bluuebunny/crossref_metadata_2025_split huggingface dataset:
Guidelines for Appropriate Application of Non-Foamed Ultra-Lightweight Cement Slurries
Authors: Dajani Ragheb , Curtis James 
Published: March 2009

Abstract
Technological advances in well cementing have made possible the use of ultra-lightweight (ULW) cement slurries with densities as low as 7.5 ppg, without foaming. These ULW slurries often achieve significant compressive strengths, even at moderate or low curing temperatures, such as in deep water environments. However, there are plenty of opportunities for disaster to occur when conventional cement slurry design criteria, laboratory testing procedures, and field practices are inappropriately applied to ULW cementing applications.
This paper will discuss the relevant issues that must be taken into account when planning a successful ULW cement operation, including materials selection, liquid volume fraction, surface and downhole densities and rheologies, compressive strength testing procedures, quality control measures, blending and bulk handling, operating error margins and on-the-fly mixing control systems.
As drilling activity continues to grow into depleted and low fracture gradient areas, especially in the offshore developments, adherence to the guidelines proposed in this paper will serve to improve the likelihood of successful ULW cementing operations.
Along String Pressure and Temperature Measurements in Real Time: Early Field Use and Resultant Value
Authors: Hernandez Maximo , Johnson Monte 
Published: March 2009

Abstract
High-speed drill-string telemetry technology is being adopted with increasing frequency into challenging drilling environments around the world. In addition to allowing instantaneous upward and downward transmission of data between surface and measurement tools located close to the drill bit, this technology also enables measurements to be acquired and transmitted to surface from many points along the string while drilling.
Real-time along-string annular pressure and temperature measurements have strong potential to provide never before seen visibility of the dynamics of drilling cuttings cleaning, equivalent circulating density (ECD) and fluid influx/loss issues at multiple points along a wellbore. In many cases this information is dramatically different from traditionally held assumptions and can be used to more effectively manage flow rates, mud weight, rate of penetration (ROP), string rotation and the use of lost circulation material to significantly reduce the risk of stuck pipe, formation fracture and excessive losses.
This paper shares and discusses previously unseen data from early field uses of along string pressure and temperature measurements with comparisons to normally available data from bottom-hole measurement tools. Particular attention is paid to the drilling decisions taken based on this additional information and the impact of those decisions on efficiency and well cost.
Case History: Successful Wellbore Strengthening Approach in a Depleted and Highly Unconsolidated Sand in Deepwater Gulf of Mexico
Authors: Fett Darryl , Martin Frederic , Dardeau Claude , Rignol Joel , Benaissa Saddok , Adachi Jose , Pastor Jorge 
Published: March 2009

Abstract
In early 2008, Total E&P-USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" TLP, in deepwater Gulf of Mexico. A pre-project geomechanics study identified that the mud weight/fracture pressure window in the depleted and highly unconsolidated ‘A’ reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing the 7" liner. The risk of losses was a primary concern since the well would be frac-packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a ‘flat rheology’ synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation.
The ‘designer fluid’ allowed the reservoir to be drilled through successfully, and the 7" liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore strengthening techniques.
The implication for the industry is that this technique can and should be considered on wells with similar challenges and risks as the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A post-mortem analysis will compare formation breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized.
Enhanced Real-Time Wellbore Stability Monitoring Using High-Definition Imaging With Wired-Pipe Telemetry
Authors: Wolfe Chris , Morris Stephen , Baule Ansgar 
Published: March 2009

Abstract
Many fields currently being drilled by the petroleum industry require the use of high angle, extended reach wells to access remote hydrocarbon deposits. Although pre-drill geomechanical modeling efforts are often carried out to define the mud weight window, many wells still experience significantly elevated drilling costs due to non-productive time (NPT) associated with wellbore instability. This can be attributed to many factors but is predominantly due to the lack of appropriate data while drilling. Since rock properties, stresses and pore pressure often vary from the pre-drill model predictions, critical wells frequently require real-time updating of the geomechanical models using relevant logging while drilling (LWD) data to facilitate accurate, real-time decision-making. In this paper, a case history is presented where memory-quality; high-definition LWD image logs were obtained via high-speed telemetry systems and used to assess wellbore conditions in real time. The high-resolution LWD images were used to detect faults/fractures, breakout and general hole enlargements. Relog images over known unstable sections were also obtained to ascertain the extent of time-dependent wellbore failure. These logs were successfully used to delineate the failure zones and apply the appropriate mitigating actions in real time.
BP Egypt uses RMR on Jack-Up to Solve a Top-Hole Drilling Problem
Authors: Hinton Andy , Seim Kjartan , Becker Gerhard , Kvalvaag Edvin , Jongejan Arthur 
Published: March 2009

