bluuebunny/crossref_metadata_2025 huggingface dataset:
Turbodrill BHA Solves Build Section Challenges, Anadarko Basin
Authors: Staley Craig , Bruton Greg , Natanael Mark , Kelley Jason , Milne Ross
Published: March 2011

Drilling the difficult build section in the Granite Wash play in Washita County, Oklahoma can present a number of challenges. The formation contains multiple reservoirs within complex sequences of sandstone, siltstone and shale interbedded with granite/limestone wash. This hard and abrasive matrix is uniquely challenging and unpredictable which makes conventional drilling with positive displacement motors (PDM) combined with rollercone TCIs and/or PDC bits difficult due to the lack of desired durability.

The operator required a new technological solution to minimize the flat time in this particular section by reducing bit trips and/or improving penetration rates (ROP). In normal situations, a turbodrill paired with a diamond impregnated bit is a viable option to tackle this challenge. However, the conventional steerable turbodrill BHA was incapable of achieving the target build rates required by the customer in their deviated section.

The challenges in the build section of the well were evaluated by the engineering team. A review of the run data and use of mathematical-based predictive analysis software identified the changes needed to achieve the required doglegs needed to meet the challenge. The study indicated that using a steerable turbodrill with two bends and a specific stabilization setup coupled with a diamond impregnated bit with a shorter gauge length could yield up to 65% higher build rates.

This new turbodrill BHA has been successfully field trialed in numerous wells in Washita County, Oklahoma and surrounding areas and has achieved the goal of consistently building a curve with a plan of 14°/100ft and has set numerous new field performance records. Drilling time has been consistently reduced by 45% (from 8.0 to 4.3 days) and bit runs reduced from 2.5 to 1.0 while achieving 40% higher ROP. The authors will present case histories that illustrate performance achievements in the build sections and provide details that contributed to the success of this unique BHA.
Development of an Automated System for the Rapid Detection of Drilling Anomalies using Standpipe and Discharge Pressure
Authors: Reitsma Don
Published: March 2011

The requirements for the early detection and the control of kicks, losses and other anomalous conditions while drilling are becoming increasingly important as the industry drills in more challenging environments both onshore and offshore due to greater challenges with respect to equipment stresses and pressure regimes. This paper will present the design and testing of a high fidelity and high certainty system for the early identification of anomalous conditions while drilling such as kicks, losses, washouts, drill string plugging and hole bridging without the need for traditional delta flow equipment and interpretation methods. An explanation of how the system minimizes false alarms and how visual and audible methods inform the operator of the different anomalies as they are detected will be included. Installation of the equipment on the rig will also be presented and compared to current delta flow methods both for managed pressure drilling operations and conventional drilling operations. Maintenance and reliability issues will also be discussed. Full scale testing and tests using collected field data will be presented to demonstrate the system operation. Further development and field testing will also be discussed.
The Successful Evolution of an LWD Rotary Steerable System for Air Drilling
Authors: Hartley Chris , Weisbeck Denis , Robert Scott , Smith Mark
Published: March 2011

This paper will present the evolution of a third-generation, point-the-bit rotary steerable system (RSS) and its successful application for air drilling of directional wells and lateral intervals.

There are a number of applications for air drilling; the primary one is obviously to drill hydrostatically underbalanced where extremely low bottomhole formation pressures are encountered. In certain circumstances, the requirement to have a very small rig footprint makes drilling with air preferable to drilling with mud systems.

The engineering requirements for drilling with air obviously differ from more conventional drilling fluids. Pressure integrity of the mechanical components of the RSS device has to be sufficiently robust to withstand more extreme differential pressures. This paper will describe the steps in the evolution of the RSS design to accommodate this requirement and other functionalities of the system.

Transmission of downhole information drilling with dry air necessitates effective communication of data via electromagnetic (EM) wave in the absence of the medium for conventional mud pulse telemetry (MPT). The timeline over nine years to integrate basic EM with more high-end LWD and steering devices is illustrated (Fig. 1). Optimization of controllable constraints to extend the reach of acceptable EM transmission is addressed.

Results of successful deployments on over twenty bit runs so far will be demonstrated, along with a step-change in tool reliability delivered. Performance improvements were achieved using the surface output of the existing rig fleet without modifications. Lateral reach capability was extended, largely due to improved hole quality over the air motor drilling system used previously. This delivered greater production footage from fewer wellbores as well as the increased ability to reach topographically constrained payzones.
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

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

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

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

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

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

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

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

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

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

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

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.
Delivering Performance in Shale Gas Plays: Innovative Technology Solutions
Authors: Baez Franklin , Barton Steve
Published: March 2011

This paper focuses on technology development for improving drilling performance in natural shale gas plays. These wells involve long horizontal laterals with frequent problems in controlling tool face and maintaining ROP. This results from a number of factors including, high tortuosity through the build section, use of high bend settings on directional motor assemblies, sub-optimal hydraulics, and drill bits with compromised aggressivity.

