bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Fluid Saturation on Waves in Porous Rock and Relations to Hydraulic Permeability
Authors: Nur Amos M. , Walls Joel D. , Winkler Kenneth , DeVilbiss John 
Published: December 2007

Abstract
Detailed and very accurate measurements of compressional Vp and shear Vs wave velocities and their attenuation in dry, partly saturated and fully saturated clay-bearing sandstone were carried out at 20, 145, and 198°C, under variable confining and pore pressures.
The velocity results show that water saturated rock has high Vp and relatively low Vs not only at room temperature but also at 145 and l98°C. Varying the pore pressure reveals that the transition from the fully saturated to the dry state involves a gradual transition of Vs and a very irregular transition of Vp – with a minimum in Vp relative to either the dry or the fully saturated cases.
The attenuation of S and P waves – Qs−1 and Qp−1, respectively - shows similar patterns: in dry rock, both Qs−1 and Qp−1 are low. In fully saturated rock, Qp−1 is low and Qs−1 is high. In partly saturated rock, Qs−1 changes gradually with saturation, but Qp−1 shows a very strong maximum-suggesting strong energy dissipation. The same behavior is observed at 145°C, with the steam/hot-water transition. It was also found that attenuation of shear waves increases with permeability in some sandstones, consistent with squirting attenuation mechanism.
The results suggest diagnostic characteristics for determining the degree of saturation in situ from seismic logs, with particular applicability to evaluation of steam content in geothermal reservoirs and of gas content in oil reservoirs.
Neural Network Approach Predicts U.S. Natural Gas Production
Authors: Al-Fattah S. M. , Startzman R. A. 
Published: December 2007

Summary
The industrial and residential market for natural gas produced in the United States has become increasingly significant. Within the past 10 years, the wellhead value of produced natural gas has rivaled and sometimes exceeded the value of crude oil. Forecasting natural gas supply is an economically important and challenging endeavor. This paper presents a new approach to predict natural gas production for the United States with an artificial neural network (NN).
We developed an NN model to forecast the U.S. natural gas supply to 2020. Our results indicate that the U.S. will maintain its 1999 production of natural gas until 2001, after which production increases. The network model indicates that natural gas production will increase by an average rate of 0.5%/yr from 2002 to 2012. This increase will more than double from 2013 to 2020.
The NN was developed with a large initial pool of input parameters. The input pool included exploratory, drilling, production, and econometric data. Preprocessing the input data involved normalization and functional transformation. Dimension-reduction techniques and sensitivity analysis of input variables were used to reduce redundant and unimportant input parameters and to simplify the NN. The remaining parameters included data from gas exploratory wells, oil/gas exploratory wells, oil exploratory wells, gas depletion rate, proved reserves, gas wellhead prices, and growth rate of the gross domestic product. The three-layer NN was successfully trained with yearly data from 1950 to 1989 using the quick-propagation learning algorithm. The NN's target output is the production rate of natural gas. The agreement between predicted and actual production rates was excellent. A test set not used to train the network and containing data from 1990 to 1998 was used to verify and validate the network prediction performance. Analysis of the test results showed that the NN approach provides an excellent match with actual gas production data. An econometric approach, called stochastic modeling or time-series analysis, was used to develop forecasting models for NN input parameters. A comparison of forecasts between this study and another is presented.
The NN model has use as a short-term as well as a long-term predictive tool for natural gas supply. The model can also be used to quantitatively examine the effects of the various physical and economic factors on future gas production.
Productivity Determination and Pump Resizing Using Variable-Speed Electric Submersible Pumps
Authors: Kelley Robert S. 
Published: December 2007

This paper discusses a variable-speed electric submersible pump system usedas a tool to provide productivity information for resizing electricsubmersible pumps. Use of this equipment enabled the generation ofproductivity information without having to pull the existing downholeequipment. Field results using this method are presented.

