bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Model For Predicting Corrosion Rates In Oil Wells Containing Carbon Dioxide
Authors: Garber J. D. , Farshad F. , Reinhardt J. R. 
Published: December 2007

Abstract
A computer model has been developed which is capable of predicting the physical condition and corrosion rate inside of a vertical oil well at various depths. These wells can be under naturally flowing or gas lifted conditions.
The windows based model contains 4 specific parts, which have been described in detail. The programs which provide the physical descriptions are the temperature program, the phase equilibrium program, and the non-annular flow dynamic program for pressure drop calculation. The model loops until pressure convergence is achieved. At this point various parameters have been selected which predict the uninhibited corrosion rate. An expert system has been developed which adjusts the predicted corrosion rate based on various field parameters.
Multi-Zone Injection by Limited-Entry Through Tubing
Authors: Wegis Anna 
Published: December 2007

Abstract
Multi-zone limited-entry injection through casing can have a serious problem – the inability to achieve efficient recovery due to lack of steam conformance. Poor sweep effiency results in steam migration into unwanted sands, cold temperatures in areas needing a steamchest, and an overall lack of oil recovery.
The failure of limited-entry injection through casing was noticed after a portion of Texaco's Kern River lease failed to achieve steam breakthrough. In July, 1996, this portion of the field had undergone a recompletion, in two distinct sands, utilizing casing limited-entry technology. After several years of injection, one sand had achieved a 0% increased recovery and the other sand had only achieved a 57% sweep efficiency. Because the cost of steam is one of Texaco's main expenses, it is important to use this resource effectively and economically. Limited-entry injection through tubing has proven to be a more efficient method for multi-zone flooding and is widely used throughout Texaco's Kern River operation.
The summer project, as a chemical engineering intern in the productions department, was to prepare and implement programs to reconfigure the field from limited-entry-casing injection to limited-entry-tubing injection in an economical and environmentally safe manner.
Multi-zone limited-entry injection through tubing is the most effective, economical, and environmentally safe answer. During August, 2000, the 20 injector wells in the project area underwent this reconfiguration process, the results of which are being awaited. This paper will document the process utilized to complete the project during the internship and the environmental, health and safety processes that were implemented.
Use of Surfactants to Recover Oils From Groundwater
Authors: Jayanti Shekhar , Pope Gary A. , Weerasooriya Vinitha , Zhong Lirong , Varadarajan Dwarakanath , Taimur Malik 
Published: December 2007

Abstract
Laboratory phase behavior and soil column experiments were conducted using branched alcohol propoxy sulfate surfactants to evaluate their effectiveness in removing gasoline and diesel range hydrocarbons from contaminated groundwater. Very low residual oil saturations were achieved with a much smaller amount of surfactant than typically required in surfactant enhanced aquifer remediation (SEAR). This type of surfactant has been shown to be both robust and efficient even when used at low temperatures and without co-solvent.
An Experimental Study of the Effects of Drilling Solids on Frictional Pressure Losses in Coiled Tubing
Authors: Shah Subhash N. , Zhou Y. 
Published: December 2007

Abstract
The drilling solids content is an important consideration in Coiled Tubing Drilling (CTD) operations. This paper presents an experimental investigation of the effects of drilling solids on frictional pressure losses in Coiled Tubing (CT) using a sophisticated full-scale coiled tubing test facility for an industry – university joint research project. The facility consists of seven reels of coiled tubing with diameters of 1", 1-1/2", and 2-3/8", fluid mixing and pumping equipment, and data acquisition system. Fluids investigated include solid-free polymer solutions at various concentrations, and real drilling fluids currently used in the drilling industry. The rheological properties of test fluids were evaluated using Fann and Bohlin viscometers. Standard industry drilling solids (Rev Dust) were added to the drilling fluids to simulate the effect of drilling solids on frictional pressure losses. Flow tests results indicate that as solids concentration increases, the frictional pressure losses increase significantly. The effect of lubricants on friction reduction in coiled tubing was also investigated. It was observed that the lubricants investigated could effectively reduce the friction pressure loss in coiled tubing. The analysis of experimental data has been focused on the effect of solids concentration, lubricant concentration, coiled tubing geometry as well as drilling fluid rheology.
Zone Selection and Production Prediction Using Advanced Logging Technology
Authors: Grieser Bill , Hill Britt , Brinska John , Stout Rex 
Published: December 2007

