bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pipe Sticking Prediction and Avoidance Using Adaptive Fuzzy Logic and Neural Network Modeling
Authors: Murillo Adriana , Neuman Johanna , Samuel Robello 
Published: April 2009

Abstract
Differential pipe sticking has a major effect on drilling efficiency and well costs. This problem is affected by many parameters, such as drilling fluid properties and the characteristics of the mud cake that is formed while drilling. Comparatively little research has assessed the prediction of stuck pipe. Traditionally, stuck pipe problems are solved by using some standard methods and techniques after they occur, but the real key to savings and success is in the avoidance of the risks associated with the stuck pipe. If these risks are identified in advance, better solutions can be provided to reduce the associated costs. To account for all of the aspects of differential pipe sticking and anticipated nonlinear behavior of the variables involved, fuzzy logic and neural network modeling can be used as primary predictive tools. These methods are widely used in other industries and in the petroleum field, especially in reservoir and core analyses. This paper presents a study of the application of the concepts of fuzzy logic to the problem of differentially stuck pipe. These methods make it possible to estimate the risk of stuck pipe occurrence in the well planning procedure and during drilling in real time. The nonconvolutional analysis of the model is based on the constraints of different drilling variables. Discriminant function analysis and fuzzy logic were used to classify drilling and mud variables. Extensive simulations were performed. This paper presents a case study in which the fuzzy logic and neural network modelling are successfully used to estimate and predict pipe sticking.
Simulating a Hilly Terrain Pipeline Using Twophase Flow Correlations and Mechanistic Models
Authors: Yuan Hong , Zhou Desheng 
Published: April 2009

Abstract
In this study, commonly used two-phase flow pressure prediction correlations and mechanistic models for pipelines in petroleum industry are used to simulate fluid flow in a hilly terrain pipeline. Simulation results are evaluated against experimental data. The experimental data were obtained from a published paper.
Hilly terrain pipelines are often encountered in oil and gas transportation. During pipeline design and simulation, experimental data are usually unavailable to calibrate against correlations or mechanistic models. In this situation, it is difficult to determine which correlation or model to use in predicting pressure drop in hilly terrain pipes due to the complexity of flow, since in a hilly terrain pipeline, fluid flow can be uphill, downhill and horizontal.
Pressure, temperature and rate measurements as well as fluid properties were given for a 2.8 mile long hilly terrain pipeline with 12-inch and 16-inch diameters. Pressure drops obtained from correlations and mechanistic models were compared with pressure measurements. Correlations and mechanistic models evaluated in this study include Beggs-Brill, Dukler, Dukler- Eaton-Flanigan, Dukler-Flanigan, Eaton, Eaton-Flanigan and Xiao and Ansari mechanistic models.
The results of this study can be used as guidelines for choosing two-phase flow pressure prediction correlations and mechanistic models in designing and analyzing hilly terrain pipelines.
Estimation of the Well Skin Induced by Accumulation of the Completion Fluid Around Wellbore
Authors: Mazloom Jalal , Tosdevin Mike 
Published: April 2009

Abstract
To control sand production in a dry gas unconsolidated sandstone reservoir, cased-hole gravel packs were installed in several newly drilled wells. Routine flow-after-flow and build-up tests were carried-out in all the wells after completion and unexpectedly high Darcy skins were estimated from the test data for all of the wells. In order to prepare a remediation plan, it was crucial to understand the source of the skin. As the estimated Darcy well skins according to the tests conducted right after drilling and prior to the well completion were negligible it was concluded that the positive skins were created during the completion process. The accumulation of liquid in the formation around the wellbore during the completion process and nearwellbore damage of the formation were considered to be the two main causes of the observed well skins.
A remediation plan would not be required if the presence of the completion liquid had generated the skin as much of the liquid would be recovered at the surface in the course of production. The gas mobility reduction and blockage to the gas movement would be a consequence of completion fluid accumulated near the wellbore. In order to estimate the contribution of this completion fluid on the total skin, radial grid single-well models representing flow into the wells were constructed. The single-well model results indicated that the blockage to gas movement due to the presence of the completion liquid manifests itself as a low gas mobility area in the build-up well test data. The maximum skin arising from this low gas mobility around the well was significantly less than observed. Near-wellbore damage was therefore recognized as the main source of the high skin. A Hydrofluoric (HF) acid job was recommended based on this conclusion and a reasonable well skin was achieved after performing these acid jobs.
Horizontal Woodford Shale Completion Cementing Practices in the Arkoma Basin, Southeast Oklahoma: A Case History
Authors: Nelson Scott G. , Huff Curtis D. 
Published: April 2009

