bluuebunny/crossref_metadata_2025_split huggingface dataset:
Riserless Reelwell Drilling Method to Address Many Deepwater Drilling Challenges
Authors: Rajabi M. Mir , Nergaard A. I. , Hole O. , Vestavik O.M. 
Published: February 2010

Abstract
Drilling a well in deep oceans is a daunting task due to both downhole drilling hazards and excessive floating rig package. Traditionally many of these challenging wells are drilled with a low-pressure 21" marine drilling riser stretched from mudline to surface. A huge rig with high weight, space, and tensioning requirement is vital to handle this monster fluid conduit. Moreover, a reliable station keeping system is essential for the rig to keep it in a very tight operating radius to have drilling operations running uninterruptedly.
When we move to deeper waters and harsher environments, it becomes more difficult, and in many cases becomes even impossible to reach reservoir targets in such challenging environments. The problem of narrow formation pressure window also exists and adds up.
Reelwell Drilling Method has been proven by series of tests and theoretical studies to have the potential to alleviate the main drilling challenges by (1) elimination of the marine drilling riser to extend the capability of drilling in ultra deepwaters, (2) providing a closed-loop circulation system to make it possible for the industry to deploy Controlled Pressure Drilling (CPD) techniques and overcome many downhole pressure related challenges including narrow pressure window which is a common problem in deepwaters (Mir Rajabi 2009).
Closed-Loop Control for Decision-Making Applications in Remote Operations
Authors: Ornas Jens Ingvald 
Published: February 2010

Abstract
New technology and standards are affecting the way traditional control systems, used for operating Drilling Equipment, are prepared for interaction with Drilling by Wire systems or other systems that are capable of intervening directly in the drilling process.
It is well understood that there is a gap between available real-time data from a drilling operation and the cost effective utilizing of this data. Improvement will come from systems that are closing the loop, by analyzing parts of t he real-time information space – and directly intervene with the drilling equipment control, leading to better well placement and less wear on critical drilling components.
Remote and harsh environments, e.g. arctic regions, add motivation for increased inter-operability. Safe and reliable remote operation of drilling equipment will make it possible to reduce on-site manning, and thus reduce risk and cost involved in the drilling operation. Such systems will need a higher level of automation and will rely on a common, computer readable "understanding" of the drilling domain.
In order to achieve this – we need to find new methods to interact with both new and existing Drilling Control Systems – without going through complex, risky and long-winded integration phases.
AutoConRig is a RCN (Research Council of Norway) funded Joint Industrial Project that addresses this challenge – focusing on 3 main areas. Development of a standard for communicating with the Drilling Machines.Development of an agent framework, allowing for autonomous machine control.Creation and maintenance of drilling-related ontologies.
The AutoConRig project was started in 2008, and will continue until May 2012. AutoConRig is part of the larger project; Integrated Operations in the High North, which targets the implementation of a generation 2 digital infrastructural framework for integrated operations on the Norwegian continental shelf. Important parts of the current work, status and publicly available results from the AutoConRig project so far will be presented in the paper.
Weight Distribution in Reaming While Drilling BHAs
Authors: Meyer-Heye B. , Reckmann H. , Ostermeyer G.-P. 
Published: February 2010

Abstract
Reaming while drilling (RWD) in general means to simultaneously drill a pilot hole and open it up to the target diameter at the same time. This could be done using an eccentric reaming device or an expandable concentric underreamer; both are called reamer in the following. In RWD assemblies the weight applied to the BHA is distributed between the bit and reamer. To ensure optimized performance drilling, it’s necessary to know the distribution of weight as well as the distribution of torque in the BHA. For any calculation of drill string dynamics or tool durability the loads applied to the BHA are an essential input. The effort required to measure all loads while reaming is rather high so there is a need to calculate the weight and torque distribution from as few measurements as possible.
Based on aggressiveness and mechanical specific energy (MSE), an analytical method is shown to calculate the load distribution in RWD BHAs. Therefore a new approach to aggressiveness is introduced for calculation at the bit and reamer. By combination of aggressiveness and MSE, it can be shown how to derive weight and torque distributions in a RWD BHA. Effects of formation changes or different drilling diameters on the rate of penetration (ROP) can be calculated, as well as changes in the load distribution. To prevent the reamer from disruptive weight and torque, depth of cut control (DOCC) technology can be applied at the bit as described by Thomson (2008). How this technology affects the reamer, even if only applied at the bit will be shown as well. Based on data from a field test where weight and torque on bit and on reamer were measured simultaneously the accuracy/validity of the method is shown.
Advanced Modeling Technology: Optimizing Bit-Reamer Interaction Leads to Performance Step-Change in Hole Enlargement While Drilling
Authors: Partin Uyen , Compton Molly , Nelson Gail , Livingston Denise , Davis Patrick 
Published: February 2010