Abstract
Completing wells with multiple pay sections can be difficult and costly. With limited capital allocated at completion time, the geologist and the completion engineer are faced with deciding how to spend the available funds to attain the best return on investment (ROI) or net present value (NPV).
A process has been developed for selecting and ranking multiple pay sections and for giving accurate post-stimulation production estimates with advanced logging technology, such as magnetic resonance imaging (MRI), in conjunction with a production reservoir simulator.
This process ranks multiple pay sections by hydrocarbon storage capacity (ϕeff)(h), and producing capacity (kh). Initial productions (IP's), Estimated Ultimate Recoveries (EUR's), or projected cumulative production is then predicted for each section with variable stimulation half-lengths (Xf) or skin values (S). Output can be displayed on the log or in a tabular format.
NPV, ROI, or the internal rate of return (IRR) can be estimated for each stimulation scenario. These estimations can help operators justify stimulation job size and completion cost for each section of pay selected, giving the operator an additional tool for deciding how to best spend completion dollars.
The ranking process can be performed rapidly, and it provides a producing potential before setting pipe. This paper illustrates the process with six field examples from the Granite Wash formation in the Ammunition Field of Washita County, OK. Actual production is compared to predicted production for each well.
A New Approach to the In-Situ Measurement of Rock Properties
Authors: Cole J. H. , Reynolds R. R. , Weinberg D. M. 
Published: December 2007

Abstract
Although amazingly simple in concept, the downhole orbital vibrator is assuming an important and growing role in wellbore applications that include subsurface diagnostic and imaging concepts. The vibrator was first intended as part of a low-frequency shear-wave logging tool. It quickly found a more important application as a dowhole seismic source for crosswell imaging. It is now being investigated as the basis for new logging concepts for the in situ measurement of important rock properties including fractures.
Size of Oil Droplets Under High-Water-Cut Conditions
Authors: van der Zande M. J. , Janssen P. H. , van den Broek W. M. G. T. 
Published: December 2007

Abstract
In this paper the oil droplet size distribution as present during conventional high-water-cut oil production is discussed. The analysis is mainly based on the results of laboratory work on, firstly, core-flow experiments and, secondly, break-up in model chokes. Downhole, the size distribution is governed by the flow of oil and water out of the reservoir sections near the wellbore. It is expected that the smallest oil droplets will be in the 10–15 μm range, while the largest droplets are, presumably, of the order of centimeters. In the tubing, breakup of the largest droplets may occur, so that, eventually, the width of the size distribution will decrease somewhat in the sense that very large droplets will no longer be present. Subsequently, due to more intense break-up phenomena in the choke, the size distribution will shift to smaller droplet sizes. Downstream of the choke, the largest droplets will be in the 100–200 μm range. More information is needed for reliable predictions on the occurrence of very small droplets downstream of the choke. It is expected, however, that many droplets of sizes smaller than 10 μm will be present downstream of the choke.
Neural Network Approach Predicts U.S. Natural Gas Production
Authors: Al-Fattah S. M. , Startzman R. A. 
Published: December 2007

Abstract
The industrial and residential market for natural gas produced in the United States has become increasingly significant. Within the past ten 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 using an artificial neural network.
We developed a neural network model to forecast U.S. natural gas supply to the Year 2020. Our results indicate that the U.S. will maintain its 1999 production of natural gas to 2001 after which production starts increasing. The network model indicates that natural gas production will increase during the period 2002 to 2012 on average rate of 0.5%/yr. This increase rate will more than double for the period 2013 to 2020.
The neural network was developed with an initial large 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 neural network. The remaining input parameters of the reduced neural network included data of gas exploratory wells, oil/gas exploratory wells, oil exploratory wells, gas depletion rate, proved reserves, gas wellhead prices, and growth rate of gross domestic product. The three-layer neural network was successfully trained with yearly data starting from 1950 to 1989 using the quick-propagation learning algorithm. The target output of the neural network 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 performance for prediction. Analysis of the test results shows that the neural network approach provides an excellent match of actual gas production data. An econometric approach, called stochastic modeling or time series analysis, was used to develop forecasting models for the neural network input parameters. A comparison of forecasts between this study and other forecast is presented.
The neural network model has use as a short-term as well as a long-term predictive tool of natural gas supply. The model can also be used to examine quantitatively the effects of the various physical and economic factors on future gas production.
Open/Cased Hole Inflatable Whipstock Anchor
Authors: Cundiff David W. 
Published: December 2007

