bluuebunny/crossref_metadata_2025_split huggingface dataset:
Planning and Implementation of the Repsol-YPF-MAXUS Krisna Underbalanced Drilling Project
Authors: Park D. , Brand P. R. , Allyson B. , Sodersano G. 
Published: December 2007

Abstract
Due to the previous history of high mud losses and stuck pipe, Repsol – YPF - MAXUS Southeast Sumatra B. V. decided to implement underbalanced drilling technology in the development drilling campaign in the Krisna Field offshore Indonesia. Although Underbalanced drilling is not a new technology, it has been used infrequently in drilling from an offshore structure.
Underbalanced drilling from a jack-up rig causes some unique planning and implementation issues. Planning and implementation are made more complex by the space limitations and logistics. These were compounded by the lack of infrastructure in Indonesia for underbalanced applications.
The Krisna D12 production interval was successfully drilled underbalanced from 10 June 2000 through 20 June 2000 from the Reading and Bates Falcon jack-up Roger W. Mowell. A total of 1159 feet of formation was drilled Underbalanced without any significant drilling related problems.
Although the project encountered problems during the initial start up, modifications to the system and changing the fluid system to a diesel mist eliminated the majority of the issues. By the end of the well, the Underbalanced system was working well.
This paper presents the pre-engineering, project management and field implementation results for the drilling of the Krisna D12.
Reservoir Characterization Whilst Underbalanced Drilling
Authors: Kneissl Wendy 
Published: December 2007

Abstract
Underbalanced drilling (UBD) is rapidly gaining popularity in the industry because of the advantages gained both in terms of the drilling process itself (for example higher rate-of-penetration and reduction of lost circulation), and for enhanced long-term productivity (associated with reduced formation damage). Production associated with the drawdown maintained throughout UBD furthermore offers the opportunity for formation evaluation in real time.
This paper presents a method for simultaneously deriving formation pressure and permeability profiles in real time during UBD, using an approach that does not require any extra operational hardware than is already typically used. This method is known as testing while underbalanced drilling (TWUBD).
The analysis uses pressure transients in the wellbore at bottomhole to perform a novel form of local multirate well test during drilling, leading to the derivation of the spatial profiles of reservoir characteristics.
The method has to date been tested with good success using UBD data from approximately 20 wells.
Extending BHA Life with Multi-Axis Vibration Measurements
Authors: Ashley D. K. , McNary X. M. , Tomlinson J. C. 
Published: December 2007

Abstract
Extending motor, bit, MWD, and BHA component life is of primary importance to the drilling process. Frequently downhole vibrations can cause anywhere from minor to catastrophic failure in any of the components of a typical BHA.
Some types of vibrations are more detrimental to various components of the BHA. Most vibrations can be controlled with the alteration of surface parameters such as weight-on-bit and rotary speed in conjunction with downhole measurement tools such as downhole weight-on-bit and downhole torque as well as BHA alteration. The problem has always been knowing which parameters to alter without adversely affecting total drilling performance.
Recent advances in MWD technology have provided a means of measuring downhole vibration in multiple axes. This information, provided in real-time, allows the driller to control the proper parameters to minimize specific vibration effects thereby maximizing BHA life and total drilling performance.
Subsea Equipment for Deep Water Drilling Using Dual Gradient Mud System
Authors: Forrest Neil , Bailey Tom , Hannegan Don 
Published: December 2007

Abstract
Deepwater drilling presents both opportunity and challenge. One challenge that consistently presents itself is the difference in pressure, at the mudline, between the hydrostatic head of the mud in the riser and the formation pressure close to the mudline, which is, typically, defined by the seawater head. This pressure differential causes an operational difficulty that may, in some cases, prevent drilling the well to its target depth using conventional riser return drilling methods. The concept of Dual Gradient drilling, using a riser filled with seawater, has been proposed as a viable method of limiting this pressure imbalance and of facilitating the drilling of challenging deepwater wells. Over the years, especially in the ‘60’ s and ‘70’ s by major Oil companies, many different approaches to dual gradient drilling have been studied, but none have been commercially developed. During the past three years, three independent large-scale efforts have been initiated in attempts to provide a commercial dual gradient system to the industry. (Ref. 1). Several of these efforts include configurations that utilize a seawater filled risers.
One of the major requirements of dual gradient drilling, using a seawater filled riser, is the need to create an interface between the drilling mud in the wellbore/wellhead and the seawater, or other fluid, in the riser. This can be simply a fluid/fluid interface, located generally above the wellhead in the riser, or a mechanical device to provide positive isolation of the two fluids.
This paper will review the general concept of dual gradient drilling, while focusing on the development of a mechanical isolation method combined with a subsea pumping system for return of the drilling mud. In addition to reviewing the mechanical aspects of the hardware, operational methods and added value that the mechanical isolation system brings to deepwater drilling methods, will be discussed.
The Commissioning and Sea Trials of the Deepwater DP Drill Ship Glomar C.R.Luigs
Authors: Chiu Hin 
Published: December 2007

