bluuebunny/crossref_metadata_2025_split huggingface dataset:
Liner Drilling Technology as a Mitigation to Wellbore Ballooning - A Successful Case Study in the Gulf of Mexico Shelf
Authors: Rosenberg Steven M. , Gala Deepak M. 
Published: March 2011

Abstract
Conventional drilling techniques proved problematic when employed in a well in the Gulf of Mexico shelf, causing the well to exhibit severe lost circulation (~25 barrels per hour) and wellbore ballooning in the interval at 10,700 ft MD. After a detailed review of the situation liner drilling technology was identified as the most appropriate technique for reaching the well objective and setting the liner at planned depth without losing hole size because of the following advantages that this technology provides: Documented lost circulation problems have been minimized or eliminated through prior use of liner drilling technology, largely attributed to the "smear effect" phenomenon.The liner system selected provided for high torsional capability as well as requiring both a mechanical and pressure event to release the setting tool, minimizing chances for premature release.The 7-in liner drilling system can help to minimize or even eliminate non-productive time in case of induced fluid losses while drilling hazards are experienced in the well.This technology has a proven track record as an effective solution to lost circulation in the Gulf of Mexico shelf.
Ultimately, the correct application of liner drilling technology on this well allowed the operator to reach the intended drilling depth and completion objective and to set the 7-in liner in place. This despite the fact that a drillable casing bit with displaceable PDC cutting structure, which was used to drill the 8-1/2 in hole section, could not be displaced as planned.
In this paper the authors will review the benefits of liner drilling technology successfully to drill the operator's 7-inch liner in place and describe in detail the equipment selection. They will go on to provide a detailed description of the liner drilling process which resulted in the wells objective being realized despite the fluid loss and wellbore ballooning that was experienced and discuss the reasons for the failure of the PDC displacement sequence.
Deepwater DP Drilling Rigs on Shallow Water Wells, Can it Work?
Authors: Kadiyala Raj , Whooley Alan 
Published: March 2011

Abstract
The steady influx of new build rigs into the Gulf of Mexico has flooded the market with 10,000ft plus rated rigs, forcing smaller rigs to forage elsewhere. This influx is clearly driven by the industry's move to deeper and deeper waters. The effect of these changing priorities has led to a shortfall in rigs specifically tailored to shallow-medium water depths.
In some cases cost and schedule constraints and rig availability have prompted contractors and operators to consider deepwater DP rigs on shallower water wells. Paramount to the success of this practice is safe rig operation, management of unplanned DP system failure (i.e. drift-off) and maximizing drilling operability.
Operability is primarily dependent on the prevailing environment, water depth and riser tension. While new rigs offer many advantages in terms of high tension capacity and better station keeping, this can be outweighed by heavier subsea hardware (e.g. LMRP, BOP), larger vessel excursions in extreme environments and poorly optimized tensioner and anti-recoil performance at lower tensions.
This paper discusses the challenges associated with operating deepwater rigs on shallow water wells; looking specifically at tension optimization, operating envelopes and drift off events. A comparison study is presented between the drift off and operability scenarios of a new generation deepwater rig and an older generation rig suited for shallower waters. Sensitivity studies are also presented to environmental directionality and magnitude and the effect on the structural and mechanical limits of the riser and tensioning system.
Integrated Downhole Isolation Valve and Managed Pressure Drilling To Facilitate Development of Sour Fractured-Limestone Gas Reservoir in East Java, Indonesia
Authors: Darmawan Ganesha Rinku , Buntu Sangka Nathaniel , Djoko Susilo Surjanto , Nas Steve , Julmar Shaun S. Toralde , Eka Prasetia Andi , Sisworo Sisworo 
Published: March 2011

Abstract
Drilling operations for the development of a sour gas reservoir (up to 7,000 ppm H2S and 20-25% CO2) in the Kujung fractured-limestone formation in East Java, Indonesia are prone to kick-loss cycles. Well control incidents have been experienced on two previous wells drilled in the area. Most of the drilling budget was spent on cement and lost circulation materials to mitigate circulation losses and the resulting kicks. The skin factors of the said wells are therefore understandably high.
In planning subsequent wells, underbalanced drilling was ruled out due to the sour nature of the reservoir, and managed pressure drilling (MPD), which involves drilling at near-balanced pressure, was selected. To further ensure the minimization if not elimination of the release of sour reservoir fluids at surface, MPD methods were integrated with the utilization of a downhole isolation valve (DIV). The implementation of the DIV + MPD system in recent drilling operations has allowed drilling operations to reach the target depth. The operation gradually shifted from conventional to MPD methods, based on the level of circulation losses encountered, thereby minimizing the amount of reservoir fluid released at surface and keeping skin factors low while penetrating deeper into the fracture limestone reservoir. The absolute open flow potential (AOFP) for the newly drilled well is considerably higher than offset wells. The DIV was able to keep sour reservoir fluids from reaching surface during MPD operations, undergoing as much as 47 open/close cycles during drilling, tripping, fishing and well test operations, all of which were performed while experiencing total loss of circulation.
The details of the DIV + MPD system utilized will be presented in this paper, together with an assessment of how these results impact the development of sour fractured-limestone gas reservoirs in the area.
New Technologies to Enhance Performance of Section Milling Operations that Reduces Rig Time for P&A Campaign in Norway
Authors: Scanlon Eamonn , Garfield Garry , Brobak Siri 
Published: March 2011

