bluuebunny/crossref_metadata_2025_split huggingface dataset:
3D Displacement Simulator Realistically Predicts Free Fall during Cementing
Authors: Chiney Abhinandan , Yerubandi Krishna Babu 
Published: October 2013

Abstract
Understanding equivalent circulating density (ECD)/downhole pressure is important for a successful cement job design and execution. One of the critical parameters to control ECD is the pumping rate, which, in turn, controls the wellbore fluid rates. But, in some cases, specifically when pumping heavier fluids, the well might go into a scenario called "free fall." During free fall, the fluid in the wellbore loses physical contact with wellhead/pump and flows on its own under the influence of gravity, making control of ECD difficult from the surface. For a well under free fall, the dynamics of wellbore rate depend not only on the densities but also on the movement of the wellbore fluids. Traditionally, job design simulators assumed flat fluid interfaces, thereby compromising on the accuracy of wellbore rate estimation. A more accurate estimation of the fluid movement/flow patterns would help operators better predict the pressures.
In the present work, a free-fall algorithm is implemented to complement a three-dimensional (3D) displacement simulator. The displacement simulator solves momentum balances, continuity equations, and scalar convection-diffusion equations on top of a 3D grid to provide fluid flow profiles in three dimensions. The simulator is capable of simulating intermixing of fluids and the resultant frictional pressure drops. This paper presents, for a model wellbore configuration, the differences in free-fall estimation and the resultant differences in ECD estimation between a traditional hydrostatic job design simulator and a 3D simulator. Traditional hydraulics is observed to be conservative for estimating wellbore rates compared to the 3D simulator during free fall, which can result in predicting lower than actual ECDs.
Advanced Bottomhole Assembly Design and Motor Technology Extends Reach and Optimizes Well Placement in Challenging Middle East Wells
Authors: Dabyah Ali Al , Toutoungy Fadi , Aldawood Jahad , Al-Madan Mohammad , Hudaithi Mohammad Al 
Published: October 2013

Abstract
Poor drilling performance can lead to increased costs when enhanced drilling performance and extended reach are the main goals for oil operators. Service companies, using the latest technology, can achieve these objectives.
A rotary steerable system (RSS) with advanced motor technology provides significant performance improvements. In addition to the improved drilling performance, the advanced system enables extended reach drilling to wells that were previously beyond the limits of a project.
This paper presents the advances in motorized RSS technology and bottom-hole assembly (BHA) design considerations that provide increased drilling performance, thereby enabling faster well delivery and extended drilling. In addition, the authors examine ongoing initiatives aimed at reducing drilling risk (vibration and torque) and optimizing well placement.
The motorized RSS technology has been used in many applications, including open hole side tracking, whipstock drill-off, cement plug side tracking and horizontal section drilling. In most instances, the technology demonstrated the capacity to deliver better penetration rates and directional control that outperformed conventional directional drilling systems. Using a motorized RSS BHA to drill-off the whipstock saved rig time by eliminating one trip in each offshore oil lateral. In addition, the nearly 25.6% improved rate of penetration (ROP) was one of the main impacts for using the motorized RSS BHAs in an onshore oil field.
The paper describes the experiences from two case studies in the Middle East. The extremely long, extended drilling of a horizontal section of an offshore field, and the successful targeting of a thin reservoir while exceeding ROP targets in an onshore field.
Automated Downhole Vibration Damping
Authors: Hutchinson Mark 
Published: October 2013

Abstract
Automated downhole rotary steering devices that were developed in the 1990's for directional control were initially d eployed on extended reach wells. They are currently more widely applied to improve both drilling performance and wellbore quality. Automated surface control systems have also been developed for safer pipe-handling, downhole pressure control and for mitigating stick-slip when induced by cumulative friction along the drill string. A novel self-adapting downhole drilling tool can now autonomously detect and suppress excessive downhole shock and vibration levels by adjusting the stiffness of its damping fluid which in turn instantaneously changes the vibration characteristics of the bottom-hole-assembly.
The downhole drilling environment is continuously and unpredictably changing as the drill string gets longer and as stabilizers navigate around micro-doglegs or past geological strata where the borehole has enlarged and no longer provides stabilization. Whenever the driller (or an automated control system) makes changes to the surface drilling parameters this also changes the downhole vibration characteristics. Each blade of the bit can additionally induce torsional shocks as it alternately cuts softer and then harder rock at a lithological transition in an inclined borehole when the formation on the upper side of the wellbore circumference is harder or softer than that on its lower side.
In order to respond to a frequently changing environment, vibration sensors in a shock-sub send data to its autonomous control system with an intelligent algorithm that iteratively adjusts the stiffness of a magneto-rheological damping fluid in response to the severity of the various modes of downhole vibrations. In this way the novel self-adapting shock-sub seeks out the optimal dynamic stiffness of the drilling assembly for each change in the downhole drilling environment.
This paper presents insights as to the nature of downhole vibrations encountered when drilling in the Middle East, describes the intelligent self-adapting shock-absorber, examines some of the characteristics of a magneto-rheological damping fluid and explains how the intelligent shock-absorber can be configured for various drilling scenarios.
First Fully Sulfide Stress Cracking Resistant Drill Pipe System for Critical Sour Drilling
Authors: Jellison M. , El-Rayes K. , Al-Khanferi N. 
Published: October 2013

