bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Steady-State Multiphase Models to Approximate Transient Events
Authors: Fan Yongqian , Danielson Thomas J. 
Published: October 2009

Abstract
Transient multiphase pipeline models have found wide use in upstream oil and gas production. Such models have been successfully used to estimate such transient events as flow ramp-up, pigging, and terrain slugging. However, it is not often appreciated how much can be done using steady-state multiphase models. Such models – along with minimal additional analysis – can be used to estimate liquid flow rate, liquid hold-up and pressure drop changes that are equivalent to full transient simulations. The focus of this paper will be on the use of steady-state models to estimate transient behavior, including estimates of ramp-up and pigging slugs, as well as terrain slugging severity (including slug size and frequency).
The Geared Centrifugal Pump: A New High-Volume Lift System
Authors: Patterson John C. , Morrow William B. , Berry Michael R. 
Published: October 2009

Abstract
The Geared Centrifugal Pump (GCP) is a high volume artificial lift system consisting of a progressive cavity pump style rotating rod string driving a bottom intake electric submersible pump (ESP) style multi-stage centrifugal pump via a downhole speed increasing transmission. The heart of the system is the unique transmission that utilizes a novel gearing configuration that allows high torque and power. The GCP provides the high volume lift of an ESP but with better gas handling, simpler operation, and lower capital and operating costs. Additionally, since all downhole components are mechanical the GCP can operate effectively at very high temperatures.
Deep Electrical Images, Geosignal and Real Time Inversion Help Guide Steering Decisions
Authors: Seifert Douglas J. , Al Dossary Salem , Chemali Roland , Bittar Michael , Lotfy Amr , Pitcher Jason , Bayrakdar Mohammed 
Published: October 2009

Abstract
Early production, as well as ultimate oil and gas recovery, from a reservoir often depend on the timeliness and the accuracy of geosteering decisions. Exiting the reservoir during drilling results in costly nonproductive intervals. Even staying within the reservoir but in a nonoptimal location eventually leads to early water breakthrough while leaving behind valuable oil. In recent years, azimuthal deep resistivity measurements have been recognized as beneficial to real-time steering decisions. Because of their deep investigation, azimuthal deep resistivity measurements anticipate exits from the reservoir well before such events occur. In addition, their azimuthal sensitivity clearly points to the direction of preferred evasive actions.
Azimuthal wave resistivity measurements take on multiple embodiments with multiple characteristics and multiple depths of investigation. The best results are achieved by jointly interpreting several of these measurements according to workflows that are specific to the particular applications. In the simplest cases, the up-down resistivity curves exhibit an unexpected behavior that has proven valuable both to petrophysicists and to geosteering specialists. When approaching conductive overlaying shale, for example, the up-curve tends to read the resistivity of the reservoir and the down-curve exhibits amplified horns beneficial to reservoir navigation. Resistivity images feature bright spots whose progression with increasing depth of investigation facilitates the avoidance of unwanted boundaries. A new measurement, designated as a geosignal, features strong lateral sensitivity. The geosignal from the deepest spacing is best suited to provide an early indication of the approaching boundary, with a near-exponential dependence on the distance to boundary. Quantitative inversion based on a subset of the azimuthal resistivity logs and the use of limited local knowledge helps to quantify the distance to the reservoir boundaries and their rate of approach.
This paper presents some of the most commonly used interpretation methods are demonstrated on computer models, and then applied to various wells, with applications varying from thick reservoirs to interbedded sand-shale sequences.
Streamline-Based Simulation of Non-Newtonian Polymer Flooding
Authors: AlSofi Abdulkareem M , Blunt Martin J 
Published: October 2009