Abstract
BP Egypt used a subsea pumping system on the Rahamat 1 well so that engineered mud could be used to drill the surface hole with returns to the Constellation II rig bypassing a large air gap. This was the first use of Riserless Mud Recovery (RMR) on a jack-up. It allowed 26" surface hole to be drilled and 22" surface casing to be set at 3755ft (1144m) Below Mud Line (BML) without major problems.
Firm sand prevents a 30" conductor being driven deeper than 167ft (51m) BML. The rig has a large, 130ft (40m), air gap and the water depth is just 62ft (19m). The result is a conductor shoe that can only support a column of 7ppg (0.8SG) fluid back to the rig. Inhibited mud, minimum weight 9.4ppg (1.13SG), was needed to control the formations. Seabed returns were unacceptable for environmental and mud supply reasons.
RMR installation / retrieval was mainly done off the critical path and did not need an ROV. The system took returns from the conductor at sea level and pumped mud with cuttings back to the rig. Mud was re-circulated after treatment. This allowed good control of the mud properties. Equivalent Circulating Density (ECD) pressure was reduced by (a) 3.5ppg (0.4SG) at the casing shoe and (b) 0.3ppg (0.04SG) at section TD compared to a full column of mud back to the rig. Mud losses in coarse sands were controlled by adding Lost Circulation Material (LCM) and fluid loss control material. The 26" hole was drilled to the planned depth. 22" casing was run and cemented while controlling the fluid level in the annulus (and therefore downhole pressure) with RMR. No losses were seen during these operations.
RMR allowed surface hole to be drilled with mud and returns to the rig because RMR removed the effect of the 130ft air gap. The alternative well design needed an additional liner, taking 20 days and costing US$10million (based on previous well). The additional advantage was that engineered mud was used throughout the surface hole resulting in greater hole stability.
Axial Force Transfer of Buckled Drill Pipe in Deviated Wells
Authors: Menand S. , Sellami H. , Bouguecha A. , Isambourg P. , Simon C. 
Published: March 2009

Abstract
Axial force transfer is an issue in deviated wells where friction and buckling phenomenon take place. The general perception of the industry is that once drill pipe exceeds conventional buckling criteria, such as Paslay-Dawson, axial force cannot be transferred down-hole anymore. This paper shows that, even though buckling criteria are exceeded, axial force transfer could be still good if drill pipe is in rotation. On the contrary, there exists sliding operations where lockup is observed, due to buckling, even though standard buckling criteria are not exceeded. This paper is intended to show and explain how axial force is transferred down-hole in many simulated field conditions: sliding, rotating, with or without dog legs. These new results have been obtained from an advanced model dedicated to drill string mechanics successfully validated with laboratory tests.
This paper will show applicable results for practical well operations where axial force transfer is an issue. These results will enable to give some guidelines to help the drilling engineer to select cases where conventional buckling criteria should be used cautiously. Indeed, simultaneous torque-drag-buckling calculations show that tubular can tolerate significant levels of compression, enabling to provide weight transfer to the drill bit, even though drill pipe is buckled. Others examples, in contrast, show that standard buckling criteria cannot predict the occurrence of buckling that may cause tubular lockup while tripping in the hole.
The applications of these results are numerous for all deviated wells such as horizontal or extended reach drilling wells. This paper should contribute to reduce unpredictable lock-up situations and improve axial load transfer performance.
MWD Vibration Measurements: A Time for Standardisation
Authors: Osnes Svein Magne , Amundsen Per Amund , Weltzin Tore , Nyrnes Erik , Hundstad Brita Lucie , Grindhaug Gaute 
Published: March 2009

