bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Environmental Corrections for Compensated Neutron Logs
Authors: Galford J. E. , Flaum C. , Gilchrist W. A. , Soran P. D. , Gardner J. S. 
Published: December 2007

Summary
The basic openhole responses and environmental correction algorithms for compensated neutron logging (CNL™) tools have been updated. The improved processing is based on an extensive set of laboratory formation measurements to which mathematical modeling calculations have been added. In all, the new algorithms include basic responses for the three principal formation matrix types and corrections for seven environmental effects and formation-fluid salinity.
A total of 467 laboratory formation measurements have been augmented with 245 data points generated through mathematical modeling. This data base has been used to define more accurately the effects on the tool response of variations in logging conditions from those considered standard in the laboratory. More accurate corrections for the effects of formation pressure, temperature, mudcake, natural or barite mud, and borehole salinity have been defined. Certain other effects depend on more than one parameter. For example, the effect of formation salinity is somewhat matrix-dependent; therefore, the corrections are handled differently for sandstone, limestone, and dolomite. The effect of tool standoff depends on the borehole size; consequently, the standoff correction is larger for larger boreholes.
The porosity crossplots and environmental correction charts based on the new algorithms represent a significant evolutionary improvement over previous techniques. They should be an important aid to the use and interpretation of neutron logs.
Vertical-Interference Pressure Testing Across a Low-Permeability Zone With Unsteady Crossflow
Authors: Wijesinghe Ananda M. , Kececioglu Ifiyenia 
Published: December 2007

Summary
Existing analytical models for interpreting vertical-interference pressure tests across the low-permeability zone in a three-layered reservoir usually assume transient radial flow in the high-permeability layers and pseudosteady vertical crossflow in the intervening tight zone. The neglect of vertical flow in the high-permeability layers and of radial flow in the tight layer requires that the permeability contrast between these layers be large. When this assumption is satisfied, however, it is also very likely that the pressure diffusivity in the tight layer is much smaller than that in the high-permeability layers. Thus, to be consistent, the flow across the tight layer must be treated as an unsteady diffusive process driven by the transient pressure changes occurring in the high-permeability layers.
In this paper, we extend the analysis of Ehlig-Economides and Ayoub by replacing their pseudosteady crossflow assumption with unsteady crossflow and interpret the crossflow response in terms of near- and far-boundary flow-response functions for the tight zone. The inclusion of unsteady crossflow requires one additional dimensionless parameter and results in a set of governing equations that are different from but similar to the equations of the dual-porosity, dual-permeability model with unsteady interporosity flow presented by Wijesinghe and Culham for naturally fractured reservoirs. As in the case of dual-porosity, dualpermeability reservoirs, the pressure response with unsteady crossflow is significantly different at early times from that for pseudosteady crossflow under practical conditions.
Exact and asymptotic solutions and type curves for the wellbore pressures at the upper and lower perforations are presented for flow-rate-specified vertical interference tests. The solutions account for different formation properties, wellbore storage, and skin factors of the two high-permeability layers and the formation properties of the tight zone. The impact of unsteady and pseudosteady crossflow model assumptions on the wellbore pressures and on the spatial distributions of fluid pressures and crossflow rates is examined in detail.
Analysis of Pressure Data From a Restricted-Entry Well in a Multilayer Reservoir
Authors: Yeh N. , Reynolds A. C. 
Published: December 2007

Summary
This work presents new semilog type curves for analyzing data obtained at a restricted-entry well completed in a multilayer reservoir where crossflow occurs between reservoir layers. Use of the new type curves along with standard semilog analysis of pseudoradial-flow pressure data makes possible a complete analysis of pressure data. Specifically, standard semilog analysis of pseudoradial-flow pressure data yields estimates of the total flow capacity and the total skin factor. The new type curves can then be used to estimate the real mechanical skin factor resulting from damage or stimulation, the flow capacity adjacent to the open (perforated) interval, and the effective average vertical permeability.
Prediction of Abrupt Reservoir Compaction and Surface Subsidence Caused By Pore Collapse in Carbonates
Authors: Smits R. M. M. , de Waal J. A. , van Kooten J. F. C. 
Published: December 2007