Abstract
Current commercial simulators for polymer flooding often make physical assumptions that are not consistent with available experimental data and pore-scale modeling predictions. This may lead to overly optimistic recovery predictions for shear-thinning polymers, while overlooking the potential advantages of reducing flow rate or using shear-thickening agents.
We develop a streamline-based simulator that overcomes these limitations and demonstrate how it can be used to design polymer flooding projects. The simulator implements an iterative approach to solve the pressure field since the pressure depends on the aqueous phase viscosity which in turn – for non-Newtonian fluids – depends on shear stress and hence the pressure gradients. This is in contrast to the common approach in commercial simulators where this viscosity-pressure interdependence is ignored, leading to over-estimation of sweep efficiency. Furthermore, in the simulator, non-Newtonian viscosities are defined to be cell-centered while current simulators use a face-approach thereby over-predicting viscosities as well as the stability of the displacing fronts. In addition, we use a physically-based rheological model where non-Newtonian viscosities in two-phase flow are taken at actual effective stresses instead of single-phase equivalents.
To validate the simulator, we construct one-dimensional analytical solutions for waterflooding with a non-Newtonian fluid. We then compare our results to those from commercial simulators. We discuss the significance of current assumptions to demonstrate the impact of non-Newtonian behavior on sweep efficiency and recovery.
A New Pressure/Rate Deconvolution Algorithm to Analyze Wireline Formation Tester and Well-Test Data
Authors: Pimonov Evgeny , Ayan Cosan , Onur Mustafa , Kuchuk Fikri 
Published: October 2009

Abstract
The deconvolved pressure change and its natural-logarithmic time (or Bourdet) derivative are very important for wellbore/reservoir system identification in pressure transient interpretation because they represent the constant-rate drawdown response of the system. In recent years, the use of pressure/rate deconvolution has increased considerably due to significant improvement of the mathematical algorithms. In this paper, we present a robust deconvolution algorithm based on a weighted Euclidean norm in the Tikhonov regularized objective function so that one can assign weights to individual pressure and rate measurement points, and thus define different error estimates for different sections of the data. Incorporating such features into the deconvolution algorithm is very useful to mitigate the effects of unreliable pressure and rate measurements and the sections of the data not obviously consistent with the wellbore/reservoir model. In the deconvolution algorithm, the Levenberg-Marquardt method with a restricted step procedure is used for the minimization of the objective function.
We present several applications of the new algorithm using real field pressure/rate transient data sets. In addition to well test data, we apply the algorithm to wireline formation-tester pressure transients which are usually also referred to as Interval Pressure Transient Tests (IPTT). The examples include data with cleanup effects as well as an IPTT test, followed by a conventional Drill Stem Test (DST). To the best of our knowledge, applications of deconvolution to wireline formation-tester pressure transients have been limited to a single publication before. Hence, the deconvolution algorithm and the results in this paper will be useful in designing and interpreting wireline formation tester pressure transients in addition to pressure transient well tests.
Gas Storage Facility Design Under Uncertainty
Authors: Ettehadtavakkol Amin , Jablonowski Christopher , Lake Larry W. 
Published: October 2009

Abstract
During the screening and concept selection stages of gas storage projects, many estimates are required to value competing projects and development concepts. These estimates are important because they influence which projects are selected and which concept proceeds into detailed engineering. In most cases, there is uncertainty in all of the estimates. As a result, operators are faced with the complex problem of determining the optimal design. A systematic uncertainty analysis can help operators solve this problem and make better decisions. Ideally, the uncertainty analysis is comprehensive and includes all uncertain variables, and simultaneously accounts for reservoir behavior, facility options, and economic objectives. This paper proposes and demonstrates a workflow and integrated optimization model for uncertainty analysis in gas storage. The optimization model is fast-solving and eliminates most constraints on the scope of the uncertainty analysis. Using this or similar workflows and models should facilitate analysis and communication of results within the project team and with other stakeholders.
Field Test Results of a New Neutron-Induced Gamma-Ray Spectroscopy Geochemical Logging Tool
Authors: Galford James , Quirein John , Shannon Scott , Truax Jerome , Witkowsky James 
Published: October 2009