Abstract
In 2008, ConocoPhillips completed the plug and abandonment (P&A) of two of eight water injection wells at the 2/4 W Platform in the Norwegian sector of the North Sea. The average performance was 65 days per well. One of the most challenging aspects of the 2008 P&A campaign was deep section milling of the casing to install the secondary reservoir barrier where multiple section mill runs were necessary. In mid-2009 ConocoPhillips resumed operations to P&A the remaining 6 wells. The scope to P&A the remaining 6 wells was increased to include a second barrier across the Miocene which called for more section milling than the first campaign. ConocoPhillips management challenged the rig team to significantly improve performance on the second campaign. Performance on the final six wells improved dramatically to an average of 46 days.
P&A requirements called for section milling 165 feet of 9 7/8″ casing at depths ranging from 8,585 ft to 10,896 ft. A joint ConocoPhillips and Baker Hughes team was formed to seek a method to significantly reduce the time required to mill the casing for the second campaign. The team set an aggressive goal of milling the section in one run. In addition a plan would be needed for additional section milling to achieve the second Miocene plug as well as potential for 13-3/8″ milling to achieve adequate isolation.
Two new technologies were implemented to improve the performance of section milling operations during the P&A campaign. A new cutter technology that had shown significant impact resistance and longer life than previous cutter technology was installed on the section mill blades which demonstrated increased resistance to wear and improved chip breaking ability. In addition, a new downhole optimization sub was included in the BHA that gathered information at the section mill and sent the data back to surface in real-time for on-site evaluation by engineers.
These two technologies significantly reduced rig time due to the longer lasting cutters as well as the real-time data transmitted back to surface from the downhole optimization sub. The information from the optimization sub was evaluated onshore during the entire P&A campaign and operational improvements were made as each successive well was completed.
A New Player Entry to the Deepwater Market
Authors: Ouwerkerk Tim 
Published: March 2011

Abstract
This paper will give an introduction to the motivation and perspectives behind the decision of a Jack-up operator entering the deep water market. The paper will illustrate how the company intends to position itself amongst competitors and how we have equipped its rigs in order to achieve this. It will further more go into detail about what philosophy is followed.
In order to communicate this, the presentation will introduce the equipment installed on the new built semi-submersibles and the safety and efficiency targeted with this equipment. A conclusion of the presentation would include recommendations on how to proceed in the future. This will include vendor ‘treatment’ for future projects as well as expansion in this market in general. The presenter will elaborate on what measures should be taken ahead of an investment in light of moving into ‘unknown’ areas and how the lessons learned system has helped and still can be improved.
In parts the paper will make reference and give updates to the paper 128700 presented in Feb/2010 with the topic of multi machine control (MMC) on the new series of deep water rigs
ECD Management and Pore Pressure Determination with MPD Improves Efficiency in GOM Well
Authors: Fredericks P. D. , Smith L. , Moreau K. J. 
Published: March 2011

Abstract
In early 2010 Stone Energy Corporation restarted development of the Amberjack field in the Gulf of Mexico in which the last two sidetrack wells were drilled eight to ten years ago under difficult circumstances that included depletion, reduced fracture gradient, wellbore instability, and high, unmanageable ECD. With no way to reduce the ECD and maintain a constant BHP in the small margin between fracture gradient and pore pressure it was next to impossible to prevent annular loading and packoff, stuck pipe, gas influx, and heavy losses.
Determined to avoid that trouble in their Amberjack redevelopment campaign, Stone employed automated MPD technology in their first slot recovery well, the A-12 ST1 Ibix well. In the 1800 feet of 8 ½" hole that was drilled with MPD, Stone was able to manage the BHP in windows ranging from ± 0.16 ppg while drilling, ± 0.12 ppg while tripping, and ± 0.05 ppg while rolling over the mud from 14.8 to 15.0 ppg.
Given the uncertainty surrounding the pore pressure in their target sand, it was particularly useful for Stone to be able to use the MPD system to confirm the pore pressure at a critical point in the well. After drilling the designated "P-sand", Stone used the MPD system to stage down the BHP in a controlled manner and watch for early signs of influx. Starting at 15.0 ppg the BHP EMW was staged down to 14.65 ppg at which point the system detected a small amount influx indicating the BHP was at or below the "P-sand" pore pressure. Total influx volume was limited to 2.5 bbl and shut-in-casing-pressure was limited to 150psi.
Using MPD Stone was able to avoid the trouble encountered in the four offset wells which cost the previous operator of the field one lost sidetrack and a month of total non-productive time. Over the course of the first two recovery wells, Stone managed constant BHP during 26 connections, mud roll-over operations, and trips in and out of the wells.
Controlling the BHP and ECD with automated MPD allowed Stone Energy to reach their planned targets in significantly less time than previously possible and avoid the wellbore instability and well control events that occurred frequently in previously drilled offset wells.
Mist Drilling in Low-Pressured, Highly Fractured Carbonates Improves Well Test Results and Fracture Identification from Image Logs
Authors: Mohd Nor Norlizah , Balzarini Maria , Siddiqui Mustafa 
Published: March 2011

