bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deepwater Four Zones Selective Washpipeless Frac-Pack Completion Inside a Bad Cemented Liner: A Case History
Authors: Vilela Alvaro , Hightower Chad , Montanha Roberto , Luiz Ronaldo , Queiroz Ricardo , Pereira Alexandre 
Published: December 2007

Abstract
Fracpack completions are not new to the oil and gas industry; however, they are operations that are very critical to the results of well longevity, productivity, and are considered operationally "high-risk" completions. Some fields in deepwater Campos basin (Figure 1) - Brazil have tightly spaced productive zones that require sand control and selectivity of production. Two systems were used on the four-zone completion to allow for the tight spacing between zones. On the lower and upper middle zone a modified washpipeless isolation system (Crippled) was utilized and on the lower middle and upper zones a high pressure retrievable washpipeless isolation system (HPRWIS) was used. Both systems utilize a concentric string for isolation, not using washpipe to the bottom of the screen, like a normal land or Gulf of Mexico completion stems from unsuccessful attempts resulting in stuck washpipe in 7" liners with 2 3/8" isolation tubing on floating platforms or drillships and rough seas.
The HPRWIS system also provides "live-annulus" capabilities and a method to isolate the production screen from the tubing after fracing by placing a concentric string into a lower seal bore after the treatment is over. All installation is done at the surface in both systems, but the HPRWIS is initially spaced out to allow communication through the lower most part of the production screen. After reversing operations to remove excess proppant from the workstring, a shifting prong actuates the concentric string down by means of well hydrostatic working across an atmospheric chamber connected to the gravel pack assembly. Actuation is accomplished by mechanically removing a lock ring attached to the atmospheric chamber with the previously mentioned shifting prong. The concentric string may also be retrieved on pipe by utilizing a HPRWIS retrieving tool with straight upward pull to the inner assembly.
This paper outlines the utilization of "State-of-the-art" frac pack downhole equipment technology used to successfully complete, without unscheduled events, a four zone well with bad cemented liner (Figures 2–5) in the Campos Basin, Macae, Brazil.
Effect of IFT Variation and Wettability on Three-Phase Relative Permeability
Authors: Cinar Y. , Marquez S. , Orr F. M. 
Published: December 2007

Abstract
In this paper, we report experimental results that demonstrate combined effects of variations in interfacial tension (IFT) between one pair of three phases and wettability of porous medium on three-phase relative permeabilities. We employed two analogue three-phase systems, in which the IFT between two of the phases could be varied systematically while holding the IFTs between the other pairs of phases roughly constant. We report measured three-phase relative permeabilities for systems with IFTs between two of the three phases varying from 0.005 to 2 mN/m. Phase recovery and pressure drop data were interpreted by the combined Welge/Johnson-Bossler-Naumann (JBN) method to yield relative permeability curves. The results obtained indicate that as IFT between the analogue "gas"/"oil" pair of phases decreases, relative permeabilities for those phases increase at a given saturation. The relative permeability for the analogue "water" phase remains nearly unchanged for water-wet porous systems, but decreases especially at low phase saturations for oil-wet porous systems.
Erosion by Proppant: A Comparison of the Erosivity of Sand and Ceramic Proppants During Slurry Injection and Flowback of Proppant
Authors: Vincent M. C. , Miller H. B. , Milton-Tayler D. , Kaufman P. B. 
Published: December 2007

Abstract
During fracture stimulation treatments, particle-laden slurries may damage pumping equipment and have been shown to erode perforation tunnels. During subsequent flowback operations, minor to severe erosion of surface equipment may be observed if formation sand and/or proppants are produced. This paper compares the erosivity of sand-based and ceramic proppants.
This paper will examine the erosion mechanisms and demonstrate that theoretical and laboratory measurements are in agreement that low density ceramic proppants, due to the superior roundness and sphericity, are less erosive than more angular sand products.
Real-world results from the oilfield, the waterjet industry, pump and valve manufacturers, and the abrasive industry will be reviewed to substantiate the conclusion that proppant angularity is a dominant parameter that increases erosion in typical pumping and flowback conditions.
Impingement tests designed to simulate flowback conditions demonstrate that substituting a spherical lightweight ceramic may reduce wellhead or other impingement surface erosion by up to 95% compared to an angular sand. The highest quality frac sand was nine times more erosive than lightweight ceramic (LWC) in impingement studies. Additional studies utilizing intentionally crushed proppant to increase angularity demonstrate that proppant shape is a dominant factor which controls erosion. Surprisingly, flowback testing has shown that resin coatings applied to proppant have the potential to increase erosion by 15-fold. The authors believe this is partially due to a focusing effect attributed to electrostatic charge. Test alterations with multiphase flow have reduced, but not eliminated, this effect.
Slurry abrasion testing has shown that the highest quality frac sands are over 250% as abrasive as LWC. Although frac sands are often specified to withstand several thousand pounds of closure stress, significant sand degradation was observed after exposure to a reciprocating five pound weight. Erosivity and abrasivity of all proppant types were shown to increase with proppant damage. Erosion within chokes was found to be three times higher with sand than with lightweight ceramic.
Despite conventional wisdom to the contrary, a number of recent laboratory studies have demonstrated that spherical proppants are less likely to flow back from the fracture as compared to more angular products. All data indicate that equipment erosion occurring during the stimulation treatment and subsequent flowback can be substantially reduced through the use of spherical lightweight ceramic proppants.
Fracture Propagation and Formation Disturbance during Injection and Frac-Pack Operations in Soft Compacting Rocks
Authors: Abou-Sayed Ahmed , Zaki Karim , Wang Gay , Meng Fanhong , Sarfare Manoj 
Published: December 2007