Abstract
A new geochemical logging tool has been developed to provide measurements of elements important to the mineralogical analysis of rock formations and geochemical stratigraphy. The measurement system uses a chemical americium-beryllium neutron source to introduce moderate energy neutrons into the surrounding environment. These neutrons lose energy through scattering reactions and are eventually absorbed by materials in the borehole, the formation and the tool itself. The scattering and absorption reactions cause various elements among the atoms in the surrounding materials to emit gamma rays which have characteristic energies. Emitted gamma ray spectra are detected and recorded using a large bismuth germanate scintillation detector coupled to a high-efficiency photomultiplier and pulse-height analyzer.
The recorded 256-channel spectra are analyzed to derive individual contributions, or elemental yields, arising from neutron capture reactions involving hydrogen, silicon, calcium, iron, sulfur, potassium, titanium, gadolinium, magnesium, aluminum and chlorine. The spectral analysis is performed with a constrained, weighted least-squares solver to ensure physically meaningful solutions are obtained for the elemental yields. Additional signals from inelastic neutron reactions with oxygen, carbon, silicon, calcium, and iron are treated separately in the spectral fitting process.
The paper discusses several subjects including basic operation of the tool, derivation of characteristic elemental spectral responses, processing of the recorded spectra to obtain elemental yields and the conversion to elemental weight fractions for downstream formation mineralogy evaluations. Example logs from initial field tests are presented to demonstrate tool performance under various borehole conditions and lithologic environments including sandstone and carbonate reservoirs as well as organic shales.
First 4.5-in Through-Tubing ESP with Downhole Wet Connect
Authors: Patterson John C. , Head Philip , Moulsdale Peter 
Published: October 2009

Abstract
Artificial Lift Company Ltd. (ALC) and ConocoPhillips Company in 2004 initiated a 5 year development program to have a fully deployed wire-line through tubing electric submersible pump (TTESP) with a down hole 3 phase electrical wet connector.
ConocoPhillips Alaska had immediate applications for this technology in its Alaska business unit, West Sak asset. The wells in this asset are multi lateral and suffer from large amounts of sand production which settles in the mother bore restricting production flow to the ESP. Historically, a Rig would be required to pull the tubing and ESP equipment to allow access for wellbore intervention. ConocoPhillips has had 10 years of experience with wireline pumps1 which allowed pump replacement of sanded pumps but did not provide for rigless cleanout of the casing below the ESP. The ability to pull the entire ESP through 4.5" tubing providing an unobstructed tubing string for placement of lateral re-entry modules and to conduct coiled tubing cleanouts of sand in the casing was highly desireable.
This was also aligned with ALC's objective which was to make the system compatible with the most common wellbore architecture.
Oil-Recovery Predictions for Surfactant Polymer Flooding
Authors: Rai Khyati , Johns Russell T. , Lake Larry W. , Delshad Mojdeh 
Published: October 2009

Summary
There is increasing interest in surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding because of the need to in-crease oil production from depleted and water flooded reservoirs. Prediction of oil recovery from SP flooding, however, is complex and time consuming. Thus, a quick and easy method is needed to screen reservoirs for potential SP floods. This paper presents a scaling model that is capable of producing reliable estimates of oil recovery for an SP flood using a simple spreadsheet calculation. The model is also useful for initial SP design.
We present key dimensionless groups that control recovery for a SP flood. The proper physics for SP floods including the optimal salinity in the three-phase region and the trapping number for residual oil saturation determination has been incorporated. Based on these groups, a Box-Behnken experimental design is performed to generate response surface fits for oil recovery prediction at dimensionless times. The response surfaces derived can be used to estimate the oil recovery potential for any given reservoir and are ideal for screening large databases of reservoirs to identify the most attractive chemical flooding candidates. The response function can also be used for proper design of key parameters for SP and ASP flooding. Our model will aid engineers to understand how key parameters affect oil recovery without performing time consuming chemical simulations.
This is the first time that dimensionless groups for SP flooding have been derived comprehensively to obtain a response function of oil recovery as a function of dimensionless groups.
Improved Accuracy in the Measurement of Downhole In-situ Fluid Density
Authors: Gao Li , Van Zuilekom Tony , Pelletier Mickey , Proett Mark , Rourke Marvin , Palmer Richard , da Silva Andre Santos , Al-Hajari A. A. 
Published: October 2009