Abstract
The recent activity increase throughout the Arkoma Basin located in southeast Oklahoma is in large part attributed to the rapid expansion of horizontal drilling in the Woodford Shale unconventional gas play. Successful primary cementing of these wells requires slurry design considerations that conventional cementing operations typically do not consider. These horizontal laterals require more than an excellent bond log to make a good well. The unique aspects of the petrophysical and geological properties of naturally fractured shale must be considered in the design. Not only are the basic cementing aspects of zonal isolation and casing support essential, but consideration of future stimulation plans are necessary to prepare and implement a proper well completion program.
Cement slurry design and execution is a crucial part of any cementing operation. This is especially true for Woodford Shale wells where the unique nature of the shale and its completion methodologies place additional demands on the cement. Slurry design considerations and successful slurry formulations for the area will be discussed along with an overview of primary cementing practices to date. Operational considerations as they apply to the cementing of horizontal shale wells in the study area will be covered. Conclusions and recommended practices for optimum results will also be presented from case history data.
Transient-Pressure Analysis of a Well With an Inclined Hydraulic Fracture Using Type Curve Matching
Authors: Dinh Anh V. , Tiab Djebbar 
Published: April 2009

Abstract
Hydraulic fracturing is an important well stimulation technique that has been widely used in the oil and gas industry. Most of the pressure transient analysis techniques to analyze pressure responses of fractured wells are based on the assumption that the fracture is either vertical or horizontal. However, a hydraulic fracture could be inclined with a non-zero angle with respect to the vertical direction. Field studies have shown that most hydraulic fractures are never perfectly vertical. Thus, for an inclined hydraulic fracture, the vertical orientation assumption may lead to erroneous results in well test analysis especially when the inclination angle is significant. However, there are very few studies concerning pressure transient analysis of inclined hydraulic fracture and there is no applicable well test analysis procedure available for inclined fractures. For this reason, it is important to develop well test analysis procedures for this type of fracture.
The purpose of this study is to develop a technique, based on the pressure derivative concept, for interpreting pressure transient tests in wells with an inclined hydraulic fracture. Detailed analysis of unsteady-state pressure behavior of fully penetrating inclined fracture in an infinite slab reservoir was provided. Both uniform flux and infinite conductivity models were considered. The study has shown that inclined fracture pressure data exhibit similar flow regimes as for vertical fracture counterpart. Those flow regimes are linear and pseudo-radial flow for both uniform flux and infinite conductivity models. However, for infinite conductivity model, a bi-radial flow regime is also observed. In the case of high formation thickness to fracture half length ratio and high angle of inclination, both uniform flux and infinite conductivity inclined fracture model exhibit an additional flow regime called early radial flow. Both bi-radial flow and early radial flow regimes for inclined hydraulic fracture have not been mentioned in the literature before.
A type curve matching technique was developed in this study using both pressure and pressure derivative curves. This type curve matching procedures can be used to obtain the following parameters: half fracture length, inclination angle, formation permeability and the pseudo-skin factor. The results should be verified with other pressure plots such as semi-log plot of ?P vs. t and ?P vs. t1/2 plot. A set of type curves with associated data was also provided for uniform flux and infinite conductivity inclined fracture models. Detailed explanations, tables, figures and numerical examples are included in this paper.
New Model for Gas Well Loading Prediction
Authors: Zhou D. , Yuan H. 
Published: April 2009

Abstract
Liquid loading is a common issue for gas producers. Better predictions of liquid loading will help operators in reducing costs (less shutdowns) and improve revenue (more production).
Turner's entrained droplet model is the most popular one in predicting liquid loading in gas wells. However, there were still quite a few wells couldn't be covered even after a 20% upward adjustment in the paper of Turner et al.. Field practice also proves that the adjusted model still underestimates liquid loading sometimes. By studying the droplet model and liquid film mechanisms, the paper presents a new empirical model.
Previous models for liquid loading are independent of the liquid amount in a gas stream. Once gas velocity is higher than calculated critical velocity, no liquid loading exists. This paper points out that, in addition to gas velocity, liquid amount (liquid holdup) in a gas stream is also a major factor for liquid loading. There is a threshold value for liquid amount in a gasliquid mixture. Above the value, liquid loading may appear even the gas velocity of a well is higher than the critical velocity form Turner's droplet model. The presented model is the first model including the amount of liquids in the calculation of gas critical velocity. According to the new model, critical gas velocity is not a single value, it varies with the liquid holdup in the gas well once the holdup excesses the threshold value.
Well data from Turner et al. were employed in the paper for evaluating the new model's parameters. Data from the paper of Coleman et al. were also used for the validation of the new model. The prediction results from the new model are better than those from Turner's model, and even better than Turner's adjusted model in matching Turner's data. The new model is consistent with Coleman's data and conclusion.
The new model is simple and can be evaluated at wellhead condition. It can be easily used to predict liquid loading in gas wells.
Horizontal Well Production Logging Deployment and Measurement Techniques for US Land Shale Hydrocarbon Plays
Authors: Heddleston Duncan 
Published: April 2009

