bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Applications of Drilling Simulators in Student Recruitment, Teaching and Research Programs
Authors: Ahmed R. M. , Smith J. R. , Bohorquez V. B. , Koederitz W. L. 
Published: February 2010

Abstract
Drilling simulators have been used extensively for teaching, especially well control, and for analyzing drilling operations, such as cementing. They also have been used to research the impact of drilling phenomena like drillstring dynamics. New approaches to develop and apply drilling simulation systems have been undertaken as a collaboration between industry and academia at two universities: Louisiana State University (LSU) and The University of Oklahoma (OU). The project involves the design and development of two different drilling simulators: a physical drilling model and a drilling simulation system. The simulators provide physical drilling demonstrations and/or hands-on simulation exercises that had previously been unavailable in an academic setting. Although the approaches are different, both are designed and developed for use in recruiting, teaching and retaining students as well as conducting simulation studies and supporting ongoing research efforts.
This paper describes the design and capabilities of the two drilling simulators and how their use is being integrated into the petroleum engineering educational programs at both universities. These novel drilling simulators are expected to have a positive impact on the recruitment and retention goals of these university degree programs. To date, their limited integration into course curriculum appears to have impacted student learning, as evidenced by improved test scores when compared to those prior to simulator implementation. Other conclusions regarding the impact of these early applications include improved student comprehension of new concepts. Plans for evaluating the broader impacts resulting from future uses of these simulation systems include observation, student performance assessments on exercises, lab reports, and tests as well as interviews of students, faculty, recruiters and involved industry personnel.
Multilateral Wells Reduce CAPEX of Offshore, subsea Development in Australia’s Northwest Shelf
Authors: Lawrence Brett , Zimmerman Mike , Cuthbert Andy , Fipke Steven 
Published: February 2010

Abstract
Multilateral technology reduces the number of production well slots required to effectively drain a reservoir, resulting in time and cost savings. Having fewer discrete subsea wellheads translates into a major reduction of investment capital in offshore environments. Reducing the cost of the subsea infrastructure is the primary benefit of multilateral well architecture, but additional benefits include reduced top-hole drilling costs, reduced project execution time, accelerated production, increased productivity index and fewer rig moves.
To take advantage of the benefits, the appropriate multilateral technology must be selected to avoid introducing additional risk and non-productive time (NPT) to the project. The multilateral junction system that meets the requirements of the wells on the Northwest Shelf of Australia has a proven track record in subsea installations. For this application, a TAML Level 5 system is required to provide hydraulic and mechanical isolation of the connected wellbores. Over the past 10 years, TAML Level 5 multilateral technology has been used extensively in the North Sea, whereas the Northwest Shelf of western Australia saw its inauguration in the southern hemisphere.
This paper discusses the lessons learned from nine horizontal TAML Level 5 dual-lateral wells drilled offshore in the Van Gogh field. The Van Gogh field provides an excellent example of a field that was developed from start to finish with multilateral technology as the enabler. The project was successfully completed in the second quarter of 2009 with a significantly lower capital investment than would have been required to develop the field with single horizontal wells.
Power of Design: Solid Expandable Installation Sets Multiple New Records in Deepshelf HP/HT Well
Authors: Nylund Jay , Flaming Sarah , Mitrushi Kristaq 
Published: February 2010

Abstract
With each installation of solid expandable tubulars, the opportunity exists to redefine the operating parameters of this enabling technology. A recent planned-in installation of a 6,935 ft (~2,115m) solid expandable openhole liner not only set a record as the longest expandable installation to-date, but also marked the first offshore-well application that combined swellable elastomer technology and solid expandable tubulars.
Operators have relied on solid expandable tubulars to mitigate and manage downhole wellbore problems for several years. However, the recent fundamental change in advanced drilling engineering philosophy is to plan solid expandable liners into the basis of design (BOD) to preserve hole size and reduce non-productive drilling time (NPT). For example, the most-recent record-setting solid expandable openhole liner (7-5/8 × 9-5/8 in.) was planned into the wellbore architecture of a previously drilled well to help explore deeper high-pressure high-temperature (HP/HT) reservoirs approaching 24,000 ft (7,315m) TVD. The swellable elastomers used on the expandable system ensured the required zonal isolation for a successful leak-off test, thereby greatly reducing the possibility for costly cement squeeze operations.
This paper discusses how solid expandable liner systems have facilitated multiple exploration and development projects in the region to address drilling and completion challenges. This paper also describes how combined technologies enable a greater application realm and uses the record-setting case history to illustrate the value gained by planning and using solid expandable technology.
Nonproductive Time NPT Reduction Delivered Through Effective Failure Investigations
Authors: Hubbard Brad L. , Kadri Shabib J. , Crotinger Michael J. , Griffith James E. , van Oort Eric 
Published: February 2010