Summary
A new procedure has been developed to predict the abrupt in-situ compaction and the associated surface subsidence above high-porosity carbonate fields that show pore collapse. The approach is based on an extensive laboratory compaction study in which the effects of carbonate type, porosity, core preparation, pore saturant, horizontal/vertical stress ratio, and loading rate on pore-collapse behavior were investigated.
For a number of carbonate types, a trendline was established that describes the relationship between the porosity after collapse and the vertical effective stress. This trendline concept, in combination with existing subsidence models, enables reservoir compaction and surface subsidence to be predicted on the basis of wireline porosity logs. Static and dynamic elastic constants were found to be uncorrelated during pore collapse.
The position of the trendline depends strongly on carbonate type, pore saturant, loading rate, and stress ratio. Therefore, procedures are given to derive the correct in-situ trendline from laboratory compaction experiments.
Correlation of Interfacial Tension of Hydrocarbons
Authors: Hough E.W. 
Published: December 2007

Abstract
Correlation of interfacial tension of the methane-n-pentane and methane-n-decane systems was made by Hough and Stegemeier by the use of the Weinaug and Katz equation. The methane-n-heptane and ethylene-n-heptane systems were investigated by the authors. Additional systems taken from the literature were the methane-propane system by Weinaug and Katz, the methane-n-butane system by Pennington and Hough, and the n-butane-carbon dioxide system by Brauer and Hough. These systems were analyzed by the Weinaug-Katz equation and the Sugden equation on the IBM 1620 II computer using a regression analysis program. Parachor and exponent values for each component and system were determined. The experimental work was close to the critical point of the light component in the n-butane-carbon dioxide and ethylene-n-heptane systems, between the critical points of the light and heavy components in the methane-n-pentane, methane-n-heptane and methane-n-decane systems, and close to the critical point of the heavy component in the methane-propane and methane-n-butane systems. An empirical formula was developed to find a value of the constant B in the Sugden equation for binary hydrocarbon systems from the parachor values of the two components. interfacial tension for binary hydrocarbon Systems was found to be a direct function of liquid-vapor phase density difference in the same manner as a single-component system.

Discussion
Interfacial tension may be defined as the measure of the specific free surface energy between two phases having different compositions. The interfacial tension (IFT) for a binary system may be predicted for any temperature and pressure if the mole fractions and molal volumes of the liquid and gaseous phases are known. One method of correlating IFT was proposed by Weinaug and Katz and modified by Hough and Stegemeier. The modified formula is:
(1)
where y = interfacial tension, dynes/cmP1 = parachor of the first componentP2 = parachor of the second componentx1, x2 = mole fractions in the liquid phasey1, y2 = mole fractions in the vapor phaseVL, Vv = molal volumes (cu ft/lb mole)1/62.43 = conversion factor, lb/cu ft to gm/ccK = exponent of the parachor relation and subscriptsL = liquidV = vapor1 = component 12 = component 2. In a binary system, there are two degrees of freedom; that is, the values of x1, x2 y1, y2, VL and Vv are determined at any particular temperature and pressure. Therefore, for each temperature and pressure at which an experimental value of IFT was measured, the values of x1, y1, VL and Vv were found, and the following values were calculated:
(2)
(3)
SPEJ
P. 345ˆ
Hot-Water and Steamflood Laboratory Experiments Under Reservoir Conditions
Authors: Quettier L. , Corre B. 
Published: December 2007

SummaryHot waterfloods at four temperatures (between 30 and 240°C [86 and 464°F]) and a steamflood were performed on the same porous medium (compacted silt) under reservoir conditions. Dynamic isothermal displacements were interpreted with a thermal simulator, taking into account capillary end effects. The corresponding oil/water relative permeability curves were obtained by matching observed pressure drop and oil production. Results show that temperature influences the endpoint saturations but not the shape of the curves.The steamflood experiment was carried out with an adiabatic core holder. The oil recovery was 70% higher than the recovery by the hot waterflood at the same temperature (240°C [464°F]). Oil stripping and production of a large amount of CO2 caused by dissolution of carbonates were pointed out. In the numerical interpretation of this experiment, we used oil/water relative permeabilities to provide the three-phase oil relative permeability. These experiments allow a better understanding of steam displacement mechanisms and supply essential data for numerical interpretation of a steamflood pilot.
Laboratory Evaluation of a Crude-Oil-Sulfonate/Nonionic-Cosurfactant Micellar Fluid
Authors: Kremesec V. J. , Raterman K. T. , Taggart D. L. 
Published: December 2007