Abstract
The Glomar C.R.Luigs, Global Marine's new deepwater dynamically positioned (DP) drill ship, has been commissioned, sea trialed, and deployed with a pace unprecedented in comparison with previous efforts. The project achieved record setting results in both operational and technical areas. Operationally speaking, client acceptance of the vessel was accomplished 32 days after Global Marine took delivery of the vessel at the Harland & Wolff shipyard in Belfast, Northern Ireland. Excluding the 20 days of transit time to cross the Atlantic, the vessel began to earn day rate and was ready to commence drilling only 12 days upon her arrival in the Gulf of Mexico. Technically, the sea trials demonstrated astonishing performance in dynamic positioning, setting new records on maximum heading turn rate (52 degrees per minute) and precision station keeping capability (one meter radius watch circle). This paper presents the key elements for the planning phase and execution phase of the project, leading to the successful operation of commissioning and sea trials. These include the operation philosophy and guidelines, scope and duration of works, team organization, preparation of the commissioning procedures, agenda of the sea trials, client's acceptance tests, and interfaces with the client, the classification society, the equipment vendors, and the ship builder.
The contents of this paper will be of interest to project management, commissioning manager and engineers, and fabricators involved in the planning and execution of commissioning and sea trials of offshore drilling and production vessels.
Drilling with Rotary Steerable System Reduces Wellbore Tortuosity
Authors: Weijermans P. , Ruszka J. , Jamshidian H. , Matheson M. 
Published: December 2007

Abstract
Wellbore tortuosity can be defined as any unwanted deviation from the planned well trajectory. As wells become more complex, oil companies increasingly perceive wellbore tortuosity as a concern in the process of drilling, completing and producing wells. Tortuosity is a potential source of additional torque/drag and can lead to problems while running casing, liners and completions. In specific applications, excessive tortuosity in horizontal wells can even impair productivity.
Due to the conceptual difference in steering principle between conventional directional drilling systems, utilizing steerable bent housing motor technology, and rotary steerable systems, it has been claimed that rotary steerable systems produce a less tortuous wellbore. This effect has so far not been quantified, mainly due to the absence of a sufficient body of comparative data. In this paper, results of a tortuosity analysis of a number of North Sea wells drilled with rotary steerable systems, and offset wells drilled with steerable motors systems is presented. Various mathematical definitions of wellbore tortuosity and their implications are also discussed.
The analysis shows that drilling with rotary steerable systems significantly reduces tortuosity. In tangent sections drilled with the rotary steerable system, superior inclination hold performance was observed and in areas of the wellbore where deviation changes were planned, more continuous curve sections were drilled.
In order to illustrate potential benefits this may have with respect to drilling conditions, results from the evaluation were used to carry out torque/drag simulations. Levels of tortuosity produced by steerable motor systems and rotary steerable systems were calculated from the well data studied. These values were superimposed on a generic well profile. It was found that the torque reducing effect of the lower tortuosity delivered by the rotary steerable system is quantifiable and in some cases significant.
Field Application of a Fully Rotating Point-the-bit Rotary Steerable System
Authors: Schaaf Stuart , Pafitis Demos 
Published: December 2007

Abstract
Rotary steerable systems are passing through their infancy stage and becoming an increasingly integral part of the drilling plans of many operators. Improvements in drilling efficiency and the subsequent economic benefits have driven the development of the technology and new methods of rotary steering have now been proven in full-scale tests. One of the key new developments is the creation of "point-the-bit" systems. In this paper, we describe the first of these systems to have all elements of the bottom-hole assembly rotating. This presents a significant advantage in terms of prevention of cuttings accumulation around the BHA, reduced likelihood of becoming stuck and the ability to back-ream. We present a number of case studies that indicate the reliability and broad functionality of the system.
Field Validation of Transient Swab/Surge Response with PWD Data
Authors: Samuel G. Robello , Sunthankar Ashwin , McColpin Glen , Bern Peter , Flynn Tim 
Published: December 2007