Abstract
The open/cased hole Inflatable Whipstock Anchor, (IWA), was designed to operate in a wide range of casing weights and hole sizes. It was originally conceived for cased hole applications but has proven adaptable to certain open hole applications. The goal was to build a whipstock anchor that would benefit a customer who needs to mill a window in old or damaged casing and reduce response time to the customers request by having a tool available that could be used in various hole sizes.
Experimental Investigation of Xanthan Foam Rheology
Authors: Sani Abu M. , Shah Subhash N. , Baldwin Larry 
Published: December 2007

ABSTRACT
In this work, experimental investigation was carried out on xanthan gel and xanthan foam rheology employing a pipe flow viscometer at 1000 psi. A nominal ½" stainless steel pipe was used as the flow conduit. Xanthan concentrations of 20, 30, and 40 lb/Mgal were used as the gelling agent to prepare xanthan fluids. Surfactant at 0.5% (vol.) was used as the foaming agent. Nitrogen was used as the gas phase. Foams were prepared and tested for qualities ranging from zero to 80% at various shear rates and at temperatures ranging from 75 to 200 °F.
The flow data showed that both xanthan gel and xanthan foam exhibited a behavior analogous to Herschel-Bulkley model fluids. It was found that the foam viscosity increases as the foam quality increases and more viscous liquid phase generated higher foam viscosities. The increase of temperature had an adverse effect on foam viscosity and stability. Viscosity isotherms were generated for the xanthan foam.
New empirical correlations for the xanthan gel and xanthan foam have been developed from the experimental data generated. These correlations are functions of liquid phase properties and foam quality and can be used to predict apparent viscosity of foam fluids for the conditions investigated. The use of these new correlations will provide a better estimation of the xanthan gel and xanthan foam fluid rheological properties.
Total Well Management II
Authors: Podio A. L. , McCoy J. N. , Becker Dieter , Rowlan Lynn , Drake Bill 
Published: December 2007

Abstract
The need of oilfield operators to verify that wells are being produced at their optimum capacity and in a cost effective manner is always present. To reduce operating costs, increase oil production and increase net income requires an integrated analysis of the pumping system including the performance and interaction of all the elements: the prime mover, surface equipment, well bore equipment, down hole pump, down hole gas separator and the reservoir. This analysis is to be made based on data obtained at the surface without entering the well bore and must yield an accurate representation of the conditions that exist on the surface, within the well bore and within the reservoir. Examples of rod pumped wells, ESP pumped wells, PC pumped wells and other well analyses are presented.
Experimental Investigation Into Revaporization of Retrograde Condensate
Authors: Luo Kai , Li Shi , Zheng Xitan , Chen Gang , Liu Ning , Sun Wenyue 
Published: December 2007

Abstract
A high condesate saturation ring usually forms in a gas condensate reservoir where pressure decreases below the dew point, especially around the wellbore. Gas injection/cycling is a main recovery process of choice for preventing loss of valuable condensate liquids. In this process the reservoir is often maintained above the dew point. Although full pressure maintenance development seems ideal in terms of preventing liquid loss, for economic reasons, this process may not be profitable. In recent years, many gas condensate reservoirs discovered have very high dew point pressures, say above 50MPa, in this case the full pressure maintenance will result in much expensive cost of the injection equipment and a large risk of safety problem. Thus one thought usually arises that whether the reservoir may be cycled at lower pressure after undergoing previous depletion below the dew point.
To address this issue, a series of experiments in this paper are performed and compared to quantitatively investigate the revaporization efficiency of retrograde condensate by lean gas injection. The studies include three main parts: (1) gas injection below the dew point in the PVT cell; (2) gas injection above and (3) below the dew point in long core equipment. Instead of the simple synthetic fluid and the packed core systems used in the previous literature, the actual gas condensate fluid and about 1m long-core are employed here. The gas condensate used is rich and has high wax content. As a comparative basis, the phase behavior is first detailed at length, including constant mass expansion and constant volume depletion. The measurements in the PVT cell show that lean gas injection leads to increase in the dewpoint of the rich gas condensate. An interesting finding from the first part is that lean gas can effectively revaporize not only the intermediate but also heavy hydrocarbon (i.e., C20+), which is contrary to the common belief that the heavy hydrocarbon cannot be revaporized by lean gas. Comparison of the second and the third parts illustrates that more condensate recovery of the former is obtained than the latter. This value is consistent with the conventional idea that full pressure maintenance is superior to the partial pressure maintenance according to the condensate recovery. However, when the expensive investments of the high pressure equipment are taken into account, the full pressure maintenance may not be the best choice. Therefore, it is recommended that an economic analysis be done to evaluate its feasibility. This is beyond the scope of the present study. To our knowledge, this paper is the first report of experimental studies on the revaporization of condensate using actual reservoir fluid/core system in long core equipment.
Effect of Pore Fluid Type on Perforation Damage and Flow Characteristics
Authors: Karacan C. Ozgen , Grader Abraham S. , Halleck Phillip M. 
Published: December 2007

