bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Experimental Study on Mechanics of Wax Removal in Pipeline
Authors: Wang Qian , Sarica Cem , Chen Tom X. 
Published: December 2007

Abstract
Pigging has been recognized as the most cost-effective method for preventing flow restriction by wax deposits in subsea flowlines. However, the piping mechanics for wax removal in pipelines is still very poorly understood.
A unique test facility was designed and constructed for experimental studies on the mechanics of wax removal in pipelines. The test facility consisted of a test section, a support structure, an apparatus to pull the pig through the test pipe, and a computer-based data acquisition system. The test section was 21-ft long and was made from 3-in. inner diameter schedule-40 steel pipe. The mixure of commercial wax and mineral oil was casted inside the test section at different wax thicknesses and oil contents. A series of experiments were performed to investigate the wax removal mechanics with three different types of conventional pigs, i.e., disc, cup and polly pigs.
The experiments showed that a typical wax removal process using a pig followed four distinct phases, namely, wax breaking, plug formation, accumulation and production phases. Wax accumulating can be very significant, and is expected to be the dominating factor for the force required for moving a pig in long pipelines. As wax thickness and hardness increases, the required force to move the pig increases. The shape and material of the pig have a profound effect on the wax removal performance. While the disc pig provides the most efficient wax removal, the force requirement is excessive, especially for thicker and harder wax deposits. The wax removal performance of a cup pig is very similar to that of a disc pig. However, the cup pig can withstand higher load without mechanical damages than the disc pig. The polly pig offers the poorest wax removal performance.
New Analytical Solutions for Predicting Pressure Distribution and Transient Behavior in Wedges and Truncated Wedges
Authors: Rahman N. M. Anisur , Bentsen Ramon G. 
Published: December 2007

Abstract
Reservoirs of various shapes are encountered in practice. Evidence of wedges and truncated wedges has been found in Texas, Louisiana and elsewhere. In most situations, predicting the pressure distribution and transient behavior becomes very difficult due to a lack of necessary mathematical solutions. However, analytical solutions are often used for such purposes, even though it may have been necessary to compromise the geometry of the actual reservoir to obtain a solution. In the literature, analytical solutions for wedges are available. Application of these solutions very often forces the use of an approximate value of the wedge angle instead of the actual value. As a result, a considerable amount of error may be introduced into the predicted pressure responses. Moreover, no solutions for truncated wedges have been reported in the literature.
In this study, an integral-transform technique (ITT) has been used to develop new analytical solutions that overcome the limitations of the existing solutions in the literature.
Forward-Inverse Adaptive Techniques for Reservoir Characterization and Simulation Theory and Applications
Authors: Doss S. K. , Ezzedine S. , Gelinas R. J. , Ziagos J. P. , Chawathé A. 
Published: December 2007

Abstract
A novel approach called Forward-Inverse Adaptive Techniques (FIAT) for reservoir characterization is developed and applied to three representative exploration cases. Inverse modeling refers to the determination of the entire reservoir permeability under steady state single-phase flow regime, given only field permeability, pressure and production well measurements. FIAT solves the forward and inverse partial differential equations (PDEs) simultaneously by adding a regularization term and filtering pressure gradients. An implicit adaptive-grid, Galerkin, numerical scheme is used to numerically solve the set of PDEs subject to pressure and permeability boundary conditions. Three examples are presented. Results from all three cases demonstrate attainable and reasonably accurate solutions and, more importantly, provide insights into the consequences of data undersampling.
Fast and Accurate Correlations to Compute the Perforation Pseudoskin and Productivity of Horizontal Wells
Authors: Tang Yula , Ozkan Erdal , Kelkar Mohan , Yildiz Turhan 
Published: December 2007