Abstract
This paper describes the results of field validation of the transient swab, surge model with PWD (Pressure while drilling) data. The maximum pressures encountered during tripping- or reciprocation are indispensable for making appropriate well completion decisions. The prediction of swab and surge pressures are of critical importance in wells where the pressure must be maintained within narrow limits of pore and fracture pressures. It also plays a major role in running casing, particularly with narrow annular clearances. For these critical cases, a fully dynamic model is required to better estimate the maximum pressures encountered.
This paper presents actual surge and swab field data during tripping and circulating operations collected using PWD tools. These data were obtained from Alaska and North Sea wells with a range of hole diameters and with different base fluid muds. The data were compared and interpreted with a dynamic surge model, which includes the effects of fluid inertia and compressibility, wellbore elasticity, axial elasticity of the pipe, and temperature dependent fluid properties.
The sampling rate was specifically increased to two seconds and in some cases one second. This is done to prevent downhole data attenuations and to capture the full waveforms more accurately. Different operations were included in the PWD runs to cover swabbing, surging, reciprocation and simultaneous pumping operations during tripping. Model predictions of downhole pressure behaviour were in excellent agreement with the measured PWD data.
Measurement of Mud Motor Rotation Rates using Drilling Dynamics
Authors: Macpherson J. D. , Jogi P. N. , Vos B. E. 
Published: December 2007

Abstract
The measurement of mud motor rotation rates, and the transmission of these measurements to surface while drilling, is important for drilling optimization. In general, mud motor rotation rates are estimated from the manufacturers performance data. However, flow rates, torque, weight-on-bit and differential pressure will all vary while drilling as will the efficiency of the motor, affecting the actual rotation rate of the motor. While torque, weight and pressure can all be measured by MWD tools, the direct measurement of motor speed has proven difficult. In general it has been necessary to instrument and hardwire a motor to the MWD system in order to extract a measurement of motor speed. Such modifications result in dedicated and specialized MWD hardware.
This paper describes a means of measuring the rotation rate of a mud motor using a device that is independent of the mud motor. In essence, the dynamic signal created by the rotor is detected by vibration sensors in an MWD measurement sub in the BHA, and converted directly to motor speed. The MWD measurement sub may be remote from (i.e., not directly connected to) the motor, and therefore this system will work with any motor developed using the Moineau principle. Development and testing of the system in the laboratory and in the field are described in the paper.
The Value of Rotary Closed - Loop Drilling Technology on Chevron Alba's North Sea Horizontal Field Development
Authors: Johnstone John A. , Stevenson Philippa 
Published: December 2007

Abstract
This paper describes how innovative Rotary Closed – Loop Steerable (RCLS) drilling technology was introduced to the Chevron Alba field in an effort to optimize horizontal well placement and extend the production life of the field. The application of the RCLS technology has been more successful than initially anticipated, with significant well cost reductions being realised. Moreover, it has allowed access to targets that could not be reached using conventional technology, thereby increasing ultimate recovery from the Alba field.
Initial field development utilized conventional steerable drilling technology, i.e. motor assemblies and rotary drilling assemblies with adjustable stabilizers. Due to geological uncertainties, directional well plans routinely featured pilot holes with an option for one or more geological sidetracks. However, the well designs were constrained by the limitations of the conventional technology. Specifically, the limited ability to steer in the unconsolidated reservoir sands set limits on the dogleg capability and therefore lowered target TVD objectives. Drilling efficiency was compromised too; non-aggressive tri - cone bits were used in preference to PDC bits to facilitate directional control and consequently this limited BHA run length.
In the late 90's a reassessment of the seismic data for the Alba field established new target areas for which it would be necessary to drill more esoteric well designs. This paper outlines the rotary drilling strategy adopted by the Alba project team to accomplish that objective. A review is made of the drilling risks on Alba in the 12 ¼" and 8 ½" hole sections from the conventional drilling perspective, and how these risks became more manageable through improvements in drilling performance with RCLS. In conclusion, an assessment of the technical and financial impact that RCLS technology made on drilling operations on the Alba platform is presented.
Integration of Drilling and Geological Data to Understand Wellbore Instability
Authors: Beacom L. E. , Nicholson H. , Corfield R. I. 
Published: December 2007