Abstract
The increasing necessity for hole enlargement while drilling (HEWD) technology has resulted in an essential need for engineers to fully understand the interaction between the drill bit and the hole opening tool. Inefficiency and damaging bit and bottom hole assembly (BHA) vibrations, caused by improper bit and reamer selection when drilling through interbedded formations and formation transitions, are a leading cause of inconsistent performance including excessive torque, low rate of penetration (ROP) and downhole tool failures (DTF). To mitigate vibrations, operators required a comprehensive analysis system/process that would allow them to model the complex BHA interaction in a virtual environment and quantitatively compare the performance of various design scenarios.
To solve the challenge, the drilling team utilized a comprehensive, 4-D finite element model that couples laboratory results with a sophisticated computer simulator that calculates the drilling system’s dynamic performance from the bit back to surface in a real-time domain. Unlike other modeling programs that assume the contact forces between the cutter and rock, this advanced model utilizes exact cutting structure details coupled with the laboratory-derived rock mechanics to accurately predict the behavior of the bit and reamer with the entire drill string and bottom hole assembly. The effects of each specific BHA component and variations in drilling parameters on vibrations, ROP, and directional tendency can then be quantitatively evaluated.
Drilling Deep in Deep Water: What It Takes to Drill Past 30,000 ft
Authors: Chatar Crispin , Israel Riaz , Cantrell Andre 
Published: February 2010

Abstract
In 1919 the world record for the deepest well was broken by the Hope natural gas company with a total depth (TD) of 7,579 ft. Although it took over 3 years to reach TD, only 325 days were spent actually drilling. Today in deepwater operations, the water depth alone can exceed this record, and operators have drilled past 30,000 ft in just 4 or 5 months. Technology and procedures have evolved extensively as operations that appeared impossible a decade ago are now considered routine. Today, operators are being pushed more than before, not just to explore deeper prospects, but also to get there efficiently. The future of the industry depends on it. Now there are new questions the industry is asking about deep water: What is different about drilling deep in deepwater operations? What does it actually take to drill the deepest wells in the world today? Currently, there are only a handful of personnel with the knowledge and experience to execute these wells. This paper will discuss the challenges of planning and drilling directional wells in excess of 30,000 ft true vertical depth (TVD) and will also look at lessons from some of the major deepwater Gulf of Mexico (GoM) operations that have successfully drilled wells beyond this mark and are continuing to push the envelope further. These wells have held, at one time or another, records for deepest wells drilled in many categories in recent years.
High Performance and Reliability for MPD Control System Ensured by Extensive Testing
Authors: John-morten Godhavn , Kjetil Arne Knudsen 
Published: February 2010

Abstract
This paper presents the control system, the preparations and some test results for a managed pressure drilling (MPD) operation at the Gullfaks oil field in Norway. The control system was developed with the objective of maintaining the bottom hole pressure (BHP) within a narrow pressure window and it was tested in two experimental set-ups; one test in a horizontal flow loop in Houston and a second test in a vertical test well in Dallas. Water was used as drilling fluid in both these tests. The paper also includes results from the offshore acceptance test in a cased well using oil based mud as drilling fluid. The main objectives of the on- and offshore testing were to qualify the MPD solution as much as possible and to save rig time offshore. The set of normal drilling operations performed in the preparation included connections, rate changes, pressure changes, start and stop of pumps, swab and surge, and drill string rotation changes. New functionality was developed to make a more flexible and robust system to handle contingencies. One is an automatic choke swapping system between two chokes for control if the automatic choke experiences malfunctioning or blocking. A second is a special solution developed to enable trapping of the BHP during unplanned shut downs of the main rig mud pump.
Hardware-In-the-Loop Simulations Used as a Cost Efficient Tool for Developing an Advanced Stick-Slip Prevention System
Authors: Kyllingstad Åge , Nessjøen Pål Jacob 
Published: February 2010