Abstract
This paper provides fast and accurate correlations to compute the perforation pseudoskin and productivity of horizontal wells. Perforation pseudoskin is defined as the difference between the dimensionless pressures of the perforated and openhole completed horizontal wells. Simple formulas are presented to relate the perforation pseudoskin to the productivity ratio (PR) of the perforated horizontal wells. The productivity ratio, PR, is the relation between the productivities of the perforated and openhole completed horizontal wells. A semi-analytical model has been used to develop the PR correlations. It has been found that the relative error of the correlations is less than 6%. The PR correlations can be used as a quick tool to optimize the perforated completion of horizontal wells. Also using the relation between the pseudoskin for inclined perforations (non-zero phasing angle) and PR, the PR correlations provide a fast means of obtaining the pseudoskin for inclined perforations. These pseudoskin terms can be used to model perforated horizontal wells in semi-analytical and numerical reservoir simulators.
Laboratory Experiments Provide New Insights into Underbalanced Perforating
Authors: Walton Ian C. , Johnson Ashley B. , Behrmann Larry A. , Atwood David C. 
Published: December 2007

Abstract
Perforating underbalanced has become the primary means of removing perforation damage and maximizing productivity through a cased and perforated completion. The level of static underbalance (wellbore to pore pressure difference prior to perforating), considered the critical parameter in achieving acceptable productivity, has been investigated theoretically and experimentally through testing on outcrop and reservoir cores under laboratory conditions.
We now report on a new series of laboratory experiments conducted on outcrop cores under more representative downhole conditions. Investigation of previously neglected parameters produced profound differences in perforation productivity. In some circumstances static overbalanced perforating proved to be as effective as static underbalanced perforating. The surprising results on underbalanced and overbalanced tests suggest a new approach to minimize perforating damage. Not only do these results impact our understanding of the mechanism of perforation damage removal, but they also have important implications for future design of perforating jobs.
Hydraulic Fracturing for Reservoir Management: Production Enhancement, Scale Control and Asphaltine Prevention
Authors: Norris M. R. , Gulrajani S. N. , Mathur A. K. , Price J. , May D. 
Published: December 2007

AbstractProductivity in the Scott reservoir, located in the Central North Sea, is subject to impairment by scale and asphaltine disposition in the near wellbore region. Several intervention options have been attempted to restore the production potential (ie. re-perforation, fractured re-perforation, scale dissolution). These techniques have proved largely unsuccessful since due to the severity of the damage mechanism. This left hydraulic fracturing as the final option to bypass the damage and reconnect the wellbore to the productive sands.A technical and economic success was particularly desirable given the high operating costs associated with offshore operations and was achieved through a combination of well analysis and novel enabling technologies which are described in detail within this paper. The target well identified (J9) was selected based on criteria of production potential, drainage, pressure support and wellbore access. The fracture orientation plane was identified using existing open hole imaging logs allowing perforations to be oriented along the preferred fracture azimuth to minimize near wellbore effects during proppant placement and production. Specialized scale inhibitor impregnated proppant was employed to ensure deep and long term productivity protection for the fracture and tubulars. Placing a fracture in the reservoir also assisting in mitigating the effect of asphaltine disposition within the formation matrix. The large production string necessitated a new approach to lifting out the excess proppant within the wellbore. This was accomplished by reverse flow up a coiled tubing string in a process which was engineered to be a safe and effective.
Kinetic Rheology of Hydraulic Fracturing Fluids
Authors: Walters Harold G. , Morgan Ronnie G. , Harris Phillip C. 
Published: December 2007