Abstract
As the severity of sour drilling applications has increased the need for drill stem materials resistant to Sulfide Stress Cracking (SSC) has accelerated. This is especially true in the Middle East with some of the most severe H2S environments in the world. Sour service drillpipe, built with SSC resistant tubes and tool joints, has been available for some time. The friction welds joining the tubes and tool joints were not SSC resistant. This has been acceptable for many sour applications since the weld is not the high stress area of the drillpipe and because the operator has some control over the environment through the drilling fluid properties and additives. As more severe H2S environments were identified for exploration, it became apparent that a fully SSC resistant drillpipe system including the friction welds was necessary. This paper presents the successful development of SSC resistant friction welds for critical sour applications. It describes the engineering and manufacturing philosophy, laboratory testing procedures and results and applications for the SSC resistant drillpipe. Since NACE MR-0175 does not cover friction welds the engineering team developed unique and innovative criteria and testing procedures. A new patent pending four point bending test procedure and fixture were develop that employed unpolished samples that represent the surface finish of the product in service, unlike polished samples typically used in NACE TM-0177 testing. This paper provides background information on the evolution of sour service drillpipe and reviews case histories where sour service drillpipe has been successfully used including the new pipe with SSC resistant friction welds. A preview of some vital planning considerations for an upcoming world-class ERD well in Saudi Arabia with high H2S concentrations is also included. The paper can benefit drilling engineers involved in critical sour drilling operations in the Middle East and other world regions.
Remote Operations Centers and Re-engineering Work Processes: Retaining Competent Personnel in an Extremely Competitive Marketplace
Authors: Saeverhagen E. , Kellas R. , Bouillouta F. 
Published: October 2013

Abstract
During the last 5 to 6 years, the utilization of real-time operations centers has gradually expanded to comprise a wide range of remote services traditionally handled at the rigsite. Some oil and gas operators have reduced the footprint for new and mature fields, which has driven the need to re-engineer the traditional work processes carried out at the rigsite. Another driver is the reduced availability of competent personnel. Over time, several functions have changed and merged into one common operation. In addition, multiple functions have been relocated from the rigsite to centrally located operations centers where the "digital part" of the jobs is now performed. Field personnel have undertaken in-depth cross training to perform new, more hands-on functions, and senior personnel have undertaken key functions in the real-time operations centers. The new remote operations approach, transforming several traditional rigsite positions, requires changes in the individual's thought and skill set. Oil and service companies, therefore, are developing and adopting new remote operations strategies for the workforce to meet the ever-increasing demand for efficiency and automation. The underlying challenge is the availability of younger competent personnel in an industry that will soon experience a workforce demographic age gap, as the aging workforce retires over the next decade. The remote operations initiative enables retention of highly competent senior personnel in the operations centers, providing knowledge transfer, cross-discipline training and efficient and effective operational advice to the workforce in the field as well as to the client.
The paper presents the evolution of remote operations over a decade with examples and effects, and discusses how remote operations centers, driven by new digital technologies and work processes, will influence the industry in the future.
Fully Rotating PDC Cutter Gaining Momentum: Conquering Frictional Heat in Hard/Abrasive Formations Improves Footage Totals
Authors: Zhang Youhe , Burhan Yuri , Chen Chen , Tammineni Sandeep , Durairajan Bala 
Published: October 2013

Abstract
A fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts formation and as the cutter wears/chips drilling efficiency declines. It is well documented that wear flats generate a high degree of frictional heat which breaks the diamond bond. To solve the issue an R&D initiative was launched to investigate different methods to enable a PDC shearing element to rotate while drilling to increase overall cutting efficiency and bit life. Engineers investigated different retention methods to create the optimal driving force and allow full cutter rotation.
The assemblies were modeled using an FEA based engineering system and then tested in the laboratory to evaluate function and strength. Experiments confirmed the new rolling cutter (RC) was able to shear an extended section of rock with a consistent force level (lbs). A traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency.
The recent introduction of a new rolling cutter PDC bit that utilizes the entire 360° of diamond edge has delivered positive results in field trials. Initial testing was targeted at the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. A six-bladed prototype PDC bit, with three rolling cutters positioned in the shoulder area was run on PDM and increased total footage capabilities compared to conventional PDC.
The next prototypes were equipped with a smaller, yet more robust generation-3 retaining device. Starting in Q4 2012, the total RC count/bit was progressively increased on five/six bladed designs from 3, 5, 7, 10 and then 12. The 13mm designs are consistently exceeding footage totals compared to offsets in central USA, North Dakota and Canada. In central USA, which contains the largest data set (13 RC runs) the rolling cutter has increased average footage totals by 34.4% compared to offsets drilled with standard PDC from various manufacturers. Case studies will document performance improvement in these challenging drilling environments. The authors will discuss plans to develop a rolling cutter bit to extend lateral run length in an abrasive Middle East formation.
South Oman Well Engineering: Where Creativity Runs Deep
Authors: Hammour Abdel-Moneim Abdel-Fattah , Al-Battashi Yousuf 
Published: October 2013