Abstract
The widespread use of FracPack technology in deepwater reservoir has been a growing practice. Its purpose is sand control and well stimulation. To-date, field applications and fracture treatments have been designed using traditional hydraulic fracturing simulators that apply LEFM theories. While this is adequate for hard rocks (e.g., tight gas formations), the fracture geometry predictions fall short when applied to fracturing soft rocks. Soft rocks are normally at incipient plasticity and, hence, are prone to compaction.
Compaction, or plastic rock deformations during sand control FracPacks operations and disposal of drilling cuttings slurries in soft layers. The capacity of the created fracture to store or accept solids, the conditions of the rock strength near the fracture faces and the near well/fracture rock porosity or permeability are all highly impacted by the rock compaction during the fracture propagation process.
The objective of the presented research is to assess the impact of compaction and plasticity on fracture geometry and formation properties around the fracture. In particular, it is important to quantify the details of the geometry of factures generated during FracPack and waste disposal operations as well as the porosity/permeability changes in the vicinity of the fracture faces.
In the current paper, rock behavior is described by a variation of the Cam-Clay model. This model represents an inelastic, work hardening model that, depending on the loading path, could predict both compaction and dilatency, in a given formation. This is particularly useful in modeling soft or elasto-plastic compacting formations since the fracture propagation is heavily driven by the leak off into the formation and the in situ stress profile. Formation low permeability leads to lower leak off rates, especially if the injected slurry has a leak-off control additive. This scenario leads to compaction of the rock along the fracture sides. High permeability at the tip results in a large amount of fluid leak off into the formation causing the near-tip zone to dilate during slurry injection and fracture propagation.
The current paper presents results of fracture simulation in compacting rocks including fracture geometry, fracturing pressure and porosity/permeability alteration around the fracture. In the previous paper, results of finite element model provided a benchmark to simulation results. The present work, on the other hand, shows the extent of formation disturbance and porosity/permeability alteration, as well as propped fracture characterization in FracPacks. Finally, the model results addressed the disparity between conventional FracPacks designs and actual treatment data. The observations confirm the need for careful consideration of rock plasticity in fracture simulation to avoid FracPack failures and minimize the absence of TSO response in some field implementations.
3D Visualisation: A Common Language for the Drilling and Subsurface Communities
Authors: Telford C. , Burns M. , Whiteley N. 
Published: December 2007

Abstract
3D visualisation has enabled the Andrew field team in the North Sea to develop a common understanding of geologically related drilling hazards to achieve Best in Class drilling performance on the 16/28-A16 well. Improvement continued in subsequent well 16/28-A17 with a further reduction in geologically related non-productive time (NPT). The common language provided by the 3D visualisation tools enabled the different disciplines onshore and offshore to communicate effectively, integrating the team.
This paper is a case history, describing how the reservoir model, 3D pressure cube and structural model were used with the 4D seismic to identify the geological targets in the reservoir. These models, together with the mapping of the overburden and the historical drilling NPT were used to determine the optimal trajectory to reach the prize. The ability of the multi-disciplinary team to view the subsurface field data alongside the drilling NPT provided a greater understanding of the potential risks and challenges, and ensured buy-in by all in the project from planning through to production. Visual images developed during the planning process were then used to brief the drilling and subsurface contractor services in technical limit, pre-spud and refresher sessions prior to each drilling phase.
Following the problematic A15y well with two sidetracks, the A16 well was drilled and completed with only 13.1% total NPT including waiting on weather, comfortably beating the aggressive 20% target and high historical levels of NPT recorded on mature fields in the same area. Only 9.4% of the total A16 NPT time was geologically related. A17 was drilled and completed with 21.4% total NPT including waiting on weather with only 3% of the total well NPT geologically related NPT.
This paper will be of interest to all personnel involved in planning and execution of a well and system developers wishing to enhance workflows for integrated teams.
A Methodology for Selecting Interventionless Packer Setting Techniques
Authors: King James G. , Arrazola Alvaro J. 
Published: December 2007