Abstract
The rapid advancement in computing power is helping the development of more advanced fracturing models. These advancements include expanded dimensional capabilities as well as improvements in handling more complex rock and fluid mechanics models. Rheology of the fracturing fluid is fundamental for predicting fracture growth and geometry. Most hydraulic fracture models assume a steady-state power law rheology model with only an implied temperature dependence and no shear history dependence. Newer models have attempted to model shear history effects, but still do not accommodate the thermal kinetics of crosslinking and breaking chemistry. A definite need exists for more comprehensive rheological models for crosslinked fracture fluids.
This work entails development of theory and experimental confirmation of a comprehensive rheological model of a complex fracturing gel prepared with a guar derivative and dual crosslinkers. The Kinetic Rheological Modeling approach uniquely integrates the nonlinear kinetics of crosslinker chemistry with the in-situ changes in fluid rheology. The model accurately predicts the effects of shear rate, shear history, temperature, temperature-time history, pH, gel loading, crosslinker concentration, and breaker concentration on the apparent viscosity function. The model predicts the early noncrosslinked pseudoplastic behavior of the linear gel fluid, and then accurately predicts the rapid increase in apparent viscosity caused by the thermal and shear induced kinetic crosslink reaction. The model also accurately predicts thermal thinning at higher temperatures and the exponential decline in apparent viscosity that occurs when the breaker chemistry begins to dominate.
The model enables researchers to develop more comprehensive fracturing models, and the kinetic theory serves as an investigative tool for determining the effect of fluid chemistry and pumping history on the rheology of new and existing fracturing fluids.
A Rheological Criterion for Fracturing Fluids to Transport Proppant during a Stimulation Treatment
Authors: Goel Naval , Shah Subhash 
Published: December 2007

Abstract
One of the primary functions of a fracturing fluid is to transport proppant through a fracture and to keep the particles suspended till reservoir closes on the fracture. The proppant when suspended and uniformly distributed in the fracture improves the productivity of the reservoir. Therefore, a question is frequently asked regarding the minimum fluid viscosity required for satisfactory proppant transport through a fracture. The knowledge of this viscosity value is useful for evaluating fluids prior to their use in the stimulation treatment, and for demonstrating the effectiveness of new fluid formulations for fracturing applications. The present study addresses this question.
The study was performed by characterizing crosslinked guar gels for their viscoelastic properties. Then, the gels were evaluated for their proppant transport capabilities in two slot models using a field-scale test facility. The result shows that the proppant transport capability of crosslinked gels correlates with the fluid's elasticity, not with the fluid's viscosity. Based on these results, this investigation proposes a minimum elastic modulus criterion required for a satisfactory performance of the crosslinked fluids in a fracturing treatment. The criterion was developed from characterizations of borate-crosslinked gels, and then validated with zirconate-crosslinked gel.
The criterion proposed in this work was developed from the proppant transport behavior evaluated on a large-scale test facility. Thus, this criterion provides a useful and simple method to evaluate fracturing fluids in a laboratory, without the need for extensive fluid testing.
Mudcake/Screen Cleanup Investigation in Openhole Gravel-Packed Completions
Authors: Asadi Mahmoud , Conway Michael W. 
Published: December 2007