Abstract
Hardware-In-the-Loop (HIL) simulation is a technique where machine control software runs virtual machines, which are mathematical models emulating the physical machines. The technique has become increasingly popular in recent years, because of its ability to shorten product development time for complex dynamic systems, through quick and cost efficient testing over a wide range of conditions.
This paper focuses on the lessons learned from HIL simulation testing of an advanced and patent applied method for curing and preventing stick-slip oscillations in drilling. In this project the HIL simulations have provided several advantages, such as a high repeatability in test conditions, the ability to test under challenging conditions rarely occurring in the field, thus avoiding time consuming field tests. The HIL simulations have also proven to be an efficient tool for debugging the control software, because programming errors are discovered long before the commissioning and field test phases.
The HIL simulation of stick-slip oscillations uses an advanced dynamic model for the entire rotary system, including the top drive electronics, the motors, and the drillstring. The drillstring is modeled as a series of lumped inertia and torsional spring elements where the friction torque for each element is a non-linear function of the wellbore contact force and instant rotation speed. The lowest element also includes the bit torque as a function of weight on bit.
The first version of a stick-slip prevention system, which has been described in an earlier IADC/SPE paper, was HIL tested over a wide range of drillstring and well geometries. Simulations with very long strings (typically 5000 m or longer) revealed that higher mode stick-slip oscillations tend to appear when the normal stick-slip oscillations are cured. The second mode frequency is roughly three times the frequency of the fundamental mode so it falls outside the effective absorption band for the first version prevention software. However, after adding an inertia compensating term in the tuned speed controller, the stick-slip prevention software was able to prevent both the fundamental and the higher modes stick-slip oscillations at the same time. In summary, the HIL simulations improved the stick-slip prevention system so it is more robust, easier to operate and has improved performance. The HIL simulations also helped to find and eliminate code bugs.
Improved Drilling Performance Brings New Life to Colombia's Oldest Oil Field
Authors: Bonilla Pablo , Castillo Lizeth Alejandra 
Published: February 2010

Abstract
Oilfield assets are subject to a daily and perpetual decline, and as existing oil fields mature, recovering the remaining reserves is increasingly difficult. Billon dollar investments have to be made continually to offset the natural depletion and increase the production. The amount invested to overcome the depletion rate and increase the production is challenged by efficiency losses and rising expenses such as those generated by conservative drilling parameters, "train wrecks", hidden flat times and experience of the various service crew's personnel available in today's industry.
This paper will focus on the engineering aspect of wellbore construction that enhances the development of the oldest Colombian oilfield. Significant improvements have been achieved in drilling operations by focusing on the effective application of drilling engineering, lessons learned, Company's best practices, and the adoption of state-of-the-art rig technology, thus reducing the drilling cycle by improving flat-spot operations and drilling operations, allowing the continuity of the development of the La Cira-Infantas mature oil fields in Colombia. Before September 2008 four conventional rigs were being used to drill an average of 14 wells per month. In January 2009, due to the early success of the program, and the need to optimize the CAPEX under the then current market situation only two automated rigs remain in operation, drilling an average of 14 wells per month and reducing the well cost-per-foot in more than 18% while oil production has increased in the order of 42%, and the success of the drilling operations have led to switching from an intensive work over/well services campaign to a more efficient drilling campaign.
An Experimental and Numerical Approach to the Prediction of Collapse Resistance for Expandable Tubulars
Authors: Agata J. , Tsuru E. , Sawamura M. , Asahi H. , Tsugihara H. 
Published: February 2010

AbstractExpandable tubular technology is an effective method for saving on the costs of well drilling and completion. There are many applications for casing repair and slim hole casing design. The most essential aspect of post-expansion expandable tubular (EXP-T) is collapse resistance, which is affected by not only the expanded pipe properties, but also the axial restraint caused by sticking pipe in wells.This paper discusses the effect of expansion condition on the collapse and the prediction methods of the post-expansion collapse resistance by conventional formulas and numerical simulation. The test pipes for EXP-T were expanded at the various expansion ratios with/without axial restraint. Using the post-expansion pipes, full-scale collapse tests were performed. FEA (Finite Element Analysis) for pipe collapse considering the pipe geometries and the mechanical property was also carried out for predicting the collapse pressure of EXP-T after expansion. In addition, the accuracy of conventional formulas and FEM models for collapse prediction was inspected by comparing the collapse test results.These results reveal potential to improve the collapse resistance of the pipe expanded under the axial restraint. Good agreements were found between the collapse test results and the predictions by FEA are drawn.
Automation of Mud-Pump Management: Application to Drilling Operations in the North Sea
Authors: Cayeux Eric , Daireaux Benoît , Dvergsnes Erik Wolden 
Published: February 2010