Abstract
This paper compares the results of two perforation tests performed to investigate porosity and permeability damage due to perforating in gas-saturated versus liquid-saturated conditions. We used a method combining transient analysis and X-ray computed tomography (CT) map variations in permeability and porosity around the perforation tunnel. Experiments were conducted on 10-cm (4-in.)-diameter Berea Sandstone cores saturated with either low-viscosity silicone oil or nitrogen gas. Perforation flow tests were performed according to API RP43 procedures using conventional 6-gram HMX explosive charges, 6.9-Mpa (1000-psi) effective stress, and 5.2-Mpa (750-psi) underbalance. After flushing the perforations to remove explosion gases and loose debris, higher viscosity silicone oil was injected into the tunnels and movement of the front in the core was tracked using X-ray CT to measure the front velocity. Radial permeability was determined by relating differential pressure, front position and velocity. Porosity near the perforations was measured by comparing images taken when the sample was saturated with the two different fluids.
Analysis of the images and the data show that, for the specific charge and test conditions used, the type of fluid saturating the rock results in significantly different perforation geometries and damage under the same operating conditions. In the gas-saturated core, we obtained a shorter total penetration depth and a tunnel largely plugged with charge and rock debris. A zone of compacted rock, about 6 mm thick and with 6–8% less porosity than the average rock, surrounded the perforation tunnel. Near the entrance hole, the compaction was more severe when compared to other locations along the tunnel. The liquid-saturated core had a clean tunnel with a larger diameter and deeper penetration than the gas-saturated core. The liquid-saturated rock had no compacted zone. Permeability damage extended approximately 1.5 cm from the center of the perforation in the liquid-saturated core. The thickness of the damaged zone was a little higher in gas-saturated case when compared to liquid-saturated one.
Proppant Holdup, Bridging, and Screenout Behavior in Naturally Fractured Reservoirs
Authors: Barree R. D. , Conway M. W. 
Published: December 2007

Abstract
Pressure spikes and early, rapidly developing screenouts are often observed while hydraulically fracturing naturally fissured reservoirs. These occurrences are commonly attributed to fracture width restrictions or slurry dehydration. This paper describes the results of a series of laboratory experiments designed to study proppant transport and distribution in a hydraulic fracture with leakoff through discrete fissures. Mechanisms are described which explain the observed phenomena of proppant induced pressure rises and rapid screenouts. Methods of treatment design to combat these effects are also outlined. Observations made during the experiments provide insight into proppant crushing during fracture closure, poor polymer gel recovery, and final fracture conductivity.
The experiments show that lateral flow velocity into natural fissures causes proppant to migrate to the fracture wall and build up a dense proppant pack at the leakoff site. With sufficient leakoff the proppant holdup is severe enough to completely fill the main fracture channel, leading to screenout, even at low injected proppant concentrations. During buildup of the proppant bank the injected fluid is forced to flow in channels of diminishing height at very high shear rate. This unstable channelized flow leads to significantly different proppant and fluid distribution in the fracture than that predicted by uniform flow and transport models.
Direct Determination of Relative Permeability from Nonsteady-State Constant Pressure and Rate Displacements
Authors: Toth Janos , Bodi Tibor , Szucs Peter , Civan Faruk 
Published: December 2007

Abstract
Direct interpretation methods for determination of the relative permeability data by linear, non-steady-state, two-phase fluid displacements conducted via constant rate and constant pressure laboratory core tests, are presented. The equations necessary for processing of the displacement test data obtained after the breakthrough of the displacing fluid phase are derived by neglecting the capillary end-effects at sufficiently high flow rates and verified by various experimental data. The total mobility and the mobility ratio of the immiscible fluids are related to the characteristic parameters of the displacement process and the cumulative injected fluid pore volume. The general correlation functions of the characteristic parameters of the immiscible displacement process in porous media are facilitated to conveniently describe the relative permeability functions. These functions allow for accurate determination of the characteristic parameters of immiscible displacement by least-squares linear regression of experimental data. Therefore, the present analytic method determines the relative permeability functions uniquely, rapidly, and more accurately than the previous direct interpretation methods, auxiliary functions, and graphical and analytical methods, and offers a possibility of determining the relative permeability functions from constant pressure and constant rate displacements data.