Abstract
Creativity and innovation in well delivery are key drivers for overcoming the challenges arising from fields' maturation and the need to maximize the recovery factor via new technology and unconventional ways of problem solving. In spite of steady performance improvements and many broken drilling records achieved, through many years of drilling operations, the South Oman Well Engineering Team (UWS) are continually looking for areas of further improvement and going beyond the previous field records by applying different techniques such as in-depth wells' detailed design, Global Well Delivery Process, Provocative Concepts, Lean, "Out of Box Thinking Approach"etc.,.
Recently; the team has successfully optimized the casing design for one of the most common oil producer well types simply by tapering the bottommost 40 m of the 9 5/8-in. production casing to 7" casing size complete with 7". casing floats. This eliminate the dedicated trip to drill out the 9 5/8-in. float equipment with an 8-1/2" drilling assembly, as the reservoir section is designed to be drilled with 6-1/8" bit and cased with 4-1/2". WWS (Wire-warped screens) including EZIP (Open Hole Swellable Packer). With in excess of 20 of these well designs per year a saving of USD 15,000 on consumables and 8 hours of rig time are realized per well completed. The potential saving is USD 300,000 over the course of the year.
Lean principles have been deployed in the most standard horizontal well type where the team has taken advantage of the programmed 6 hours waiting for wellbore acid soak to lay down the excess drill pipes and prepare the completion tubing in stands. This job, conducted some ±120 times per year represents a saving of USD10,000 per well. The potential saving is USD 1.2 Million over the course of the year
Shallow gas drilling practice has been challenged and updated. The surface hole in South Oman is characterized by medium to hard rock (limestone interbeded by gypsum with little strikes of shale and Anhydrite) of 14 kpa/m fracture gradient. Total losss of drilling fluid in these shallow formations is always seen at around ±420 m depth (UER formation). Traditionally a divertor system is used instead of a BOP when it is thought that the surface formations have insufficient strength for a kick to be shut in with the BOP without breaking down or cratering the surface formations.
The two conditions mentioned above makes the the risk of rig cratering unlikely therefore the use of 13-3/8" Diverter system has been phased out and replaced by 13-3/8" BOP system for the whole well operation. This has saved Diveter system rental cost and installation time. This job is being repeated ±40 times per year saving USD 25,000 per job, a yearly saving some USD 1Million per year.
The Importance of Acceptable Electrical Power Quality to the Drilling Industry Worldwide
Authors: Evans Ian C , Al Khaimah Ras 
Published: October 2013

Abstract
Electrical power quality is routinely taken for granted by oil and drilling industries worldwide despite the fact that the quality of electrical power is fundamental to the safety and operational integrity of drilling rigs and oil production platforms worldwide, without exception. US$100m's are lost each year, direct and indirectly, due to poor quality of power.
Currently some offshore safety authorities are considering the imposition of strict limits on harmonic voltage distortion in their jurisdiction. Harmonic voltage distortion may become a regulatory issue in the future.
This paper examines the salient harmonic and power quality issues onboard drilling rigs with full SCR drilling packages, as well the more recent hybrid (mixed SCR and VFD drives) and full VFD (variable frequency drive) drilling packages.
With SCR drives the main problems are harmonic voltage distortion, line notching and voltage spikes which destroys capacitors inside equipment. Low generator power factor is also often an operational problem.
For VFDs, harmonic voltage distortion is also a problem but increasingly so is excessive common mode voltage caused by VFD operation which disrupts susceptible electronic equipment.
The paper will offer advice on proven solutions for common power quality problems and introduce a remote/local power quality monitoring system which can be easily retrofitted to existing rigs and platforms.
Formation Damage Evaluation of Drill-in Fluid Lubricant Products for Optimized Production in Low-Permeability Gas Reservoir
Authors: Osode Peter , Otaibi Msalli , Bataweel Mohammed , Ammari Saleh , Himes Ron 
Published: October 2013