A combination of technologies can be used to dramatically increase performance in these challenging sections by limiting resistive torque, maximizing bit hydraulics, and improving weight transfer. In each example, a separate engineered solution is introduced. These include;

A novel tool that vibrates the drill string with low frequency, low amplitude axial vibrations to reduce drag and dramatically improve weight transfer to the bit. This tool has been used successfully in hundreds of horizontal wells A specific sealed bearing, motor technology that delivers 100% of the mud flow to the bit. Advantages of full flow include increased bit hydraulics (improved ROP in Shale), and no detriment in response when using tools below the motor that rely on pressure or flow to activate. Run data demonstrates a 37% average increase in ROP compared to conventional sealed bearing motors that rely on flow restrictor bypass leakage for seal performance Development of a unique flexible bit design, specifically for directional applications. These bits contain novel features that allow rapid design modifications to be performed locally, significantly reducing response time, and allowing the drilling program to proceed at a much faster pace than previously possible

Case studies are documented where these solutions have proven extremely successful in gas shale plays. The savings produced by the improvement in drilling performance has greatly assisted the economic viability of continued development in these applications.
Effective BHA Design and Vibration Modeling for Improving the Quality of Sonic Measurements
Authors: Chatar Crispin , Blyth Matthew
Published: March 2011

The first logging while drilling (LWD) sonic tool was developed in 1996. For the oil industry, sonic tools have now become a critical part of the existing suite of LWD tools. They allow the determination of formation velocities while drilling, enabling real-time decision making. Compressional and shear velocities obtained can be used for calculating rock mechanical properties, which can then be used for drilling optimization, ensuring hole stability, or as inputs into mechanical earth models. Compressional velocities are also sensitive to pore pressure and can be used to determine pore pressure trends while drilling. This allows the calculation of a safe mud weight window and the ability to update it in real time. LWD sonic tools also allow the calculation of interval transit time, which can be used to update seismic data while drilling. Acoustic tools, therefore, offer a variety of measurements critical for drilling successful wells, so it is imperative to ensure that the best quality data are delivered at all times.

The detrimental physical effects of shock and vibration on drillstring and bottomhole assembly (BHA) components are well known. However, vibrations have also been known to have adverse effects on downhole LWD tool measurements. Measurements of acoustic signals are sensitive to excessive sources of downhole noise, such as shock, vibrations, and poor drilling practices. It is therefore critical to the quality of the sonic log to minimize vibrations while drilling, to design BHAs that minimize tool movement, and to optimize drilling parameters. The effects of shocks and vibration can be clearly seen by comparing acoustic logs over zones with high downhole shocks to those zones in which shocks were minimized. The primary way to reduce the likelihood of these problems is to design a BHA that is less prone to vibrations and is correctly configured to optimize the acoustic measurement. Today, many companies have a range of software available, from simple vibration to finite element analysis software that can create models required for this type of design.

Background information on acoustic measurement and its uses is presented, along with an overview of some current BHA vibration modeling techniques. We review data from projects with poor quality sonic data due to lack of vibration modeling and from projects in which vibration modeling was done so that the results can be compared and analyzed. We look at what is required at the design phase for planning BHAs to minimize vibrations and to optimize the acoustic measurement. Some examples of what is done today are discussed, and a list of general guidelines for BHA design that should be considered when running acoustic tools is included.
Hydrocarbon Reservoirs Where Proactive Geosteering is Most Likely to Succeed
Authors: Seifert Douglas , Aramco Saudi , Chemali Roland , Bittar Michael , Althoff Gary , Lotfy Amr
Published: March 2011

Proactive geosteering is the fastest-growing form of geosteering. It enables reservoir exits to be anticipated before they occur and well paths to be altered to navigate within the best portion of the reservoir. This paper demonstrates that proactive geosteering when utilizing resistivity tools is most likely to succeed when drilling in a high resistivity reservoir surrounded by low resistivity formations. The likelihood of success is further improved when the different media are separated by sharp boundaries, whereas gradational transitions prove to be challenging.