Introduction
Waterflood expansion and developmental drillingprograms are being pursued actively in the LostSoldier Tensleep reservoir in central Wyoming. Response to the increased injection has resulted infrequent resizing to larger artificial lift equipment.As new injection wells are drilled and existing wellsconverted to injection to complete the pattern flood, adjacent areas are experiencing significant increasesin static and operating bottomhole pressures. Tohandle the increased fluid withdrawals possible, themajority of producing wells are being changed frombeam to electric submersible pump (ESP) lift andexisting ESP's are being resized.
The production of ESP-pumped wells in the LostSoldier Tensleep reservoir ranges from 400 to 6,200BFPD (64 to 986 m3/d fluid). Average depth of the reservoir is 5,000 ft (1524 m). Producing-wellbottomhole temperature is approximately 175 degreesF (79 degrees C).ESP lift plays an important role in this reservoir.At the end of 1978, 31 well, or 61% of all producing wells, were on ESP lift. These wells account for 87%of the total fluid produced. During the year therewere 10 new ESP installations and 14 ESP installationsthat were resized. It has been found thattraditional methods of predicting productivitycharacteristics for ESP sizing cannot be used in allcases. Several different size installations have beenrequired in some wells before an acceptable operatingfluid level has been achieved.
As a solution to reducing the uncertainty in sizingESP's, a variable-speed electric submersible pump(VSESP) was employed. By varying the frequency tothe downhole motor, it is possible to increase fluidproduction without pulling the existing downholeequipment. This paper discusses the results obtainedby using this equipment on two Lost Soldier Tensleepwells.
Resizing still will be necessary as response toinjection is seen in certain areas. However, once it hasbeen determined that a resize is justifiedeconomically, the VSESP can be used as a tool to aidwith sizing for the existing conditions. Otherapplications for this equipment also exist. A thirdwell tested is discussed briefly because it resulted in a further application.
JPT
P. 1503＾
The Interpretation of Capillary Pressure Data from Carbonate Reservoirs
Authors: Aufricht W.R. , Koepf E.H. 
Published: December 2007

Introduction
The theory, measurement, and application of capillary forces in reservoir rock have been treated extensively in the various petroleum publications. These forces are of prime importance in oil production, and data on capillary properties are among the most important tools used in the study of reservoir mechanics.
The principal application of measured capillary pressure data by the production and reservoir engineer is in the determination of the initial distribution and mobility of fluids in the reservoir. The distribution refers to the magnitude of the oil and interstitial water saturations under capillary equilibrium conditions and to their variation throughout the reservoir as a result of changes in rock properties and nearness to free water. The magnitude of the water (or oil) saturation, as well as the porosity, is required in volumetric calculations of oil in place. In low permeability reservoirs, where long transition zones are common, the magnitude of the oil content, even below the depth interval where commercial rates of flow of oil can be obtained, must be evaluated since this oil contains energy available to the production of the remainder of the reservoir.
The mobility of the water phase is of particular importance in waterflood calculations since mobile water may condemn what would otherwise be a successful water flood. In reservoirs with predominantly small pores, high immobile water contents are possible. Conversely, reservoirs with predominantly large pores may contain mobile water even though the interstitial water contents are relatively low.
This presentation reviews the distribution and mobility of interstitial water contents as determined from capillary pressure data and shows typical data for various types of carbonate reservoirs. A discussion of the variations found in different types of carbonate reservoirs is given.

Discussion

Interpretation of Laboratory Data
Fig. 1 is a typical laboratory capillary pressure curve where water saturation as per cent of pore space is plotted vs capillary pressure (psig) for an air-water system. This particular curve was obtained by measurement on a sample of San Andres dolomite with inter granular-type porosity.
Phase Partitioning of Anionic and Nonionic Surfactant Mixtures
Authors: Koukounis Christos , Wade W. H. , Schechter Robert S. 
Published: December 2007