Abstract
Traditional US land hydrocarbon bearing shale formations are presently being drilled & produced via horizontal wells. These horizontal wells consist of numerous selectively shot stages containing as many as 15 stages spread out across 2000 ft to 5000 ft interval.
These completions have been hydraulically fractured with water or slick water & require a flowback period of the injected water prior to the wells being kicked off with gas production. Since these types of formations are far from being homogeneous, the horizontal laterals can intersect existing natural fractures or faults in the formation or an aggressive hydraulic frac could induce fractures into existing natural fractures or faults.
When producing horizontal wells the lateral section draw down of the formation water has the ability to enter the wellbore from these faults or fractures causing the well's gas production performance to drop & eventually die off.
This paper will showcase US land horizontal well Production Logging deployment techniques using coiled tubing or well tractor examples & measurement techniques by imaging wellbore liquid / gas holdup, fluid velocity & thermal changes across the lateral. These techniques are successfully being used on US land horizontal wells in shale gas plays, whereby these case histories located inflowing gas and water entries across the lateral section.
The emerging trend of drilling and completing long horizontal laterals in unconventional shale gas formations leads to novel deployment techniques and measurements in order to efficiently measure data across these producing lateral sections.
U.S. Gas Market: The New Trends
Authors: Schubarth S. K. , Bazan L. W. , Whitehead W. S. , Larry J. D. 
Published: April 2009

Abstract
In the early 1980's an excess supply of Natural Gas was established in the U.S. due to the Natural Gas Pricing Act (NGPA) of 1978. In our last two papers we documented how this excess supply aided in keeping Natural Gas prices low until it disappeared and the subsequent lack of supply led to higher prices. There continues to be much talk around the importation of LNG and how it will affect the U.S. Gas Market. In this paper we will examine how LNG imports have changed, the relationships between pricing and supply, the historic value of U.S. gas production and what New Trends are being established in the market. This paper should help the oil and gas developer understand the market influences that result in the price he receives for his product.
Guidelines for the Proper Application of Critical Velocity Calculations
Authors: Sutton Robert P. , Cox Stuart A. , Lea James F. , Rowlan O. Lynn 
Published: April 2009

Abstract
Critical velocity calculations in the form of charts or simple equations are frequently used by field personnel to evaluate a gas well's flowing conditions to determine if the well is experiencing liquid loading problems. Literature detailing the critical velocity necessary to keep a gas well unloaded suggests using the conditions at the top of the well as an evaluation point. This is convenient for personnel conducting the evaluation as wellhead pressure and temperature data are readily available. A number of situations exist where the use of the wellhead as the evaluation point can lead to erroneous conclusions. The most obvious situation occurs with a change in geometry downhole when a tapered tubing string is run in a well or when the tubing is set above the perforations. In these instances a more robust evaluation results from using conditions at the bottom of the well and the downhole tubing geometry. Other conditions exist where the use of downhole conditions provide a better evaluation point. The assumptions used in the development of the standard, simplified form of the critical velocity equations and charts may not be appropriate for downhole application. In these cases the fundamental equations must be used. The calculation of critical velocity requires knowledge of pressure, temperature, produced fluids and PVT properties. The determination of critical rate requires the same properties with the addition of pipe diameter. The required PVT properties including surface tension and density for both the gas and liquid phases are reviewed. Correlations to calculate water-gas surface tension were found to have excessive error so a new, more accurate method is presented. This paper provides recommendations when the use of a surface or downhole evaluation point is more appropriate in the determination of the minimum critical gas velocity for a well.
Performance Analysis of ESP Systems in High-GLR Wells: From Lab Experiments to Practical Field Applications
Authors: Elichev V. A. , Khabibullin R. A. , Krasnov V. A. , Litvinenko K. V. , Prado M. G. 
Published: April 2009