Abstract
Eliminating intervention during well completion reduces operating expense and risk. In deepwater, horizontal, and extended-reach applications, interventionless actuation systems for setting completion tools are reducing well intervention and completion time and associated costs without compromising reliability or safety. This paper details the operation of three commercially successful technologies that permit interventionless actuation and provides a methodology for selecting the optimum solution for a particular application.
Using Cost Effective Tools to "Bring the Wells to the Operators!"
Authors: Cramer Ron , Der Kinderen Wim , Berendschot Leo 
Published: December 2007

Abstract
This paper describes a cost-effective, pragmatic way to continuously monitor and control well performance for most oil well types. Well fluid flow rate estimates are displayed in graphical form as trends on user desk top PCs. Deviations from the norm are flagged as process alarms. In some cases measured fluid flow changes are used to automatically control the well by adjusting choke settings for performance improvement.
The main benefits of this approach are safer operations and reduced operating costs - operators visit only wells with problems thus reducing exposure to hazard and eliminating spurious travel and logistics. Other benefits include increased production due to early warning of well problems, better understanding of well behavior, improved allocation accuracy and improved well testing.
The purpose of this paper is to describe Shell experience with low cost continuous well performance devices and some of the benefits that can be gained from this approach.
Business Ethics, Corporate Social Responsibility, and Firm Value in the Oil and Gas Industry
Authors: Fadul Javier , Maurer Ruth A. 
Published: December 2007

Abstract
This study is an examination of the relationship between ethical behavior, corporate social responsibility, and firm value in companies in the oil and gas industry. The considerable social impact of the behaviors and actions of oil and gas companies and their undeniable weight in the overall economy drive the purpose of this research. Ethical behavior and social responsibility of the sampled oil and gas companies will be conceptualized by a series of ethical and social indexes used to carry out empirical observations representing those concepts. Each social index will be analyzed using statistical data analysis techniques to establish if there is any significant relationship with the firm's value. This research presents empirical evidence examining whether, along with other standard factors, corporate social responsibility is associated with the firm value of companies in the oil and gas industry.
Cased-Hole KUTh Logging Using A PNS Tool
Authors: Reed Skip , Jacobson Larry A. , Durbin Dennis 
Published: December 2007

Abstract
Traditionally, all major service companies have had an openhole spectral gamma tool in their arsenal that will measure the naturally occurring potassium (K), uranium (U), and thorium (Th) radioactivity surrounding a borehole. KUTh data are used in various ways, such as subtracting out high API uranium indications from total API Gamma Ray readings in radioactive formations and using the relative percentages of these elements as input to proprietary mineral calculation programs.
Recently, a standard C/O logging tool with the neutron generator turned-off was used for cased-hole KUTh logging with good results. Although this pulsed neutron spectrometry (PNS) tool was a slim tool (2 1/8-in. diameter), the log quality was comparable to that achieved by earlier, large diameter gamma spectrometry tools because this particular PNS tool utilized a high density scintillator. This experience clearly demonstrated that reliable spectral gamma measurements can be made in cased hole. Calibration with a standard thorium calibration sleeve allows the operator to set the spectral gain of the system (using the Th peak); and this value of gain is used during the logging operation. After logging, the data is reprocessed with software that tracks and corrects any gain drift due to temperature producing the final corrected log. Concentrations of K, U, and Th are extracted using a weighted-least-squares (WLS) fit of standard elemental (basis) spectra to the log data during the re-log phase.
Measurements made in this way can readily precede the standard formation evaluation run in a well and use essentially the same instrumentation and thus replace traditional openhole KUTh measurements. The enhanced design and the software associated with it provide high quality formation evaluation information; and this information can be made available with no associated drilling rig cost if the tool is run going in the hole.
This paper will show field examples of KUTh data. The paper will also discuss procedures necessary to obtain quality measurements, will point out various savings that can be realized by an operating oil company using the new design and the information it gathers, and will present the interpretation procedures necessary to obtain a final product.
Important Modeling Parameters for Predicting Steamflood Performance
Authors: Satik Cengiz , Kumar Mridul , DeFrancisco Sam , Hoang Viet , Basham Mike 
Published: December 2007