These observations are substantiated and quantified with models and actual case histories. The key enabling geosteering technology considered in this study is the newly deployed azimuthal deep resistivity family of logging-while-drilling (LWD) sensors. These sensors can detect and locate an approaching boundary from several feet. The geosteering personnel track oil/water contacts and shale/sand interfaces. The earlier these boundaries are identified, the better the chances for successful geosteering. The resistivities of the formations are important because the lateral reach of the sensor is most favorable when navigating in a high resistivity reservoir adjacent to low resistivity formations. Similarly, the least favorable situations occur when navigating in a low resistivity interval and seeking a high resistivity formation. Series of modeling results help to quantify and visualize the expected geosteering performance for various resistivity values in the reservoir and approaching formations.

The paper includes case studies from actual geosteered wells to illustrate the performance predicted by the theoretical models. It also provides guidelines for planning and interpreting a proactive geosteering operation.
Understanding and Managing Bottom Hole Circulating Temperature Behavior in Horizontal HT Wells - A Case Study Based on Haynesville Horizontal Wells
Authors: Trichel Keith , Fabian John
Published: March 2011

While HT wells have always presented drilling challenges, the recent activity increase in the Haynesville shale located across the border between Texas and Louisiana presents a unique and extreme environment for drilling equipment. Not only is there a high frequency of temperature related MWD/LWD failures, the profile and architecture of Haynesville wells has provided an opportunity to study and better understand the thermal behavior of horizontal HT wells in general. Through improved understanding, well specific operational guidelines and planning considerations can be implemented to ultimately reduce the risk of downhole temperature related failures.

This paper discusses a Haynesville horizontal well case study where temperature simulations were compared and calibrated to actual downhole temperature measurements taken while drilling. After calibration of the model was established, a series of simulations were conducted to investigate the sensitivity of bottom hole circulating temperature to choices of drilling systems, fluids systems, mud cooling systems and well design.

The simulation results indicate:

The bottom hole circulating temperature profiles of HT horizontal wells are significantly different than those of vertical wells and can even exceed the bottom hole static temperature. The simple every day choices made with regards to the drilling program including fluids selection, hole size, bottom hole assembly type, bit hydraulics, and flowrate all influence bottom hole circulating temperature and can either increase it or decrease it. Optimization in the traditional sense (focused on ROP) does not apply and can result in even higher bottom hole circulating temperatures. The correct procedures are often counter intuitive.

This paper will detail the above mentioned effects on bottom hole circulating temperature and will present optimization guidelines and planning considerations for managing circulating temperatures. At the time of this writing, the implementation of these guidelines and procedures discussed in this paper is just beginning. The overall trends for MWD/LWD performance for the Haynesville, while improving over time still indicate significant room for improvement in planning and operating practices (Appendix - Figure A1). Guidelines and planning considerations, and operating practices for horizontal Haynesville wells are presented along with the reasoning behind them.
How to Accelerate Drilling Learning Curves
Authors: van Oort Eric , Griffith James , Schneider Barry
Published: March 2011

Given the current economic climate and continued volatility in oil and natural gas prices, extracting maximum benefit from drilling performance optimization is key to the economical exploitation of many resource plays around the world. Shell Upstream Americas is employing a highly effective performance improvement team to help drive performance optimization and the delivery of top quartile performance on its wells in North America and beyond. Central to this group is a dedicated team of optimization engineers that deliver drilling efficiency optimization techniques, the innovative use of real-time optimization centers, and value-adding root-cause failure investigations to various land and offshore well delivery teams in a fit-for-purpose way. Using the optimization approaches taken, it has been possible to help accelerate well delivery times and associated learning curves by as much as a factor of three, often in a minimum amount of time. A main conclusion is therefore that this approach is a highly effective way to bring performance optimization focus to field operations.

This paper highlights the modus operandi of these optimization engineers, the techniques and tools they employ, and the remarkable results achieved. The workflow and organizational structure was applied to well delivery optimization with projects ranging from shale gas drilling in the Continental US and Canada as well as hard rock drilling in the Middle East.
Testing the Combination of High Frequency Surface and Downhole Drilling Mechanics and Dynamics Data under a Variety of Drilling Conditions
Authors: Lesso Bill , Ignova Maja , Zeineddine Firas , Burks James , Welch Brent
Published: March 2011

Understanding the behavior of the drill bit, bottomhole assembly (BHA), and drillstring in drilling operations is difficult without accurate measurements of tensile load, torque, pressure, and various vibrations both at surface and downhole. A variety of methods have been employed to compress measurements obtained downhole in order to transmit them to the surface with measurement-while-drilling (MWD) mud-pulse telemetry. During the last ten years, some success has been achieved in making these measurements, recording them, and then retrieving the data at surface upon the end of the bit run. Meanwhile, the comparable measurements at surface have limitations in terms of accuracy, calibration, and dampening.