Abstract
The efficiency of oil recovery by waterflooding can be greatly improved by the addition of judiciously selected surfactants. Under certain conditions, when surfactant solutions are mixed with oil, microemulsions are formed that may be in equilibrium with an excess oil (Type I), an excess aqueous phase (Type II), or both (Type III). The partitioning of the surfactant between those coexisting equilibrium phases is important to consider in the design of microemulsion processes for oil recovery. This is particularly true because different phases generally move at differing velocities within the pore spaces of an oil reservoir and therefore fractionation will occur in successive stages along the flow path. This leads to chromatographic separation of the surfactant molecules. The problem is complicated because all surfactant systems are blends of molecules, and chromatographic separation will result in a change in the optimal salinity of the surfactant system. Thus, a system that is initially optimized will not remain optimized during the course of the flood.
To examine the question of selective surfactant partitioning, we varied the composition of oil/water/surfactant equilibrated systems so that they would pass through the optimal formulation region. The partitioning of anionic surfactants into the oil in Type I and Type III phase systems was small. Furthermore, binary and ternary mixtures of these surfactants were found to copartition; that is, little if any fractionation was detectable. Their collective behavior was intermediate between those of the pure components. Nonionic surfactants, unlike anionics, partition substantially into the oil phase in Type I and Type III phase systems. This was found to be an intrinsic property of the surfactant structure and not unique to those nonionic surfactant systems that are polydisperse.
Selective fractionation also was found for polydisperse nonionic surfactants.
Modeling Dependencies Between Geologic Risks in Multiple Targets
Authors: Delfiner Pierre 
Published: December 2007

Summary
A single-target prospect can be characterized probabilistically by two elements: the risk or probability of success and the distribution of reserves given success. But there is no obvious way of combining the results of multiple targets into a single representative assessment.
This paper presents a simple approach for aggregating multiple targets for the purpose of prospect ranking. Reserves given success are assumed independent, and the novelty lies in the modeling of dependencies between geologic risk factors. Although interdependence can be represented by conditional probabilities, the selection of these values is a problem for most explorationists. In this paper, a more practical method is proposed. A matrix is completed for multiple targets, specifying which geologic factors are common and which are independent. An outcome tree with dependent targets is created, and the probability distribution of aggregate reserves is determined either analytically or by Monte Carlo simulation.
A case study with six targets illustrates the method. Dependencies reduce the probability of at least one success from 92% to 65% and the number of possible outcomes from 64 to 25. This allows a useful grouping by development cases. The method can be used for stacked reservoirs or portfolio analysis.
Non-Darcy Flow in Wells With Finite-Conductivity Vertical Fractures
Authors: Guppy K. H. , Cinco-Ley H. , Ramey H. J. , Samaniego-V. F. 
Published: December 2007

Abstract
Several methods have been proposed in the literature for analyzing drawdown data for the determination of fracture conductivity of vertically fractured wells. These techniques have proved accurate, but in some cases the fracture conductivity calculated is much smaller than anticipated. This study shows that producing fractured wells at high flow rates will cause non-Darcy effects in the fracture, resulting in a pessimistic fracture conductivity.
Numerical and semianalytical models were developed to analyze the unsteady flow behavior of finite conductivity fractures producing at high flow rates. Two methods are presented for determining the true fracture conductivity when drawdown data are available at two different flow rates. The amount of turbulent effects also is quantified by the techniques. Examples are presented to illustrate the solution methods.
Analysis of Two-Phase Tests in Large-Diameter Flow Lines in Prudhoe Bay Field
Authors: Brill James P. , Schmidt Zelimir , Coberly William A. , Herring John D. , Moore David W. 
Published: December 2007