Abstract
A comprehensive numerical study was performed to investigate impact of pattern confinement on simulation results, using a three-phase and three-dimensional thermal reservoir simulator. In addition, effects of cyclic steaming the producers, grid size, and other physical parameters were evaluated. Detailed multi-pattern, single-sand steamflood models were constructed using properties of a heavy oil field in California. All models included an initial primary depletion zone of 6 ft within 60 ft of net pay. Up to 25, 2.5-acre patterns were included in the study.
Results show that finely gridded models capture near vertical steam override, and oil drainage by gravity with a near horizontal steam/oil interface accurately. High injection pressures observed in many prior simulations are primarily a result of confined reservoir models. Steam zone pressures and temperatures are similar to those typically observed in the field, when the model is unconfined (model area is greater than pattern area), representing undeveloped portions of the field. Moreover, including cyclic steaming of producers accelerates the steam breakthrough time (BT) and lowers injection pressures. During post-breakthrough steam rate reduction period, field-observed oil production response is better represented when the influence of surrounding patterns is included. Production rate decline is small when injection rate is reduced only in the primary pattern(s); however, the decline rate increases if rate reduction is implemented in the entire modeled project area.
A New Computational Fluid Dynamics Model to Predict Flow Profiles and Erosion Rates in Downhole Completion Equipment
Authors: Russell Ronnie , Shirazi Siamack , Macrae Jonathan 
Published: December 2007

Abstract
Flow velocities and sand generation encountered in high-volume oil wells have exceeded the accuracy of current CFD modeling data. Advanced theoretical work and erosion modeling have been performed to address these high flow rates. The theory and models are compared and verified by testing several materials under an array of flow conditions. The models and test data provide a valuble design tool to ensure performance and reliability of critical completion hardware.

Introduction
Sand production is a major problem in oil and gas production operations. The presence of sand in produced fluid presents many challenges to equipment suppliers and production companies. Sand control has become increasingly important as high-rate wells with sand become more prominent. Sand erosion as a result of sand production is a major concern. It causes loss of pipe wall thickness that can lead to expensive failures and lost - production. Even when sand production is as low as a few pounds per day, it can cause erosive failure at high production velocities. Laboratory experience indicates that when the produced fluid is a liquid, exchange of momentum between sand particles and liquid reduces the impact velocity of sand particles, resulting in little or no erosion. However, current erosion data does not cover the range of materials and flow conditions experienced in high flow rate oil wells.
American Petroleum Institute Recommended Practice 14E (API RP 14E) provides a criterion for sizing gas/liquid two-phase lines on the basis of flow velocity. The recommended practice states that (API RP 14E, 1991):
"The following procedure for establishing an ‘erosional velocity’ can be used where no specific information as to the erosive/corrosive properties of the fluid is available. The velocity above which erosion may occur can be determined by the following empirical equation:Equation 1
where:
Ve=fluid erosional velocity, ft/sec
c=empirical constant
?m=gas/liquid mixture density at flowing pressure and temperature, lb/ft3
Industry experience to date indicates that for solids-free fluids, values of c=100 for continuous service and c=125 for intermittent service are conservative." The recommended practice adds: "If solids production is anticipated, fluid velocities should be significantly reduced. Different values of ‘c’ may be used where specific application studies have shown them to be appropriate."
Eq. (1) is simple and easy to use, but it does not account for many factors contributing to erosion/corrosion. The only physical variable accounted for in Eq. (1) is the fluid density. The equation suggests that the limiting velocity could be higher when the fluid density is lower. This does not agree with experimental observations for sand erosion, because sand in gases with lower densities will cause higher erosion rates than liquids with higher densities. Therefore, the form of Eq. (1) does not seem to be appropriate for situations involving sand production.
Stimulating Sandstone Formations with non-HF Treatment Systems
Authors: Martin A. N. 
Published: December 2007

AbstractRecent advances in acidising technology mean that it is now feasible to effectively and efficiently stimulate sandstone formations, using acid systems not containing hydrogen fluoride (HF). Although quartz and certain silicate materials are not significantly dissolved by non-HF systems, there are a significant number of minerals and deposits that can be completely or partially removed. This means that formations that have been considered difficult to stimulate with HF-containing systems, may in fact be the best candidates for non-HF systems.Over the last decade, tremendous advances have been made in the application of HF-based systems in sandstone formations. The technology has moved from "hit or miss" conventional HCl:HF systems, to significantly more chemically specific systems. Such systems can be used with an extremely high success rate, when applied scientifically and systematically. Nevertheless, there are still many sandstone formations that cannot be successfully stimulated using even the most advanced HF systems, such as those with a high content of carbonate minerals or highly reaction-sensitive clays. However, non-HF systems are now available that can stimulate such formations successfully and cost-effectively - without causing damaging precipitation of acid reaction by-products or near-wellbore formation deconsolidation.This paper outlines the mechanisms of sandstone formation mineral dissolution by various non-HF acid systems, and more importantly, the prevention of post-treatment damage, including secondary, tertiary and quaternary precipitation reactions. It will also detail methods by which long-term improvement in productivity can be achieved in formations that are prone to suffer from scale formation or water production. Case histories will be used to illustrate application of these unique treatment methods.