AbstractA large-scale wellbore model is used to evaluate the effect of mudcake on screen plugging and to study various mudcake and screen cleanup methods such as acid spotting, enzyme breaker, and oxidizer. A 6 ft long wellbore with 4 in. diameter was formed at the middle of an unconsolidated formation housed in the model. Mudcake was built onto the face of the unconsolidated formation by having a sized linear log 2% KCl based carbonate mud in the wellbore for 24 hrs at 160°F and at 150 psi. Carbonate mud was then drained from the wellbore and a screen was placed into the wellbore. The effect of mudcake on screen plugging was then evaluated with and without the presence of gravelpack around the screen by measuring the pressure drop across the screen during a production process. The model was fully instrumented and included pressure sensors, a densiometer and flow meter to assist in electronically recording data. Based on the pressure drop measurements, the degree of screen plugging was measured as a result of mudcake invasion into the gravelpack and screen. Finally, various cleanup methods were applied to the system containing unconsolidated formation, mudcake, gravelpack, and screen to evaluate mudcake and screen cleanup.
Laboratory Evaluation of In-Situ Gelled Acids for Carbonate Reservoirs
Authors: Taylor K. C. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Three different commercial formulations (A,B,C) of in-situ gelled acids are compared in detail at temperatures up to 150 °F and at acid concentrations from 5 to 20 wt% HCl. In-situ gelled acids are claimed to work by a gelation mechanism that occurs at the rock surface as the acid is neutralized. These acids contain a polymer, a crosslinker, and a breaker in addition to other additives. Detailed viscosity measurements of each in-situ gelled acid were made as a function of pH. A new experimental procedure was developed to partially neutralize the in-situ gelled acid, then the viscosity was measured as a function of shear rate in the range 1 to 3000 s-1. Relative reaction rates with reservoir rock of the three in-situ gelled acids were compared at 100 °F. Coreflood experiments were conducted with small acid volumes so that injectivity could be measured before acid breakthrough occurred.
In-situ gelled acids significantly retard the rate of acid reaction with reservoir rock. Results showed that acids B and C had similar behavior, while acid A was more reactive with reservoir rock. Viscosity measurements of partially neutralized in-situ gelled acids showed that only with acid C was a significant viscosity maximum observed as the pH of the acid increased. This pH maximum occurred at a value of approximately 2.2 with 5 wt% HCl at 100 °F. In the absence of breaker and crosslinker, acids A and B were very similar, while acid C showed as little as a tenth of the viscosity at low shear rates. Coreflood experiments showed that in some cases, the in-situ gelled acids irreversibly reduced the permeability of reservoir rock.
Geomechanical Analysis and Decision Analysis for Mitigating Compaction Related Casing Damage
Authors: Bruno Michael S. 
Published: December 2007

Abstract
Reservoir compaction and associated bedding plane slip and overburden shear has induced damage to hundreds of wells in oil and gas fields throughout the world. Critical casing damage mechanisms observed in a variety of structural settings include: 1) overburden shear damage on localized horizontal planes; 2) shearing at the top of production and injection intervals; and 3) compression and buckling damage within the production interval primarily around perforations.
Analytical solutions are readily available to estimate compaction, subsidence, and casing damage risks. These should be applied as initial screening tools at an early stage in reservoir development planning. They can also be applied to estimate relative risks for various well locations and trajectories.
Geomechanical models of increasing complexity, including two-dimensional and three dimensional finite element type techniques have been used with good success to assess formation deformation and casing damage risks in several reservoirs, and are described herein. Three dimensional geomechanical models at the wellbore scale are required to evaluate shearing deformation on specific well designs, and are used to assess damage mitigation effectiveness for varying completion strategies.
An economic decision tree model is applied to compare the costs and benefits of alternative well designs, while taking into account inherent uncertainties in model input data, well damage location, and the effectiveness of various mitigation strategies. In some instances the appropriate action is not to change completion design and simply accept damage risk.
Direct Measurement of Formation Resistivity through Steel Casing Solves a North Sea Production Question
Authors: Ferguson Roy , White Jim , Kadi Antoine El 
Published: December 2007

Abstract
Almost every oilfield well is logged with a resistivity tool prior to setting casing. This measurement enables interpreters to locate hydrocarbon and estimate water saturation. Once steel casing is run, conventional resistivity tools no longer function, so any estimate of formation saturation has then needed a neutron based measurement, for example formation sigma or carbon/oxygen ratio.
This situation has now changed. A new generation of resistivity logging tools is now available that can make formation resistivity measurements in cased holes. Such a measurement was recently successfully run in a key well in a major North Sea field.
In this well there was concern about near-wellbore damage affecting production. Sigma measurements were already available, but these shallow readings could not confirm if the oil saturations were truly representative of saturations far from the wellbore. This question could only be resolved by a deep reading saturation tool.
The Cased Hole Formation Resistivity Tool was therefore run in this key well, along with sigma tools to allow comparison with earlier sigma logs. The wellsite cased hole formation resistivity curve highlighted the areas that were water processed or unswept, however comparison of the shallow and deep saturations showed that the true situation was more complex than originally thought. This paper will review the results of this study and the impact of this new technology on the future life of the field.
Determination of Fit-For-Purpose Saturation Exponents
Authors: Worthington Paul F. 
Published: December 2007