Abstract
A total of 29 two-phase flow tests was conducted in two 3-mile-long flow lines in the Prudhoe Bay field of Alaska. Of these, 11 were for a 12-in.-diameter line and 18 were for a 16-in. line. Nine of the tests were in slug flow, and 20 were in froth flow. Flow rates, inlet and outlet pressures, and temperatures were measured for each test. Gamma densitometers were used to monitor flow pattern and to determine mixture densities and slug characteristics.
It was found that a modified Beggs-Brill1 pressure-loss correlation predicted culled data to within − 1.5% on the average compared with + 11.4% for a modified Dukler-Eaton2,3 correlation. Very little scatter was observed with either method.
Analysis of flow-pattern observations showed that none of the slug-flow tests were in the Schmidt4 severe slug region characterized by extremely long slugs. It also was found that the slug/froth (dispersed) flow-pattern boundary existed at a much lower liquid flow rate than predicted by either Mandhane et al.5 or Taitel and Dukler.6
Four of the slug-flow tests in 16-in. lines lasted for a sufficient time to permit statistical analysis of slug-length distributions. Sixteen additional tests on 4- and 7-in.-diameter pipe reported by Brainerd and Hedquist* were analyzed statistically. It was found that slug lengths could be represented by a log-normal distribution. A regression analysis approach was successful for estimating the mean slug length for stabilized flow as a function of superficial mixture velocity and pipe diameter. The extreme percentiles of the slug-length distribution then can be computed using standard probability tables, making possible probability statements about expected maximum slug length.
A mechanistic analysis of the slug-flow tests resulted in equations for predicting slug velocities, liquid holdup in both the liquid slug and the gas bubble, and the volumes of liquid that are produced and overrun. These parameters are important for predicting liquid-slug effects on separator performance.
Characterization and Oil Recovery Observations on a Series of Synthetic Petroleum Sulfonates
Authors: Malmberg Earl W. , Gajderowicz Carolyn C. , Martin F. David , Ward Jill S. , Taber J. J. 
Published: December 2007

Abstract
Synthetic sulfonates for application in enhanced oil recovery are of increasing interest. Because of the need to explore the range of candidates potentially available at various costs from the petrochemical industry, a series of nine samples was prepared for distribution with financial support of the U.S. DOE. This paper briefly describes the samples and, in more detail, the characterization of the samples for oil recovery. The characterization included determination of optimal salinity, stability of aqueous dispersions in brines containing sodium chloride and calcium ion, and oil recovery and loss of sulfonate in 1-ft (0.305-m) Berea cores.
Inferring Interwell Connectivity Only From Well-Rate Fluctuations in Waterfloods
Authors: Albertoni Alejandro , Lake Larry W. 
Published: December 2007

Summary
This paper presents a practical technique to quantify communication between wells in a reservoir using only production and injection rate data. The technique combines a constrained multivariate linear regression analysis with diffusivity filters to provide information about permeability trends and the presence of transmissibility barriers. The method was developed and tested using a numerical simulator and then applied to a waterflooded field in Argentina. The simulation results indicate that the connectivity between wells is described by coefficients that only depend on geology and relative position between wells; they are independent of injection/production rates. The results of this work can be used to improve the performance of an existing waterflood by suggesting how well patterns might be changed or managed. They could also be used to model flow in the reservoir.
Innovative Critical Sour Gas Extended Production Test Through Surface Coiled Tubing
Authors: Campbell S. F. , Pettigrew S. M. 
Published: December 2007

Summary
This paper describes the deliverability test of a critical, sour, natural-gas well that uses coiled tubing as a surface pipeline. Conventional production deliverability tests are constrained by regulatory limitations on emissions and flaring, affecting test duration and reservoir evaluation. Conventional tests also carry significant environmental impact, and the lost revenue from flared gas hampers the economic justification of the test. This paper describes the concept, the background analysis, and the field production test. A safety-focused procedure was developed using surface coiled tubing for in-line testing of high-rate, critical, sour gas wells. This prototype method allows a proper evaluation of a well without the commitment and installation of a permanent pipeline, the volume restraint imposed by regulatory limitations, harm to the environment, and compromising economic value. This method of well production deliverability tests is projected to become an attractive alternative for the Alberta oil and gas industry.
New Developments in Aerated Mud Hydraulics for Drilling in Inclined Wells
Authors: Sunthankar A. A. , Kuru E. , Miska S. , Kamp A. 
Published: December 2007