Abstract
Throughout the initial phase of development on the Mungo field in the Central North Sea, wellbore instability and mud losses have caused serious drilling problems and additional expense. Geomechanical modeling around the salt diapir led to refinement of some drilling procedures but the direct cause of the drilling problems still remained poorly understood.
A detailed fault mapping study has been carried out from the Paleocene reservoir interval through the overburden. Wellbore instability and mud loss zones displayed along the wellbores were integrated with the 3D fault model and demonstrated that the wellbore instability and mud loss incidents coincide with the location of seismically resolved faults. However, not all faults in the overburden or reservoir were associated with drilling problems. It was found that the intersection angle between the wellbore and the fault surface is critical to determine whether drilling through the fault will induce instability. The Mungo data indicates that small intersection angles (commonly between 0–45°) resulted in drilling problems while larger intersection angles (commonly between 45–90°) were not associated with drilling problems.
These results have been incorporated into the current well planning and drilling strategy for Mungo development wells. So far, a sidetrack well and chalk oil appraisal well has been successfully drilled in the overburden. Potential problem zones predicted in advance were mitigated for in the well planning stage and contingencies included in the drilling budget. The overburden drilling risks are understood by visualizing the integrated geology and drilling data in 3D, so it now takes less time, and therefore less cost to drill successfully to the reservoir target. The techniques are also being applied successfully for well planning and drilling on other fields.
First Simultaneous Application of Rotary Steerable/Ream-While-Drill on Ursa Horizontal Well
Authors: Eaton L. F. , McDonald Scott , Rodriguez Edgar M. 
Published: December 2007

Abstract
The development wells at the Ursa tension leg platform (TLP) site use 8.625" production casing in conjunction with 5.5" tubing to achieve the highest daily production rates to date in the Gulf of Mexico. The desire for large diameter production casing and the small margin between mud weight and fracture gradient at the deepwater Ursa site combine to require drilling a larger sized hole than the drift diameter of the previous casing string for all of the casing intervals. Bi-center bits have successfully drilled all of the intervals in one run except the section to total depth (TD). The last 1,000’ true vertical depth (TVD) on the first two wells were drilled and then under reamed prior to running casing.
The directional plan for the third well at the Ursa TLP included an 86° turn in azimuth and building hole angle to horizontal by 18,300’ TVD. The previous lack of success drilling the TD interval in one trip with bi-center bits led to using a 9.5" bit below a 6.75" AutoTrak rotary steerable closed loop system (RCLS) in combination with an 11.4" ream-while-drill (RWD) sub. This bottom hole assembly (BHA) would simultaneously drill and ream the hole to the proper diameter, thus eliminating the separate under-reamer run.
During the initial pilot hole penetration of the target reservoir and two subsequent sidetracks to build to horizontal, the RCLS / RWD system drilled approximately 20,000’ of Miocene age sand and shale sediments at inclinations that ranged from 30° to 88°. The instantaneous and average rate of penetration (ROP) increased 30% and 85% respectively over that achieved in the TD interval on the previous wells drilled with steerable mud motors and bi-center bits. The directional target of the well was intersected at the desired inclination and azimuth. Caliper logs obtained while evaluating the pilot hole showed the shales had been opened to the gauge diameter of
11.4" while the sands were opened to a slightly smaller diameter. Subsequent laboratory tests showed that the slightly smaller hole diameter in the sands was most likely due to filter cake build-up and/or barite sag.
This paper will discuss the planning, results, problems, and lessons learned during the first simultaneous use of rotary steerable and RWD technology while drilling a build to horizontal section to 18,300’ TVD on the Ursa A-6 well.
West Africa Deepwater Wells Benefit from Low-Temperature Cements
Authors: Piot Bernard , Ferri Alain , Mananga Simon-Pierre , Kalabare Collins , Viela David 
Published: December 2007

Abstract
More and more drilling occurs in frontier areas and particularly in deep water. In this environment, where the water depth often ranges between 1000 and 3000 m, the temperature at the seabed is extremely low, reaching –1°C (30°F) or less in certain parts of the world. In addition, a nonlinear temperature gradient in this water column and the sea currents further participate in and accelerate the cooling of the fluids in the wells. These low temperatures considerably slow cement hydration, which adversely affects the compressive strength development of the cement slurries.
The young, soft formations encountered in the first few thousand meters below the seafloor preclude the use of normal-density cement slurries. However, conventional low-density cements take a long time to set and develop significant strength at these very low temperatures. The daily rate of the rigs able to drill these deepwater wells is fairly high. In addition, the latest generation of offshore deepwater rigs is designed to work faster and deliver wells drilled more efficiently. It is therefore important to have lightweight cement systems that set quickly and develop high strength in the short period of time compatible with the operation of these new rigs.
Often, the permeable layers below the seabed contain either free gas, when the water depth (and pressure) is reasonable, or gas hydrates at greater water depth. The lightweight cement system used in deepwater wells must therefore also control gas during its setting process at these low prevailing temperatures.
Several case histories are presented from West Africa, where lightweight cements capable of setting quickly and managing gas flow in low temperatures have been required to economically drill, case and abandon formations with low fracture gradient in deepwater wells. These systems are compared to more conventional solutions that have been either applied or attempted for cementing the shallow casing strings in wells drilled in water depths ranging from 800 m to 1900 m (~ 2620 to 6230 ft). Applications for water depths to 2800 m (~ 9190 ft) are also considered.