Abstract
New sensors have been developed for measuring in-situ fluid density that are based on the natural vibration of a structural member in contact with fluids being sampled using a wireline pumpout formation tester. Typically, a fluid-conveying tube is driven to its natural frequency and the frequency changes with fluid density. This design has the potential to greatly enhance the downhole fluid density measurement capability. However, the physical characterization and subsequent calibration of the sensor had to be proven for the harsher downhole environment. Although the principle for the vibrating density sensor is simple, a long list of factors, such as temperature, pressure, and tension, directly or indirectly affect the response of the sensor.
Experimental correlations are typically used to calibrate this type of sensor. However, in this paper, we systemically study all of these factors and derive a differential equation that fully describes the physics of the vibrating tube densitometer based entirely on first principles. This is followed by the solution of the equation and its subsequent application to laboratory test results as part of the sensor calibration process. Comparisons between theoretically predicted density values for various fluids and their known fluid density values show this method to be more robust than previous correlations methods. An accuracy of better than +/- 0.002 gm/cm3 over the pressure range of 0 to 20,000 psi and a temperature range of 75 to 350°F under controlled conditions is achievable. The resolution of the sensor can also be better than 0.001 gm/cm3. Experimental results and field examples are presented to demonstrate the accuracy and resolution of the sensor.
New Inflow Performance Relationship for Solution-Gas Drive Oil Reservoirs
Authors: Elias Mohamed , El-banbi H. Ahmed , Fattah K. A. , El-Tayeb El-Sayed Ahmed Mohamed 
Published: October 2009

Abstract
The Inflow Performance Relationship (IPR) describes the behavior of the well's flowing pressure and production rate, which is an important tool in understanding the reservoir/well behavior and quantifying the production rate. The IPR is often required for designing well completion, optimizing well production, nodal analysis calculations, and designing artificial lift. Different IPR correlations exist today in the petroleum industry with the most commonly used models are that of Vogel's and Fetkovitch's. In addition to few analytical correlations, that usually suffers from limited applicability.
In this work, a new model to predict the IPR curve was developed, using a new correlation that accurately describes the behavior the oil mobility as a function of the average reservoir pressure. This new correlation was obtained using 47 actual field cases in addition to several simulated tests.
After the development of the new model, its validity was tested by comparing its accuracy with that of the most common IPR models such as Vogel, Fetkovitch, Wiggins, and Sukarno models. Twelve field cases were used for this comparison. The results of this comparison showed that: the new developed model gave the best accuracy with an average absolute error of 6.6 %, while the other common models are ranked, according to their accuracy in the following order to be Fetkovich, Sukarno, Vogel, and Wiggins, with average absolute errors of 7 %, 12.1 %, 13.7 %, and 15.7 respectively.
The new developed IPR model is simple in application, covers wide range of reservoir parameters, and requires only one test point. Therefore, it provides a considerable advantage compared to the multipoint test method of Fetkovich. Moreover, due to its accuracy and simplicity, the new IPR provides a considerable advantage compared to the widely used method of Vogel.
Corrosion Inhibition of Low-Alloy Steels in Brine With Highly Oxygenated Nitrogen Membrane Gas for Underbalanced Drilling Applications
Authors: Mcnealy Richard , Hausler Rudy , Tabinor Matthew 
Published: October 2009