Summary
Phase behavior, interfacial tension (IFT) measurements, fractionation studies, and core tests have been used in the formulation of a crude-oil-sulfonate (CROS)/ethoxylated-alcohol micellar fluid for application in a changing ionic environment that attains a relatively high hardness concentration as a result of ion exchange. By varying the hydrophile/lipophile balance (HLB) of the nonionic cosurfactant, phase behavior can be shifted from lower to upper phase and the optimum can be found. It is shown that the solubilization of oil and brine and the value of the optimum can be controlled further by blending different nonionic surfactants with CROS samples whose properties were altered by controlling variables in the manufacture. Effects of such system variables as surfactant and hardness concentration and the ratio of CROS/nonionics have a significant effect on phase behavior. The IFT vs. solubilization parameter correlation was in reasonable agreement with that of Huh1 and is shown.to hold over a wide range of surfactant and hardness concentrations, but the intercept is different for each CROS/nonionic pair. IFT’s and phase behavior from core-test effluents are shown to agree with the phase-behavior studies. Fractionation phase-behavior studies indicate that chromatographic separation will affect the process significantly only if oil is inefficiently displaced; this is supported by core tests. Excellent oil recovery was attained in Berea over a wide range of concentrations and HLB’s, and with small slugs. Oil recovery in field core tests was poor because of stringent capillary desaturation requirements.
Microemulsion to Liquid-Crystal Transition in Two Anionic Surfactant Systems
Authors: Hackett J. L. , Miller C. A. 
Published: December 2007

Summary
The phase behavior of two anionic surfactant systems, one containing a commercial alpha olefin sulfonate (AOS) and the other containing pure sodium dodecyl sulfate (SDS), was determined in the region where a transition from microemulsion to liquid-crystalline phases occurred with decreasing alcohol content and temperature. A general and rather complex pattern of phase behavior was seen that included a four-phase coexistence region of brine, microemulsion, lamellar liquid crystal, and oil, and two three-phase regions containing both microemulsion and liquid crystal. In much of the four-phase region, complete separation of the phases did not occur even after equilibration for 1 year or more at constant temperature. Instead, oil and brine were observed to coexist with stable birefringent dispersions that (for some compositions at least) apparently contained three phases: microemulsion, liquid crystal, and oil. Solubilization of brine was uniformly low in the phases making up the dispersions. The dispersions in the SDS system exhibited non-Newtonian behavior with apparent viscosities in the range of 50 to 100 mPa·s [50 to 100 cp] at a shear rate of 10 seconds−1. Microemulsion viscosities in the same system were about an order of magnitude lower. No plugging or other adverse behavior was seen when such dispersions flowed at a velocity of 10−5 m/s [3 ft/D] through a model porous medium having pore sizes comparable with those in reservoirs. In preliminary experiments, selected dispersions appeared to be capable of displacing oil from the same model porous medium.
Methods for Predicting Wax Precipitation and Deposition
Authors: Weingarten J. S. , Euchner J. A. 
Published: December 2007

Summary
Removal of wax from wells and flowlines can account for significant additional operating costs. To evaluate these potential costs, the operating conditions that allow waxes to precipitate in the wellbore must be identified, and deposition rates must be estimated to determine the costs associated with removal of wax deposits. Presented in this paper are laboratory and analytic methods that can be used to estimate both The critical operating conditions and the deposition rates. The laboratory tests and analysis presented may be used to characterize any type of oil.
An Improved Method for Calculating Bottomhole Pressures in Flowing Gas Wells With Liquid Present
Authors: Peffer J. W. , Miller M. A. , Hill A. D. 
Published: December 2007