Abstract
Nonproductive time (NPT) caused by preventable tool and equipment failures in offshore drilling and completion operations typically accounts for 5% of well delivery time, but can reach as high as 30%[1]. This equates to millions of dollars per year that could have been spent on other well delivery opportunities. Mutual benefit exists for both operators and vendors to dedicate the time and effort necessary to consistently perform comprehensive investigations and develop effective solutions to mitigate risk of repeat failures. A one-sided or inadequately supported approach to failure response can lead to incomplete analyses and insufficient solutions that treat symptoms rather than root causes, thereby sustaining or creating reliability gaps and allowing further NPT to be incurred.
In recent years, Shell’s Gulf of Mexico (GOM) drilling operations formed a specialized, dedicated team to establish and facilitate an effective, sustainable approach to failure response. The team’s immediate goal was the reduction of NPT cost associated with drilling tool failures. Long term, the team’s objective was to promote a culture within both operator and vendor organizations for effective failure prevention and performance improvement. Via this team consistent representation, influence, and support is maintained during failure response activities. The team enforces vendor failure response expectations and ensures complete, unbiased analyses and solutions with appropriate local, regional and global communication within operator and vendor organizations, such that the chance of repeat failures anywhere in the industry is minimized.
Since inception, the team’s efforts have facilitated a significant reduction in NPT, which translates to yearly multi-million- dollar savings. Given its evident success, the scope of this initiative has been expanded within the Americas and also in global operations. This paper reviews the approach and process, clarifies the roles, responsibilities and accountabilities for both operator and suppliers, highlights the mutual benefits for operators and vendors, and illustrates the effectiveness of the approach through its very positive impact on operational NPT reduction.
Fully Automated Pipehandling System on a 6th Generation Drilling Vessel
Authors: Rohde Kjell , Berg Tore , Yost Tom , Aanesland Svein Ove , Kudsk Gregers 
Published: February 2010

Abstract
Drillfloor equipment controls and associated equipment on the latest generation of floating drilling vessels have evolved into a "system" of computer controlled machines that are currently operated by multiple operators each running these machines from a series of dedicated control stations. The latest drilling vessels utilize as many as three (3) operator stations to drill the well, trip the tubulars, or perform offline activities such as stand building. These stations all individually control their respective machines, but do require constant "multi-tasking" operations by their operators which results in inefficiency and operator fatigue.
A multi-machine control (MMC) system for automatic control of the hoisting, rotating, and pipehandling systems has been executed on a recently delivered 6th Generation Semi. The MMC allows full automatic control of these systems from ONE Operator using ONE joystick.
This paper will discuss the control system and machine hardware and software and how the development process has taken this technology from a "concept" to a working drilling and tripping machine that adds value, efficiency, and safety to what has previously been a multiple operator station deliverable.
Utilizing an Engineered Particle Drilling Fluid to Overcome Coal Drilling Challenges
Authors: Zeilinger Sabine , Dupriest Fred , Turton Ryan , Butler Hayden , Wang Hong (Max) 
Published: February 2010

AbstractBorehole instability and stuck pipe while drilling coal can lead to significant non-productive time. This paper describes a drilling fluid developed to stabilize coals in a program that was previously unable to achieve all extended reach objectives. The fluid design principles are believed to apply broadly in stabilizing coals, fractured shale, and other cleated formations.The rock mechanics that govern instability in coals is identical to shale. However, coal instability often does not respond to the same remediation used in shale, which is to simply raise the mud weight to reduce the compression hoop stress to below the strength of the rock. Despite using an optimum mud weight, hole breakout or borehole collapse may still occur when the coal cleats and natural fractures of the coal allow the drilling fluid filtrate to invade. This leads to a pressurization of the near- wellbore region and loss of the effectiveness of mud weight support for coal stability.A fluid was developed based on the belief that the wellbore is stabilized with increased mud weight if the additional pressure acts specifically on the face of the borehole. This stabilization effect can be achieved by preventing pressure penetration into the near-wellbore region through coal cleats or natural fractures. The fluid design developed included bridging particles with a size distribution based on analysis of the coal cleat apertures, as well as filtration control material to effectively reduce the permeability of the bridge. Sealing alone does not provide stability and an analysis of the coal strength and in-situ stresses were conducted to select a mud weight that would stabilize the very weak coals.The paper discusses the rock mechanics concepts, fluid design criteria for determining the allowed leakage rate when designing the bridging process, and the operational learnings from implementation. The use of the coal stabilization fluid and stability mud weight allowed the objectives to be achieved and contributed to record performance in this a narrow-margin drilling environment in Australia.
Well Delivery Process: A Proven Method to Improve Value and Performance While Reducing Costs
Authors: de Wardt John P. 
Published: February 2010