Abstract
Algorithms that are commonly used for the evaluation of water saturation can require different input values of saturation exponent for meaningful application to the same reservoir rock. Further, the differences in the required saturation exponent can vary according to the reservoir properties themselves. By taking account of these different input requirements, it is shown that the discrepancies between predicted water saturations obtained using dissimilar petrophysical algorithms can be confined to a restricted range. The procedure is synthesized for easy operational application of an ordered, interactive method that allows a fit-for-purpose saturation exponent to be identified. Through this process, the sensitivity associated with the choice of an interpretative model for the evaluation of water saturation is demonstrably contained. The application of the method therefore increases confidence in petrophysical interpretation by limiting uncertainty.
Flow Diagnosis and Production Evaluation in High Flowrate Oil-Water Producers Using Optical-Fibre Holdup Sensors
Authors: Jackson R. R. , Ayan C. , Wakefield J. 
Published: December 2007

Abstract
In the North Sea (UKCS), Amerada Hess Ltd. is the operator of several oil fields which are developed using subsea technology (Fife, Hudson, Telford etc) and with a fixed platform in the case of the Scott field. In almost all wells, production is above the bubble-point pressure, at a wide range of water-cuts in multilayered reservoir systems. Many of the wells have monobore completions with 5″ production tubing and surface flowrates in excess of 15000 stb/d and up to 35000 stb/d. The downhole environment of these wells which comprises of high-velocity multiphase flow, has presented significant problems for conventional production logging sensors and analysis methods to evaluate. Friction and jetting effects on gradiomanometer type tools and small bubble sizes, which can not be detected by electrical probes are the well known complications.
To obtain reliable stabilised flow and transient data for diagnosis and production evaluation, a hold-up sensor based on optical principles has been applied. This sensor was recently introduced as a gas hold-up measuring tool. The application described here is the first use of this principle for measuring oil-water hold-up in high flow velocity wells.
Flow profile data and interpretation results from several wells are presented. Sensor performance was evaluated by comparing conventional and new generation sensors, including electrical and optical probes. In all cases, the optical probes gave reliable and consistent water holdup values, which were used for the interpretation of the data. Decisions involving water shutoff operations were based on the analysis of these results. We also review pressure and flow transient data recorded during the operations, which has the potential for providing skin factors and reservoir parameters for individual zones in a layered reservoir system.
Improvements in a Through-Casing Pulsed-Neutron Density Log
Authors: Odom Richard C. , Tiller Don E. , Wilson Robert D. 
Published: December 2007

Abstract
The practice of measuring the formation density with a standard pulsed-neutron system has been described in the literature1,2,3,4,5, and has been successfully applied in many reservoirs. This success leads to the obvious question: Can a system be developed that is optimized for this measurement?
To understand which parameters should be measured, characterized, or require improved response, a more exact analytical model is required. The pulsed-neutron density measurement is based on the transport of gamma rays created by inelastic scattering of fast neutrons. The current density algorithm uses a diffusion model for the gamma ray transport process. This simple model does not include the effect of variations in fast neutron parameters on the process of gamma ray production. As a result, an ambiguity is introduced in the density log that is associated with the dynamic nature of the gamma source. The initial distribution of gamma rays is a function of atom density and hydrogen content and must be properly described as a first step toward a more exact transport model.
The pulsed-neutron density measurement is analyzed and optimization is achieved using theoretical models, responses from laboratory formations and test wells, and through computer modeling. Along with data supporting an improved analytical model of the measurement, data is shown for incorporating fast neutron detectors and for optimizing spacings of the gamma ray detectors. As a result of this study, a prototypical detector array is described for improved density response.