Summary
A method is presented for calculating bottomhole pressures (BHP's) from wellhead measurements in flowing gas wells with liquid present in the well stream. This method, a modification of existing methods, is based on including the contribution of entrained liquid to gravitational gradients. The study also includes evaluation of effective roughness factors evident from actual flowing pressure data.
The proposed method was tested vs. both a two-phase flow model developed by Govier and Fogarasi1 and currently applied methods based on dry-gas wells. The method was also tested with Govier and Fogarasi's data from 94 flowing wells and with data from 50 wells from the public files of the Texas Railroad Commission. The new method compared favorably with the two-phase flow model and was superior to currently applied methods.
Analysis and Evaluation of Alternative Concepts in Modeling Tarmats To Conform to Laboratory Investigations and Field Conditions
Authors: Tripathy B. 
Published: December 2007

Summary
Black-oil reservoir simulators are universally formulated to handle a maximum of three different fluid phases—i.e., oil, water, and gas. The phase identity of tar, occurring in concentrations called "tarmats" within or marginal to petroleum reservoirs, varies widely from highly viscous hydrocarbon fluid to near-solid material. In black-oil modeling of tarmat reservoirs, therefore, considerable challenge is posed in characterizing tar as a drastic departure from the three fluid phases. No published literature provides concentrated details on tarmat modeling with an emphasis on comparative analysis and adaptability of different state-of-the-art modeling techniques. This paper compares the two approaches adopted most often to characterize tar in a model— i.e., as a highly viscous hydrocarbon fluid and as a relatively impermeable rock matrix. Other less commonly used methods that also may be reasonable are not discussed.
Low-Resistivity Hydrocarbon-Bearing Sand Reservoirs
Authors: Zemanek Joe 
Published: December 2007

Summary
It has been found that significant amounts of water-free hydrocarbons can be produced from sandstone reservoirs that have water saturations greater than 50%. From comprehensive core and log analyses, the sands were found to have high surface areas that immobilize large amounts of water. The actual water saturations can be high, but water-free hydrocarbons will be produced.
Oil Production Using Pumped Multiphase Systems
Authors: Leggate J. S. , Iball W. N. , McJarrow S. 
Published: December 2007

Summary
This paper reviews the production system options available for the development of remote oil fields by unmanned facilities at the remote site. Various types of artificial-lift techniques, surface multiphase fluid pumping, and flowline systems are compared and the attributes of each system illustrated, including an evaluation of the useful operational envelope of each system and its economics.
Improved Disposal-Water Treatment at Bahrain Oil Fields
Authors: Murti D. G. K. , Al-Maskati A. H. , Sood L. K. 
Published: December 2007

Summary
Bahrain's Awali oil field is one of the oldest in the Arabian Gulf region. The recent sharp increase in produced water cut at Awali has resulted in higher oil carry-over in the produced water, which is currently disposed of in an aquifer about 700 ft [210 m] deep. The steps taken by Bahrain Natl. Oil Co. (Banoco) and the problems encountered in improving the quality of effluent are described in this paper.
Deltas
Authors: Richardson J.G. , Sangree J.B. , Sneider R.M. 
Published: December 2007