Abstract

Description
A Well Delivery Process defines a set of activities along a time line to plan, execute and close out a well. The most advanced versions of this process include tools and techniques that create robust plans including risk and uncertainty management, technical limit focus and stretch goals, probabilistic time and cost estimating, detailed scheduling, Drill / Complete the Well on Paper and similar group exercises. Stage gates are included that provide review points which are usually matched to a corporate Capital Value or Opportunity Realization Process. The most advanced form of the process incorporates best practices from Lean Manufacturing. The paper describes best practices in the development of a Well Delivery Process.

Application
The Well Delivery Process applies to all wells in a scalable format whereby a longer term, more detailed process is used for Exploration Wells and a simpler, shorter duration process for repeatable development wells. It covers work processes between departments, especially subsurface and drilling, and between the suppliers and the oil company, as well as between suppliers. An actively maintained Well Delivery Process provides the means to capture lessons learned and to retain knowledge within a company.

Results, Observations, Conclusions
In a West African offshore operation in a marginal field development with complex wells, the application of a Well Delivery Process resulted in best in class performance in an industry benchmark survey (Rushmore Review). This included a 77% reduction in non productive time. Added value was achieved through increasing the typical well productivity by more than 33%.
In the N Sea, a horizontal well drilled from a semi sub achieved an overall drill rate of 171 m / day versus a historic average of 80 m / day. Well cost was reduced by 30%.
A N Sea operator improved from 3rd quartile to 1st quartile performance while another improved overall drilling performance by more than 30%.
Reviews of drilling performance in two different regions demonstrated the correlation with poorer performance when there was insufficient lead time for proper planning according to the Well Delivery Process due to late and frequent drilling sequence changes.
Lessons learned are described including the correlation of performance with robust risk assessment
Recommendations on the key characteristics for a successful Well Delivery Process are described.

Significance of Subject Matter
A best practice and robust Well Delivery Process is essential for high cost drilling operations and challenging drilling environments whether exploration wells or infill drilling in depleted reservoirs to small hydrocarbon accumulations. This paper will provide an essential guide to Drilling Managers wishing to develop a Well Delivery Process.
The paper also introduces Business Process distinctions for different types of wells from project based exploration through Factory Drilling which impact the application of a Well Delivery Process.
Hybrid Bits Offer Distinct Advantages in Selected Roller Cone and PDC Bit Applications
Authors: Pessier Rolf , Damschen Michael 
Published: February 2010

Abstract
Early concepts of hybrid drill bits go back to the 1930's but the development of a viable drilling tool has only become feasible with the recent advances in polycrystalline diamond compact (PDC) cutter technology. This paper describes a new generation of hybrid bits that are based on proven PDC bit designs with rolling cutters on the periphery of the bit. Laboratory and field results will be presented that compare the performance of hybrid bits with that of conventional PDC and roller cone bits. A hybrid bit can drill shale and other plastically behaving formations two to four times faster than a roller cone bit by being more aggressive and efficient. The penetration rate of a hybrid bit responds linearly to RPM unlike roller cone bits, which have an exponential response with an exponent of less than one. In other words, the hybrid bit will drill significantly faster in motor applications. Another benefit is the effect of the rolling cutters on bit dynamics. Compared to conventional PDC bits, torsional oscillations are as much as 50% lower; stick/slip is reduced at low revolutions per minute (RPM), and whirl at high RPM. This gives the hybrid bit a wider operating window and greatly improves toolface control in directional drilling. The hybrid drill bit is a highly application-specific drill bit aimed at 1) traditional roller cone applications that are rate-of-penetration (ROP) limited, 2) large diameter PDC and roller cone bit applications that are torque or weight-on-bit (WOB) limited, 3) highly interbedded formations where high torque fluctuations can cause premature failures and limit the mean operating torque, and 4) motor and/or directional applications where a higher rate of penetration and better build rates and toolface control are desired.
Real Time Drilling Data Analysis: Building Blocks for the Definition of a Problem Anticipation Methodology
Authors: Gandelman R. A. , Martins A. L. , Teixeira G. T. , Waldmann A. T. , Aragão A. F. , Mari A. D. , Strugata V. A. , Rezende M. S. 
Published: February 2010