Abstract
This paper presents the results of field evaluation by Rosneft of correlations developed by the Tulsa University Artificial Lift Projects (TUALP) to predict the performance of the natural separation process and of Electrical Submersible Pumps (ESP) operating under multiphase flow conditions as well as Russian State University of Oil and Gas (RSUOG) correlations for the performance of rotary gas separators. The first two set of correlations were developed using data acquired with TUALP experimental facilities but have not been tested against field data. The correlations developed by the Russian State University were also accomplished using lab data and a field test validation was required. During the years of 2006 and 2007 Rosneft conduct several field tests with the purpose of evaluating the performance of several gas handling technologies for ESP installations. The valuable data from those tests enabled Rosneft to verify the accuracy and validity of TUALP and RSUOG correlations for natural separation efficiency, rotary gas separator efficiency and for ESP multiphase performance under real field operational conditions with real crude and natural gas. The TUALP-Marquez-Prado correlation was selected for natural separation efficiency, the correlations for rotary gas separators developed by RSUOG were used and the TUALP-Duran correlation was chosen for pump multiphase head degradation. An excellent match was obtained between the field test data and the correlations predictions with exception of the following cases: Natural separation for installations with a horizontal ESP;Multiphase flow head degradation in installations using gas handling devices.
The paper presents a brief description of field data, a review of correlations for natural separation efficiency and pump head degradation; and a comparison between the predicted and measured performance.
Determination of the Suitability of Reinforced Thermoplastic Pipe for Applications With Aromatic and Cyclo-Aliphatic Hydrocarbons
Authors: Weller B. , Conley J. , Parvez A. , Cheng Y. 
Published: April 2009

Abstract
Reinforced Thermoplastic Pipe (RTP) is a new technology that is reducing the cost of constructing oil and gas gathering pipelines while improving reliability. RTP combines high performing materials such as bimodal high density polyethylene with high strength reinforcing fibers in a unique construction to create a spoolable high pressure pipeline system. The compatibility of high density polyethylene in general and RTP specifically with aromatic and cyclo-aliphatic hydrocarbons was previously only understood in a qualitative manner. A test program was conducted to determine an appropriate quantitative application envelope.
The test program consisted of exposing samples of high density polyethylene to various concentrations of aromatic and cyclo-aliphatic hydrocarbons at various temperatures. After the samples were saturated, mechanical properties of the samples were tested at a variety of temperatures.
The mechanical properties of the exposed samples and unexposed samples were compared in order to determine an appropriate application envelope. It was determined that as the temperature was increased, the effect of the aromatic hydrocarbons on the mechanical properties of high density polyethylene increased dramatically. The results allowed for the determination of acceptable concentration levels of aromatic and cyclo-aliphatic hydrocarbons at a variety of temperatures.
RTP provides solutions to many challenges associated with the construction of gathering pipelines including construction cost, availability of skilled labour and limited construction timeframes. It is currently being used in wide range of gathering applications. The conveyed fluid in many gathering applications includes some level of aromatic hydrocarbons and napthenes. The results of this study provide guidelines for determining the suitability of RTP for such applications given the concentration of aromatic and cyclo-aliphatic hydrocarbons and the operating temperature.
Next Generation Cement Analyzers
Authors: Bhaidasna Ketan , LeBlanc Chris 
Published: April 2009

Abstract
During cementing operations, the cement is handled in both slurry and set forms. Physical parameters, such as gel strength, thickening time, and compressive strength, play a crucial role in determining the final cement mix used during cementing. Successful cementing requires knowing the relative strength development of the cement for its target environment and conditions, prior to actual pumping. Ultrasonic cement analyzers provide a non-destructive means for determining the relative strength development of a cement sample under downhole conditions. Using the development and improvement of the modern ultasonic cement analyzer as an example, this paper describes how a modular platform for instrument design can be developed and demonstrates how this type of development can be extended to other instruments.
Comparison of Magnetic Resonance Bin Distribution Permeability to Observed Production
Authors: Thibidoux Steven , Smith Charles H. , Huggins Ken , Ramakrishna Sandeep 
Published: April 2009

Abstract
The Granite Wash formation in Oklahoma is made up of arkosic detrital material resting on older Precambrian rocks. It can range in age from Precambrian to Middle Pennsylvanian. Formed by erosion of uplifted segments, it is generally granitic in nature; it may also include large areas of reworked carbonate. This wash presents a very difficult log interpretation problem since reservoir consistency varies greatly from well to well. Magnetic resonance image logs were added to the logging program to establish additional parameters that could be used for reservoir description. The standard Coates permeability equation and its variations were applied to estimate permeability with little correlation to production. An observation was made that T2 bin distribution data tended to mirror production rates. Attempts were made to establish an algorithm that would directly establish permeability for this formation using measured T2 data. By matching actual production rates to observed T2 distribution data, we developed an equation to estimate permeability. This case study presents the results of using T2 bin information for estimating permeability and includes several Granite Wash wells.