Technology Today Series articles provide useful summary informationon both classic and emerging concepts in petroleum engineering. Purpose: To provide the general reader with a basic understanding of a significantconcept, technique, or development within a specific area of technology.
A major part of the oil produced from sandstone reservoirs has been fromancient delta systems. Because of their importance and their variedcharacteristics, deltas are the subject of a three-article series. This initialarticle discusses the general building processes of deltas. Future articleswill focus on characteristics of sand-rich, high-energy deltas and mud-rich, low-energy deltas. Deltas form near the mouths of rivers that dischargesediments into oceans or other bodies of water. Two main stratigraphic eventsoccur in the building processes of all deltas:sediments are carried anddeposited in channels andthe sediments arc then reworked by waves andtides.
All materials reaching the delta mouth generally will be reworked it thesediment volume is low relative to the energy levels of the waves and tides. Inhigh-energy environments the clays and silts are eroded. leaving sand-richdeposits. Conversely, mud-rich deposits are left if the sediment flow rates arehigher than ocean flow rates. High-energy sand deltas have few activedistributry channels: these channels are meandering or braided. Shorelines arecontinuous sands. A good modern example is the sand delta now forming at themouth of the Nile River (Fig. 1). Mud-rich delta have many straight to sinuouschannels that form frequent branches. Shorelines are discontinuous stretches ofsands and muds. The best modern example is the Mississippi River delta (Fig.2). Sand bodies deposited, formed, and left in different parts of a delta havedifferent characteristics. For example, sand bodies deposited upstream in adistributary channel are not reworked by ocean currents, and have the coarsestmaterial at the base and finer sand, silt, and clays toward the top. At thechannel mouth and near shore, sand reworked and moved by tides forms bars thatgenerally run parallel to the shoreline. The bars have the coarsest material attheir tops. Farther offshore, sands are spread and deposited in thin sheets bycurrents that fan out from a channel mouth. These thin sheets of sand areusually interspersed with thin layers of shale that settle in the water anddrape over the sands during periods of lower river flow rates. Fig. 3 showsseveral such near-shore areas.
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Mud-Rich Deltas
Authors: Richardson J.G. , Sangree J.B. , Sneider R.M. 
Published: December 2007

Technology Today Series articles provide useful summary informationon both classic and emerging concepts in petroleum engineering. Purpose: To provide the general reader with a basic understanding of a significantconcept, technique, or development within a specific area of technology.
Mud-rich deltas form when the sediments brought in by the rivers aredeposited faster than they can be reworked by basin currents. Compared withsand-rich deltas, which are at the other end of the spectrum of delta types, mud deltas contain more silt and shales in the river-mouth bars and delta-frontsheet sands and have poorer continuity among the various sand bodies. Muddeltas characteristically have many straight distributary channels that branchfrequently. Sands deposited and preserved in the channels have the samedistributions as the sand-rich deltas discussed in Ref. 3. The coarsest, cleanest sand is left at the base. Finer sand, silt, and clay are left at thetop. The channel sands also become progressively thinner and of poorer qualitytoward the channel mouth in mud deltas, as in sand-rich deltas. Mud deltas canbuild very rapidly. For example, the modem Mississippi delta complex, formedduring the past 5,000 years, now encompasses hundreds of square miles, as shownin Fig. 1. This rapid building process often leaves large areas of mud-richdeposits, which prevent communication among the various bodies of channelsands, bars, and sheet sands. The distributary channel that cuts into previousdeposits of bar sands as the delta builds seaward usually has clay/silt bedslining the channel boundary, as shown in Fig. 2. These act as barriers to fluidflow. Along the shore and offshore, the sheet sands and river-mouth barsdeposited during a given sequence are often isolated by large areas containingbeds of silt and clay. The prodelta sheet sands are typically interbedded withsilts and clays (see Fig. 3). These sand beds may be less than 1 in. [2.5 cm]thick, may appear as water-saturated sands on resistivity logs, and yet may beprolific oil producers. Fig. 4 illustrates the conceptual geologic model of amud-rich delta. High-quality sands are distributed in the channels and inriver-mouth bars similar to those found in sand-rich deltas. The principaldifferences between the mud-rich and sand-rich delta models are the lowerquality of the bars and sheet sands, the poorer lateral continuity, and thelarge areas along the shoreline and offshore that are covered by beds of siltand clay. Oil recoveries and sweep efficiencies in mud-rich deltas are expectedto be less than those in sand deltas. Problems in locating wells and developingprojects are more critical than in sand-rich deltas because of the poorercommunication among sand members. Location of pilot-test areas for evaluationof additional recovery processes requires special studies by all disciplinesinvolved in describing the reservoir and designing the recovery process.
P. 334
Improved Thermoplastic Materials for Offshore Flexible Pipes
Authors: Dawans F. , Jarrin J. , Hardy J. 
Published: December 2007

Summary
Long-term aging tests representative of field operating conditions have been conducted on various thermoplastic materials proposed for the inner tube of flexible pipes for offshore drilling and production applications. In particular, experimental data are provided about the changes of the mechanical properties of selected thermoplastic materials owing to optimized formulation when the pipes are exposed over time to crude oil in the presence of gas and water.