Abstract
The drilling industry has invested a lot, in the recent years, in the development of tools to measure and transmit real time drilling data. These technologies enabled obvious gains in wellbore orientation and navigation besides providing useful alerts of downhole conditions. There is a common sense among operators, however, that there is a misuse of such data in anticipating and remediating drilling problems. Pressure while drilling (PWD) data, for instance, is used in a subjective manner and interpretation depends a lot on the operator philosophy. The correct interpretation of PWD data is a powerful tool to identify and avoid problems, reducing operational risks, time and costs, especially in deep and ultra-deepwaters.
This article deals with the construction of an integrated methodology aiming the diagnosis and anticipation of drilling problems before they occur. The philosophy is to consider the wellbore, the reservoir vicinity and the drillstring as an integrated domain to be inspected, as a doctor would analyze a human being, considering body and mind. The drilling fluid which flows through all the portions of the domain, behaves as the human blood and its local pressures may reflect symptom of any abnormal behavior. In this way, pressure analysis would constitute the central core of the diagnosis system. Pressure analysis depends on several aspects, including solids segregation and loading, surge/swab effects, gel breaking, temperature and pressure dependency on fluid properties, etc.
The system, however, requires more information to help in the diagnosis task: that is where the several additional blocks coupled with the central core provide additional aid. Geopressures, torque & drag, temperature profiles, wellbore stability etc are different aspects to be considered.
Can Aluminum Drill Pipe Extend the Operating Envelope for ERD Projects?
Authors: Jenkins Mark , Rodriguez Alejandro Castro , Linke Christian , Mader Georg , Davies Mark J. 
Published: February 2010

Abstract
One of the many challenges for the industry is how to extend the limits from rig capacities without significantly increasing cost; this is a perpetual problem which will continue to challenge the industry as the perceived norms for well designs are driven forward, with the need to tap into ever deeper and more distant targets. A way to address this challenge is to use a lighter drill string.
The objective of this investigation was to determine whether, by reducing string weight and changing the material properties of the drill string it is possible to extend the operational envelope of the drilling rig; without having a detrimental impact on the drilling process. A field testing program was carried out on a full-scale experimental drilling rig in Oklahoma, USA. To test this hypothesis, steel drill pipe (SDP) was exchanged for aluminum drill pipe (ADP). By utilizing this methodology, it is possible to greatly reduce the weight of the drill string without significantly reducing its mechanical integrity.
Two representative, well-known geological sections on separate wells were drilled with a string containing ADP. Extensive surface and downhole datasets were obtained on these wells. Dynamic drilling data was recorded at three discrete points along the drill string. At two of these three points, mechanical drilling data was also collected.
An advanced modeling package was used during the planning phase of these wells and during the post-drilling analysis of the datasets. Through interpretation of the results from the testing program and by extensive modeling, it was possible to extrapolate the extent to which the operating envelope may be extended. These models were then used to challenge Extended Reach Drilling (ERD) profiles and investigate if the drilling envelope could be extended by applying ADP to future projects.
Particle Size Distribution Improves Casing-While-Drilling Wellbore- Strengthening Results
Authors: Watts R. D. , Greener M. R. , McKeever S. , Scott P. D. , Beardmore D. 
Published: February 2010

Abstract
This paper describes the application of particle size distribution principles for determining materials to be added to the mud system during casing while drilling operations. Casing while drilling (CwD) has been demonstrated to stop or significantly reduce lost circulation and improve wellbore strength. The mechanism by which this improvement occurs is not understood, however the results from this work significantly advance what is needed to get repeatable results.
If wellbore strengthening can be systematically achieved, then wells can be drilled in known loss areas without contingency strings of casing. In addition, wells drilled in mature fields, where producing horizons have altered pressures either from depletion or pressure maintenance, can be drilled with fewer casing strings. Sidetracks become economical because hole size can be preserved for an effective completion and well costs are lowered by not using additional liners to reach the objective.
By adding particles to the mud to fill in the particle size distribution, losses to natural fractures were stopped while directional wells were drilled with casing in the Piceance Basin of Colorado. Applying what was learned in a field trial of casing while drilling in the Alaskan Tarn Field, the open hole leak off resistance was improved by 3.0 pound per gallon (ppg) drilling with 7.0 inch casing in a 67 degree angled well. With this success, a four well casing while drilling campaign was executed with two wells drilled each in the Kuparuk and Tarn fields on Alaska's North Slope. Results were positive for 7.0 inch and 7.625 inch casings but wellbore strengthening did not occur sufficiently in the 5.50 inch casing trials. Annular clearance appears to be a critical component to success and is not yet fully understood.
The results demonstrate that a significant improvement in fracture gradient can be achieved with the right clearance between the hole and the casing and the proper sized particles added to the mud system. In addition, the amount of material added has been demonstrated to be as low as two pounds per barrel. With confidence that strengthening can be achieved to the levels of improvement demonstrated, wells can be evaluated with significant cost savings by eliminating casing strings and preserving hole size for completions or further drilling.