SummaryAn experimental study of aerated mud flow in an inclined well has been conducted, and the results are presented in this paper.Extensive experiments were performed in a unique field-scale low-pressure flow loop (8×4.5 in. annular geometry and 90 ft long) in an inclined position (15° from vertical) with and without drillpipe rotation. Water and an aqueous polymer solution [CMC (sodium carboxymethyl cellulose)+XCD (xanthan gum)+water] were used as the liquid phase. The liquid flow rate was in the range of 100 to 325 gal/min. The air flow rate was in the range of 8 to 85 scf/min. Measurements of pressure drop and average liquid holdup were carried out for the entire annular section. To our knowledge, no such data has been published previously.The two-phase flow patterns were identified by visual observations. Bubbly and slug/churn (intermittent) flow were observed for the ranges in the chosen test matrix.The flow-pattern boundaries proved to be shifted as compared to pipe flow. The transition between bubbly and slug flow was observed at a void fraction of 0.32 as compared to that reported for pipe flow (0.25) for air-water flow. On the contrary, for air-aqueous polymer fluid, flow was the same as for air-water pipe flow (0.25). For flow with drillpipe rotation, churn flow was observed instead of slug flow because of the churning of slugs by the rotating drillpipe.There was no significant effect of drillpipe rotation on the pressure drop for air-water flow. However, in the case of air-aqueous polymer fluid flow, the pressure drop decreased with drillpipe rotation.A higher pressure drop was observed in case of air-aqueous polymer fluid flow as compared to air-water flow.
Slimline Dual Detector Density Logging - A Semitheoretical but Practical Approach to Correction and Compensation
Authors: Samworth J. Roger 
Published: December 2007

A semiempirical approach to particular problems encountered in quantitative density logging with slimline logging tools is made. Equations based on known "physics" are employed to avoid problems encountered if empirical relationships alone are used. The simplest assumptions consistent with satisfactory results are outlined, and sample logs illustrate the effects of dual detector compensation.

Introduction
The log described in this paper is part of a multifunction sonde (gamma ray and caliper also are included as well as two density logs) developed to fulfill a requirement for a slimline one-run tool for one-man coal logging operations. The log response and compensation theory used also has shown itself to be readily extendable to logging in the higher 2- to 3-g/cm3 density region. The original purpose of the dual detector density log was to provide a thin-bed resolution capability with a good quantitative density measurement from the long-spacing detector. The spacings were chosen with these requirements in mind and were developed in an earlier generation of single-function tools. A semiempirical approach was taken to the density response equation with satisfactory results, and more recently, efforts to utilize the two logs to give densities compensated for tool standoff and (to some extent) for caving have shown some success.

Slimline Sonde Design Constraints
The one-man operation and slimline requirements indicated a sonde diameter of less than 5 cm and of manageable length (eventually around 3.5 m). The small diameter and desire for relative simplicity made necessary two other basic constraints.1. A limited volume was available for collimation of the source (Cesium 137) and the detector. This meant that a much larger borehole effect was present than is usual with larger-diameter tools and necessitated use of the semiempirical theory described later.2. An articulating detector shoe for the density logs was not used, since the sonde was eccentered as a whole by a single eccentering arm (Fig. 1).To reduce radiation counting statistics, high-efficiency scintillation counters were used for both detectors. Downhole count-rate dividers also were used to eliminate dead-time losses that can be caused by low-bandwidth logging cables. These dividers are such that the resolution and low counting statistics provided by the scintillation counters are in no way provided by the scintillation counters are in no way compromised. The detector dead time still remains, however, and is dealt with later.

Response Equation
For the preceding reasons, a semiempirical approach was thought to be necessary to allow a reasonably comprehensive relationship between the detector count rate and formation density to be established. The procedure should, however, apply equally to other similar tools. Let us begin with a relationship between count rate and density in an isotropic medium:
I = P e (-mp),......................(1)
JPT
P. 1316