AbstractDrilling in the North Sea is confronted with an ever more challenging pressure management issue due to narrow geo-pressure windows in depleted reservoirs. Further, the occurrence of pack-offs can cause serious damage to the formation and contribute to non-productive time. To address these problems, automation of mud pump management has been developed over the last four years to minimize the chance of fracturing the formation while starting the mud pumps or circulating. To account for abnormal flow restrictions in the annulus, automatic actions are also an integral part of the mud pump automation described in this paper.Since the downhole conditions are continuously changing (depth, temperature, flow-rate, gel time, cuttings proportion, etc), the necessary safe guards to operate the mud pumps need to be updated constantly. Advanced transient temperature and hydraulic models are used to estimate, in real-time, the downhole situation. Based on the current context, evaluation of maximum pump rates and acceptable flow accelerations are performed and sent to the mud pump control system to be used as an envelope of protection. Furthermore, to assist the Driller during connections, the pump start-up procedure has been semi-automated in order to decrease connection time. Finally, an automatically triggered pump shutdown procedure is also available to minimize the consequences of a pack-off on formation fracturing.A first version of the system has been tested during the drilling of one well in 2008 in the North Sea. Based on the initial experience, a revised version has been used during the drilling of three wells drilled on the Norwegian Continental Shelf in 2009. The feedback from the Drillers involved in the testing has been used to improve the user friendliness of the system. The automation of the mud pump management has been well accepted by the drilling crews. However, the testing has shown that additional instrumentation at the rig site is necessary before such automation can be rolled out safely.
Automation of Drawworks and Topdrive Management to Minimize Swab/Surge and Poor-Downhole-Condition Effects
Authors: Cayeux Eric , Daireaux Benoît , Dvergsnes Erik Wolden 
Published: February 2010

Abstract
Unwary axial and rotational movement of the drill-string can cause formation fracturing or fluid influx resulting in costly remedial actions. With increasingly complex wellbore geometries and narrow geo-pressure windows, it is not always obvious for the Driller to estimate the real manoeuvring limits of the drawworks and the topdrive, especially under poor downhole conditions. The solution presented in this paper uses continuously updated safe guards applied to the drilling control system to maintain a downhole pressure within the acceptable limits of the open hole formations. It also stops automatically the movement of the drill-string in case of abnormal hook loads or surface torques. Since automatic actions can be triggered in case of an unexpected situation, some standard procedures have been fully automated, including friction tests and back-reaming.
Numerical models are used to constantly calculate the maximum accelerations and velocities which can be applied to the drill-string in the current drilling conditions. The resulting envelope of protection is depending on many factors. Therefore, a proper evaluation of the downhole conditions is of paramount importance for the quality of the calculated safe guards. An automatic calibration of the physical models, based on surface measurements, is at the heart of the system. The calibrated mechanical models are used to determine the limits for abnormal surface torques or hook loads. It is therefore possible to automatically take actions in case of overpull, set-down weight or high torque.
In 2008, a preliminary version of the system has been tested during the drilling of a well in the North Sea. Even though the control algorithms did work well at that time, it has been noticed that in some circumstances the drilling control system would not be ready in time for fast changing drilling conditions. An improved version of the drawworks and topdrive automation system has been tested during the drilling of three North Sea wells in the spring of 2009. In this last version, the response time of the system has been optimal at all time. The Drillers involved in the testing of the system have found the system useful and user-friendly.
Drilling Efficiency and Rate of Penetration - Definitions, Influencing Factors, Relationships and Value
Authors: Mensa-Wilmot Graham , Harjadi Yoseph , Langdon Sheldon , Gagneaux Jay 
Published: February 2010

Abstract
Drilling efficiency must be improved, in order to drive down operational costs. This requirement must not be viewed in isolation, considering the vast number of activities that determine a drilling program's success. In most instances, discussions relating to drilling efficiency have centered on rate of penetration (ROP)1,2. As a result, ROP is either equated to drilling efficiency, or seen as the parameter that establishes drilling efficiency. These positions, in addition to being flawed, are highly inconsistent with field results. ROP must not be equated to drilling efficiency. Rather, ROP needs to be seen as one of several parameters that influence drilling efficiency.
The industry's most common performance quantifying metrics - cost per foot (CPF), feet per day (FPD), mechanical specific energy (MSE)3,4, etc - are strongly influenced by ROP. These relationships complicated earlier efforts that sought to establish the appropriate dependencies, between drilling efficiency and ROP. To drive down operational costs, while continuing to push drilling activities into harsher and more challenging environments, emphasis must clearly be placed on drilling efficiency. Thus, in order to achieve this goal, drilling efficiency and ROP must both be defined. In addition, the factors influencing ROP and drilling efficiency must be identified. Most importantly, drilling efficiency's different influencing factors5, which include but are not limited to ROP, must always be analyzed based on specific project objectives.
This paper, in addition to addressing the issues listed above, will also establish a clear distinction between drilling efficiency and ROP. In addition the contributions and impact of both ROP and drilling efficiency, as it relates to value creation will be discussed. The positions, to be presented and argued, will be supported with field and operational data.