fracture cross section on proppant placement. This fracture shape is predicted by idealized fracture propagation models such as the Perkins-Kerns-Nordgren (PKN) model.Main conclusions are that during placement:Proppant settling and convection can occur under practical conditions; Convection rates are slightly greater in sheet flow than in homogeneous flow, and settling is greatly enhanced in sheet flow. Overall, settling in sheet flow gives the worst vertical motion of proppant. Settling and convection in homogeneous flow cause no problems under conditions considered in this paper; In elliptic fractures, heavy, proppant-laden slurry can override earlier-pumped lighter pad (zero solids) under most fracturing conditions.