An instrumented surface sub (ISS) has been developed that replaces the saver sub at the bottom of the top drive on a rig's traveling assembly. It measures in real time at the top of the drillstring, using accurate and calibrated sensors, tension/compression, torque, rotational speed in revolutions per minute (RPM), and surface pump pressure, among other parameters. These measurements, made at 400 Hz, are not dampened by the drill line and sheaves. A drilling mechanics module (DMM) sub that is part of the BHA has also been developed, which provides downhole measurements including, but not limited to, tension, torque, RPM, internal and annular pressure, at frequencies between 200 and 2,000 Hz. Additionally, along-string vibration measurements are provided using memory only devices.

To evaluate both of these downhole and surface drilling data acquisition tools, a test was conducted in June 2010 at the Schlumberger directional drilling test facility near Cameron, Texas. Four different BHAs were run to evaluate downhole behavior and collect data using milled-tooth and PDC bits while directional drilling in surface rotary mode as well as with steerable motors. This paper presents some of the wide-range findings regarding the use and analysis of the data gathered in terms of static drilling mechanics, as well as dynamic drillstring behaviors and downhole vibrations.
Cutting Carbonates — New Technology Delivers Step Changes in Bit Performance
Authors: Weeden R. W. , Williams S. , Lugo F. , Gaduan P.
Published: March 2011

Carbonate formations are renowned for their propensity to quickly turn a great interval into a set of costly challenges. These formations can quickly damage the cutting structure of drill bits which can result in a short/slow run. Consequently, bit aggressivity is often sacrificed for longevity to guarantee a minimal amount of trips to complete the section.

Historically, these formations were drilled with rolling cutter technology. However, after decades of development, rolling cutter bit designs could not provide the versatility and efficiency required by operators. Subsequently, fixed cutter technology was trialed through PDC and diamond impregnated drill bits. While providing abundant leaps in drilling efficiency, PDC suffered from diamond table loss which resulted in multiple trips. Conversely, diamond impregnated technology was able to provide improvements in longevity and reduce trips, but these improvements were offset by reduced drilling efficiency.

The reliability and durability of diamond impregnated bits has offered the industry a good option to reduce the number of trips required to drill a carbonate interval when tripping costs outweigh the operational costs of low penetration rates. While there are still improvements to be made with this technology, the next step change in performance will come from a bit which has the longevity of diamond impregnated bits and the efficiency of PDC bits.

This manuscript details a project aimed at delivering the next generation of drill bit technology for carbonate formations. In this project, key performance challenges associated with carbonate intervals were identified and concepts developed to overcome these challenges. After evaluation of these concepts, products were developed for field testing. Following a series of tests, the advantage of these concepts became apparent when performance illustrated abundant increases in efficiency while maintaining the longevity of diamond impregnated technology.
Natural Gas as a Fuel in Drilling Operations-Analysis, Testing and Implementation
Authors: Hill David G. , Johnson Jeff , Bell John , Mayer Nathan , Giberson Hugh , Hessler Ryan , Matthews Will
Published: March 2011

Utilizing natural gas as fuel to power large engines is not a new technology; however the application of dedicated natural gas powered engines to power drilling rigs can be considered a new approach to environmentally and socially responsible operations in the oil and gas industry.

The use of dedicated natural gas engines on drilling rigs provides the opportunity to capture the following advantages:

reduced emissions reduced cost improved maintenance characteristics, and improved for domestic energy security.

Barriers to adoption of this technology application for drilling operations included low cost of diesel, certainty around diesel handling and performance, uncertainty on natural gas engine performance under variable load conditions, impact of variations in gas composition on engine performance and operational challenges related to bringing natural gas to the rig in remote operations.

This paper describes the process used to evaluate, test, implement and measure the application of dedicated natural gas drilling systems in the Jonah Tight Sands drilling operations in Wyoming and in the Haynesville Shale Gas operations in northern Louisiana. Key learnings from deployment of natural gas engines in the field will be shared.

As part of the technology application process, dedicated and dual fuel engines were tested and different forms of natural gas fuel sources were utilized based on maturity of the field, proximity to natural gas infrastructure and natural gas quality. This included utilization of lease/field gas, treated gas (tailgate of gas plant) and liquefied natural gas. The evaluation process included the following: engine performance, engine emissions, natural gas quality, cost differential when compared to dieselburning engines, planned maintenance costs versus diesel and life cycle analysis. Evaluation results will be summarized along with economic analysis.

A decision tree model was developed to assist in evaluating when to consider natural gas as a fuel in drilling operations and what adaptations to the application would be required to respond to various forms of natural gas available for use. The model will be applied to an emerging natural gas field in Europe or Asia.