Abstract
Residual oxygen in membrane generated nitrogen, when commingled with potassium or sodium chloride drilling brines for underbalanced drilling (UBD) applications, is known to be very corrosive to drill pipe, casing and tubing. Commercial chemical inhibitors are routinely applied in such applications but supporting laboratory test data in the literature often fail to represent actual downhole environments.
The corrosion rate data from case study wells has limited value due to available locations and technology for measurement within drilling process flow loops. The test protocol discussed here and corresponding results provide for more realistic evaluation of inhibitor effectiveness and suggest a mechanism for corrosion inhibition.
The tests were conducted in stages intended to first establish the baseline corrosive behavior of low alloy steel in oxygenated brine with and without pH control by means of buffering agents. Subsequent tests focused on the effect of corrosion inhibitor concentrations and other additives. The results of the test program indicated that a combination of conditions resulted in significant inhibition of low alloy steel against oxygen corrosion, and is associated with the formation of surface film containing phosphorus. Corrosion rates as low as 50mpy without pitting were achieved, compared with 900mpy with significant scaling for uninhibited oxygenated brine.
This paper describes the development of conditions necessary to create a stable protective film in oxygenated brine without the formation of copious corrosion products known to present problems in UBD operations. The test protocol used herein suggests a method for qualifying the performance of candidate inhibitor formulations for specific UBD design conditions.
Laboratory and Field Scale Analysis of Steam Over Solvent Injection in Fractured Reservoirs (SOS-FR) for Heavy-Oil Recovery
Authors: Al Bahlani Al Muatasim , Babadagli Tayfun 
Published: October 2009

Abstract
Tapping heavy-oil from fractured carbonates is a real challenge due to unfavorable rock and reservoir characteristics. We introduced a new technique called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) for efficient heavy-oil recovery from fractured reservoirs, more specifically carbonates. The process consists of cyclical injection of steam and solvent in the following manner: Phase-1: Steam injection to heat up the matrix and recover oil mainly by thermal expansion, Phase-2: Solvent injection to produce matrix oil through diffusion-imbibition-drainage processes, and Phase-3: Steam injection to retrieve injected solvent and recover more heavy-oil. Our preliminary experiments under static (SPE 117626) and dynamic (SPE 123568) conditions showed that, under very unfavorable conditions (oil-wet carbonate, ~4,500 cp crude), oil recovery at the end of Phase-3 could be as high as 85-90% OOIP with 80-85% solvent retrieval.
This paper presents numerical modeling of the dynamic experiments and an upscaling study for reservoir size matrix. Heptane was selected as the solvent to inject through a single-matrix/single-fracture oil-wet Berea sandstones saturated with ~4,500 cp oil. The experimental results were matched to a single matrix/single fracture numerical model and parameters needed for larger scale simulation (matrix-fracture interaction parameters such as thermal diffusion, solvent diffusion and dispersion coefficients) were obtained. The main focus was the matrix size and first an up-scaling study to field conditions was performed.
Specific observations and conclusions as to the applicability of this technique in the field effectively were reported. It is hoped this new technique will be an alternative for tapping heavy matrix oil from oil-wet, fractured, deep, carbonate fields.
Hostile Formation Testing Advances and Lessons Learned
Authors: Van Zuilekom Anthony , Rourke Marvin 
Published: October 2009

Abstract
Exploration and development wells are moving toward increasingly deep and hot reservoirs, which require a new generation of hostile wireline formation tester (HWFT) tools. This paper addresses both a first generation of hostile HWFT and a next generation formation testing tool that will operate in reservoirs as hot as 450°F and at 30,000 psi pressure.
The first generation of hostile sequential formation testing (HSFT) tools was introduced in 2002 (Rourke and Powell 2006). A wealth of experience collecting pressure measurements and fluid samples in formations as hot as 408°F has been accumulated since the first generation tool was introduced. Since 2002, the practice of obtaining of pressure data and fluid samples has evolved from a rarely performed service to a routinely performed service. Tool hardware and operations procedures have incorporated new techniques, which have resulted high reliability and low fishing rates. Many lessons were learned along the way. The next generation of hostile formation tester tools will incorporate the lessons learned from the first generation into its design to extend the pressure testing capabilities and to move toward the ability to acquire (PVT) quality samples and fluid identification (F-ID) in these difficult and increasingly hostile conditions.
Past HWFT experiences are used to illustrate the best practices for high pressure, high temperature (HPHT) testing. Success rates are tracked to demonstrate how the improvements have led to successful testing in progressively more hostile conditions. Conclusions are drawn regarding the future of HWFT testing and how the new technologies that are anticipated for these tools will continue to extend their capabilities.