Abstract
Since downhole vibration measurements were introduced in the early 1990's, these measurements have become extremely useful for improving drilling efficiency in most parts of the world. Most operators will specify a vibration sensor of some sort to be run with most MWD (Measurement While Drilling) and LWD (Logging While Drilling) applications.
Unlike most other downhole measurements, there is no industrial standard for how to sample, process and present the vibration data. This raises a few issues that this paper attempts to address: Vibration measurements from different companies cannot be readily compared – and it is not known if the different tools and systems will detect the same vibration mechanisms and/or severity of vibrationsVibration Specifications of MWD and drilling tools from different service providers cannot be compared. It is not possible to compare specifications of the various tools as these are given based on the individual service company's internal vibration definitions
This paper looks into the physics and statistics of how four major MWD service providers conduct their vibration measurements.
Even though all the service companies basically can measure the same physical parameters such as tri-axial accelerations and instant changes in downhole RPM (Revolutions Per Minute), the data are handled differently when it comes to the physical understanding of the data, as well as the statistical modelling of the vibration severities. To further confuse the issue, the data is also presented differently and on different severity scales.
The torque/RPM vibration measurement, commonly referred to as "stick-slip", is well documented by previous publications by the different companies (Chen et. al. 2006). The present paper mostly concentrates on how the different MWD companies measure, process, report and interpret their tri-axial data. An analysis is conducted to establish if the various service companies are tuned to look for the same type of vibrations, or whether different vibration patterns tend to be detected with the various procedures in place.
Finally, the need for an industry standard is highlighted, and the MWD industry is challenged to move towards standardisation.
Drilling Wells With Narrow Operating Windows Applying the MPD Constant Bottom Hole Pressure Technology—How Much the Temperature and Pressure Affects the Operation's Design
Authors: Arnone M. , Vieira P. 
Published: March 2009

AbstractNarrow pore / fracture pressure gradient margins (operating window) is translated as a real drilling hazard scenario, where a slight change in the bottom hole pressure conditions can lead to an increase the Non Productive Time (NPT) due to the time spent in solve a possible fluid losses and/or gas kick situation, or even worst, dealing with occurrence of blowouts. In specific and non rare cases, deep formations with small gap between pore and fracture pressure are un-drillable with conventional drilling practices because the frictional losses pressure (difference between the dynamic and static pressure) is greater than the existent operating window. Constant Bottom Hole Pressure (CBHP), one of a number of variants of Managed Pressure Drilling (MPD) enables "walking the line" between pore and fracture pressure gradient. The objective is to drill with a fluid that bottom hole pressure is maintained constant, whether the fluid column is static or circulating. The loss of annulus flowing pressure when not circulating is counteracted by applied surface backpressure. The basic of Constant Bottom Hole Pressure (CBHP) methodology is to accurately determine the change in bottom hole pressure caused by dynamic effects and compensate with an equal change in annular wellhead pressure. The bottom hole temperature as well as the hydrostatic head of the drilling fluid column increases with the well depth and both parameters have opposing effect in the resultant static and dynamic equivalent density. An increase in the hydrostatic and dynamic pressures increases the equivalent fluid density due to compression but an increase in the temperature causes a reduction in the equivalent fluid density due to thermal expansion. Conventionally, these parameters considered together results in a cancellation of effects. In the reality, this assumption should be carefully reviewed. The effect of temperature in annular pressures, on a MPD CBHP operation through narrow operating windows, can not be ignored due to the potential impact. Precise estimation of static and dynamic equivalent fluid densities is of essential importance for a successful MPD CBHP operation through narrow operating windows.
Drilling Automation: Technologies, Terminology and Parallels With Other Industries
Authors: Thorogood John , Aldred Walt , Florence Fred , Iversen Fionn 
Published: March 2009

AbstractDrilling Automation is a rapidly developing area of technology that is seeing growing interest within the drilling community. The SPE set up a new Technical Section devoted to the subject as it relates to downhole performance, and the IADC has created a committee with a focus on surface processes.As with any emerging technology, the associated jargon is evolving rapidly, and different terms are used by different groups to refer to similar concepts with the potential for confusion and misunderstanding. Automation efforts are being undertaken by numerous and diverse organizations and implementation of such interrelated offerings at the rig site need consistent interface criteria at each boundary to ensure efficient and safe operations.The purpose of the proposed paper is to describe some of the concepts already in operation and under development and to classify them into a number of key categories.The more significant interface requirements will be identified and key safety concerns will be highlighted. Parallels will be drawn with other industries to demonstrate analogues and suggest directions where and how further developments might be expected to lead.
Further Developments in Drill Pipe Fatigue Management: A Case Study
Authors: Zoanni R. F. , Everage S. D. , Wadsworth T. M. , Cassanelli J. P. 
Published: March 2009