Abstract
Conventional lubricant products composed of different surfactant materials are required in water-based mud for drilling highly deviated and horizontal pay zone sections due to their lubricity associated with torque reduction and better penetration rate. Drill-in fluid (DIF) filtrate-induced formation damage in low-permeability gas reservoirs as a result of water blockage and reduced relative permeability to gas can be significant in view of the high capillary pressure associated with small pore throats. Formation damage risk assessment of the drilling lubricants utilization was therefore considered critical for a low-permeability gas reservoir development project.
Lubricant product evaluation experiments were designed to provide the production impairment potential measurements using Berea and Unayzah sandstone cores with a laboratory formulated DIF and base brine containing 3–4% lubricant by volume and to confirm fluid compatibility with divalent salt (CaCl2) brine. Fluid compatibility and emulsion risk was investigated using mineral oil as the representative formation hydrocarbon fluid. Core flood and dynamic filtration tests were carried out at an estimated bottom-hole temperature of 250 °F and pressure of 1,000 psi for the high-temperature reservoirs while the compatibility tests were carried out at room temperature. Filter cake removal tests were also performed by using high pressure, high-temperature filter press equipment and synthetic disks to determine filter cake removal efficiency with acid brine breaker fluid.
The obtained results from the laboratory study were integrated to evaluate and rank the lubricants based on their assessed formation damage risk. The test results showed that both lubricant return permeability and compatibility tests were important in selecting the best performance lubricant.
This paper discusses the experimental analysis of the formation damage potential of 12 commercially available water-based mud (WBM) lubricants. It also provides an insight into the formation damage (FD) impact of the drilling fluid lubricants on gas reservoir deliverability.
Precise Gain and Loss Detection Using a Transient Hydraulic Model of the Return Flow to the Pit
Authors: Cayeux Eric , Daireaux Benoît 
Published: October 2013

Abstract
Abnormal variations of pit volume are a prime indicator of mud losses and formation fluid influxes. However the detection of gain and loss at the pit level can be difficult because of the transient behavior of several components in the hydraulic loop. For instance, during circulation the compressibility of the drilling fluid changes the total volume of mud needed to fill the well compared to static conditions. Similarly, changes of the drilling fluid temperature modify the volume of mud due to its thermal expansion. Furthermore, the transport and separation of cuttings also influences volume variations in the pit. Finally, the retention capacity of some of the mud transport and treatment equipment (e.g., return flow-line, shakers, sand-trap, degasser, transfer pit) has a direct impact on the active pit level. All of these effects are transient and can cause substantial variations of the active pit volume that may be interpreted as gain or loss while they actually have natural origins.
Most of these effects are well known and are dealt with in a pragmatic way by using finger printing between the current pit volume variation and a reference pattern obtained in similar drilling conditions. Nevertheless, the finger printing method has its limitations when the current drilling condition variation does not have an obvious reference pattern. In addition, it necessitates a selection of the reference pattern by an operator and therefore is rather difficult to automate.
This paper describes in detail a transient hydraulic model of the downhole and surface equipment effects on the pit volume variations. Several use cases are also described including early kick detection with small margins during pump shutdown and detection of tiny gains during draw-down tests used in an MPD (Managed Pressure Drilling) operation.
Minimizing Phase Trapping Damage Using Malaysian Diesel Oil
Authors: Lashari Arshad A. , Shuker Muhannad T. , Bahrami Hassan , Memon Khalil R. , Memon Faisal H. , Kumar Sandeep 
Published: October 2013

Abstract
The low permeability and tight gas reservoirs are problematic throughout of their development (drilling, completion, stimulation and production) around the wellbore. However, they required advanced improvement techniques to achieve flow gas at optimum rates.
Phase Trapping or retention of fluids is a form of mechanical formation damage mechanism, which is caused by fluid invasion into formation, and also when liquid leak-off into formation during fracturing stimulation near the wellbore. Low permeability and tight gas reservoir are sensitive to water invasion damage results create water blocking and phase trapping damage due to high critical water saturation, relative permeability effects, capillary pressure and Interfacial tension between produced fluid and wellbore fluid. Proper evaluation of damage and its factors which influenced its severity is essential for prevention and optimizing well productivity.
Thus, this study is presenting both laboratory experiments and simulation to evaluate phase trapping damage. In which, the core flooding was performed to evaluate permeability damage by using Malaysian diesel-oil drilling fluid in comparison with water based drilling fluid. Further, interfacial tension was tested between produced gas and wellbore fluids at different temperature and pressure conditions. The effect of interfacial tension on phase trapping damage was observed and validate with the result of core flooding experiments where the affect of water injection and diesel-oil injection on core permeability was studied and shown. Reservoir Simulation approach was also used to study the effect of relative permeability curves on phase trapping damage and its impact on well productivity. The result highlights the benefits of using Malaysian diesel-oil in drilling and fracturing the low permeability and tight gas reservoirs in meaning of 30% increment in well productivity compared with water based fluid.