Abstract
Underbalanced drilling (UBD) is an effective technique used to prevent severe fluid losses typically encountered when drilling through vuggy and fractured carbonates. This paper discusses the successful application of UBD to improve drilling performance and data acquisition quality in an ultra heavy oil carbonate resource located in Alberta, Canada. Logistical challenges associated with mobilizing UBD equipment to a remote location during extreme winter conditions are also presented.
A series of appraisal drilling campaigns were conducted over a four year period in the ultra heavy oil-bearing Grosmont carbonates to acquire subsurface data in support of field development planning. Prior to 2010, the primary drilling fluid used was water-based polymer mud and, when heavy losses were encountered, polymer-based lost-circulation material. The formation damage caused by drilling with these materials hampered hydrology testing and masked image log responses resulting in an inaccurate view of the reservoir architecture and an inappropriate development concept. During the winter 2010 drilling campaign, a change was made from overbalanced to underbalanced drilling using mist in the bitumen-saturated carbonates. The main objective of mist drilling was to reduce near-wellbore damage and improve interpretability of hydrology test data.
The application of mist drilling was proven to be operationally feasible despite the challenges posed by severe winter weather conditions during drilling, which are exacerbated by the poor infrastructure surrounding the remote Grosmont well locations. Excellent quality image logs and much improved hydrology test data were obtained in the mist-drilled wells compared to appraisal wells drilled overbalanced in past campaigns. Skin factors were reduced by a factor of 100 and fractures became more discernible on image logs. Consequently, understanding of permeability architecture in this heavily fractured carbonate reservoir was greatly enhanced.
The successful experience with mist drilling in these fractured carbonates paves the way for better fracture identification and reservoir characterization for the resource. The data acquired from the UBD wells have impacted key decisions related to technology testing and future development planning for the Grosmont lease.
Automated Real-time Drilling Hydraulics Monitoring
Authors: Zoellner P. , Thonhauser G. , Lueftenegger M. , Spoerker H. F. 
Published: March 2011

Abstract
One essential element of real-time drilling monitoring is wellbore hydraulics reflected by fluid flow and pressure response. Issues related to pipe wash-outs, cuttings accumulations and well control create a significant source of drilling related problems and consequent lost time.
In addition to lost time incidents, the optimum processes to clean and condition the hole in relation to hydraulics are a significant potential in avoiding hidden lost time.
This paper outlines a concept and several case studies to monitor drilling hydraulics by analysing fluid flow in relation to pump pressure and other relevant sensor channels. Objective of this work is to early recognize the on-set of hydraulics related problems to take preventive action.
The concept is based on recognizing variations in expected behaviour of rig sensor responses using hybrid algorithms, which link analytic, statistic and knowledge based concepts.
With a large number of data at a high degree of operational detail, generated using automated operations recognition, it is possible to identify patterns, which allow the early detection of a number of problems, such as pipe washouts, circulation losses, as well as stuck pipe.
The analysis of routine drilling operations, like pump start-up, allow the optimization of the drilling process to avoid hidden lost time. The interpretation of the related patterns allows optimizing pump start-up procedures and shows trends in changing wellbore behaviour over time.
The concept is implemented by a hydraulics monitoring screen fed by the results of the automated analysis, which outlines the ideal operating window to enable the drilling personnel to act on the information generated.
A Cost-Effective Alternative Method of Deploying Perforating Devices in High-Angle Wells
Authors: Hord Ryan , Scott Thad , Weeks Fred , Budde Marcel 
Published: March 2011