Abstract
Industry advances continue to enable pursuit of more challenging drilling targets with complex well bore trajectories. Many of these targets are in costly deepwater and/or remote operating areas. Demand for a practical, field-proven drill pipe fatigue management system has grown as drill string failures due to fatigue contribute to a significant amount of non-productive time and cost. The response to this demand has been the development of an engineered approach that combines pipe section positioning and inspection scheduling based on estimated fatigue damage rather than rotating hours or footage drilled. Successful real-time field implementation with ongoing drilling programs demonstrates that the cumulative fatigue damage technique is a valuable and proven tool for risk mitigation and cost reduction.
The cumulative fatigue damage technique and its implementation have been introduced in previous literature [1,3,8,10]. This method of monitoring fatigue damage due to rotary operations allows the pipe to be evaluated under real-time operating conditions along a specific section or the entire length of the drill pipe. Monitoring begins at spud and is performed on each joint of drill pipe as it traverses along the well path to total depth (TD). This not only allows a quantitative measure of the relative fatigue damage accumulated joint by joint for the drill pipe, but also provides the opportunity to manage logistics, forecast pipe inspections and position pipe sections to minimize cumulative drill string fatigue damage.
The cumulative fatigue damage technique has been successfully applied in the field[1,10]. Hind casting, pre-drill planning and real-time analyses have been utilized for assessing drill string design as well as pipe management. The current case study further demonstrates the methodology introduced in the previous literature and illustrates the modeling and management of fatigue damage over a three well project. The subject operator originally anticipated that pipe inspection may be required before each well to mitigate costly historical drill pipe failures. However, the cost and logistical challenges of mid-program pipe inspection in remote operations could not be ignored. Described is the pipe management strategy employed to complete the drilling program without drill pipe failures and without the need for any mid-program inspections. In addition, the inspection results post TD of the third programmed well have been evaluated and correlated back to expected pipe damage, making this an excellent case study for the further deployment of this technology.
HPHT Drilling—New Frontiers for Well Safety
Authors: Paula R. R. , Ribeiro P. R. , Santos O. L. A. 
Published: March 2009

Abstract
In a scenario of huge investments in the quest for new oil and natural gas discoveries, the oil industry has reached a consensus: no easy fields to be developed remain undiscovered, especially in offshore environments. New and old challenges on well drilling such as drilled extensions over 6000 m, sub-salt drilling, very narrow operational windows, operational problems like lost of circulation, stuck pipe, and kicks are aggravated when drilling in high pressure and high temperature (HPHT) environments.
In the world's exploratory context, the occurrence of HPHT areas is an increasing trend. It is the materialization of the worst case scenario for well drilling and safety, formed by great challenges and operational, environmental, and economic risks. Field experience has shown that the economical risks have been overshadowed by the great premium target: increments on reserves. However, if the well safety aspect is dealt with the conventional approach, the oil industry is at risk of losing its investments, causing great impacts to the environment and also to the company's image. Since HPHT well construction costs are so much higher than those of traditional wells, the scope of knowledge and science on well safety, once limited to kick prevention and well control contingencies, are now an integral part of the technical and economic feasibility of well construction.
Within this context, this work surveys the best HPHT techniques and procedures practiced by the oil industry, presents the new researches and trends and shares some valuable lessons learned on Petrobras, operations in Brazil and throughout the world.
Kicks in Offshore UK Wells—Where Are They Happening, And Why?
Authors: Dobson J. D. 
Published: March 2009

Abstract
The first well on the UK Continental Shelf was spudded 44 years ago and the area has long been considered a mature province. Despite this, kicks are still a frequent occurrence.
Kicks occur across the entire UKCS area from the Atlantic margins, west of the Shetland Islands to the mature gas fields of the southern North Sea, where the first significant discovery was made in December 1965. Kicks occur in high pressure high temperature condensate exploration wells and in production wells in depleted, sub-normally pressured oil reservoirs. They occur during drilling operations and during work-over operations.
Analysis of data on well incidents held by HSE, the UK regulator, has identified where, geographically, kicks occur most frequently. Analysis also identifies the type of operation being carried out at the time and some of the more significant factors behind the influxes.
The purpose of this paper is to share the regulator's observations with industry. While well operators and drilling contractors hold in-depth information on individual incidents, it is the regulator that is often best placed to observe the wider picture.