Abstract
In wells with high angles and horizontal well geometry, wireline-conveyed perforating devices have limits on their ability to be deployed into the wellbore after the final casing string has been set. In such cases, perforating devices have to be conveyed either on tubular such as coil tubing/jointed tubing/drillpipe or pulled into the well with a tractor to reach the target depths. This procedure, in turn, requires that either the drilling rig be retained or that it be replaced with a workover unit in order to perforate the well.
A new method has been devised which involves the use of a simple cement wiper plug system with a high pressure/high temperature (HPHT) rupture disc located in the top plug. This method can be used to install and cement the casing and to provide a means of deploying wireline perforating equipment. Once the cement is pumped into the well, it is displaced by means of a calculated amount of retarded mix water, which is designed to be pumped behind the top plug. When the top plug is bumped and latched into the float shoe, the casing may be tested and the rupture disc burst, enabling the fluid to clear the float shoe and a predetermined area of wellbore near the shoe. Subsequently, the rig can be released and a fluid pumping unit, together with a wireline perforating unit, mobilized to the well site to complete the well. At this time, formation fractures are initiated into the area near the shoe, enabling the wireline perforating device to be pumped into the wellbore. Perforating takes place and the perforating device is retrieved via wireline so that the fracturing unit procedure can be initiated immediately.
In this paper the authors will discuss the problems associated with perforating high-angle wells and review, in detail, an alternative way of deploying perforating guns, considerably reducing overall expenses as proven in over 400 such operations.
Extension of Gauge Length to Reduce Vibrations and Improve Drilling Performance
Authors: Smyth Gregory F. , Evans Andrew M. , Babb Jonathan , Bolivar Neil 
Published: March 2011

Abstract
During extended reach drilling operations at the Hibernia Platform, operated by Hibernia Management and Development Company Ltd. utilizing ExxonMobil Canada Ltd. resources, bit gauge length and profile have been systematically varied to improve drilling performance while using a standard bottomhole assembly (BHA) and bit design. Prior to developing the standard BHA design and implementing a global performance management process, the ExxonMobil Fast Drill Process, multiple bit runs were required to drill a typical high angle, 10,000-ft interval of 12¼-in. hole. Tool failure and bit damage caused by vibration resulted in multiple bit runs. In order to reduce vibrations and improve drilling performance, bit gauge length has been systematically increased in 1-in. increments while utilizing a standard BHA. Partially tapered gauge was used in conjunction with the increased gauge length to allow directional control.
This paper presents the results of progressing from a 4-in. non-tapered gauge bit to a 5-, 6-, and 7-in. partially tapered gauge bit from 2005 to 2009. Mechanical specific energy (MSE), vibration, rotary steerable wear, and directional response data is presented to show the impact of the incremental changes in gauge length over a group of seven wells. The tapered profile and increased gauge length provided comparable directional response with significantly improved drilling performance, resulting in multiple field record rates of penetration (ROPs) and bit run lengths.
Hibernia Well Overcomes Challenges to Further Extend Worldwide Extended Reach Drilling (ERD) Envelope
Authors: Woodfine Miriam , Bolivar Neil , Trend Sarah , Ottesen Steinar 
Published: March 2011

Abstract
In 2007, Hibernia Management and Development Company Ltd. (HMDC) began drilling operations on B-16 57 (OPA2). The plan involved drilling and completing an oil producer to 32,000-ft measured depth (MD) and to a total vertical depth (TVD) and horizontal departure that would put the well outside the worldwide ERD envelope. The well was temporarily plugged and abandoned at ~20,000 ft in the 12¼-in. hole section as a result of a combination of factors including complex geology and wellbore instability.
The planning of the redrill began almost immediately and involved the collaborative efforts of the local drill team, the local geoscience team, industry experts from ExxonMobil, and the other HMDC co-venturers and service providers. The final trajectory was a result of HMDC co-venturer collaboration and balanced risk associated with encountering unstable zones and complex lithology. Successfully drilling this well would require an engineered approach to operations as well as incorporating an ultra thin fluid system in the 8½-in. hole section.
The successful execution of the redrill was a result of enhanced cooperation between the operations, engineering, and geoscience teams. The application of proven HMDC and ExxonMobil practices for hole cleaning, rate of penetration (ROP) management, and wellbore stability were critical success factors. The increased focus on downhole mechanics and surface limitations through the ExxonMobil Fast Drill Process and the flat time reduction initiative allowed OPA2 to be completed successfully at a depth of 33,209-ft MD, further extending the worldwide ERD envelope. Application of the drill team's standard bit and bottomhole assembly (BHA) design allowed shock and vibration and mechanical specific energy (MSE) to be minimized, resulting in field record rates of penetration (ROPs). Most notably, the 8½-in. hole section was drilled in one shoe-to-shoe bit run in 5.7 days. The nearest offset, completed in 2003 in the same geologic fault block, required eight bit runs and 57.6 days from drill out to TD.