bluuebunny/crossref_metadata_2025 huggingface dataset:
A Systematic Approach to Performance Drilling in Hard Rock Environments
Authors: Dykstra Mark , Schneider Barry , Mota Jose
Published: March 2011

The Haynesville shale gas play in North Louisiana poses a number of significant technical challenges. One of the most daunting is penetrating the hard, abrasive Hosston sandstone-shale sequence and hard Knowles limestone in the intermediate section of the overburden. The high strength and interbedded nature of these formations trigger bit and drillstring vibration that can lead to short, slow bit runs and unacceptably high cost per foot.

The operator applied a systematic Drilling Efficiency Optimization (DEO) approach encompassing well planning, well execution and post-well analysis to drive performance improvement through these formations. Optimization efforts focused on polycrystalline diamond compact (PDC) bit design, bit hydraulics, positive displacement motor (PDM) selection, soft torque rotary system (STRS) utilization, bottom hole assembly (BHA) design and active management of drilling parameters. Combined, these efforts reduced cost per foot and days per thousand feet by over 50% while drilling approximately 70 wells over a two year period.
Drilling Performance Improvement in the Haynesville Shale Play
Authors: Billa Rich , Mota Jose , Schneider Barry , Weissman Mike
Published: March 2011

Significant drilling performance improvement was achieved over a two year period in the HPHT Haynesville Shale Play in North Louisiana. Technical challenges include drilling through abrasive, high compressive strength formations, bottom hole temperatures exceeding 360°F, sour gas and shut-in surface pressures near 10,000 psi. The wells are horizontal with 12,500 to 14,500 ft TVD, and 16,500 to 18,500 ft MD. The application and optimization of managed pressure drilling (MPD), underbalanced drilling (UBD), hard rock drilling, casing drilling, casing design and installation procedures will be discussed.
Can Safety Improvement Increase Drilling Efficiency?
Authors: Pavel David , Boutalbi Said , Grayson Brian
Published: March 2011

The number one operational safety risk during the drilling and completion of a well is the risk of a kick becoming uncontrollable and the danger that can place on people, assets and environment. Another risk is the potential misdiagnosis of a kick and the ability to quickly and efficiently identify downhole anomalies. Is it a kick, or is the wellbore breathing when making a connection? Are we experiencing losses, or is the wellbore ballooning when the mud pumps are turned back on after a connection is made? If a wrong decision is made based on a misdiagnosed situation, the results can range from costing millions of dollars in nonproductive time to loss of life and rig.

There are numerous key technology elements in the industry today that can greatly mitigate these risks and create a substantially safer drilling and completion operation and environment. These elements are field-proven over 40 plus years, are readily available from many vendors and are relatively economical. Surprisingly, these elements are not used on the most critical, risk-laden and expensive wells being drilled globally. These risk-mitigating elements include such systems as rotating control devices, flow-metering technologies, automated drilling choke systems, and downhole isolation valves.

Individually these elements add incremental benefits and increase the overall safety of the drilling and completion operations. When these systems are paired or used in combination with each other to create a closed and pressurizable mud-returns system, the benefits escalate exponentially when compared to cost or perceived inconveniences of these elements.

Furthermore, when the closed-loop system is designed as such – a system – as opposed to being piecemealed together, the operational benefits of the system are maximized.

This paper describes how a few of these basic elements greatly enhance operational safety and efficiency. A closed mud-returns system will allow us to identify kicks and losses quickly and accurately, thereby minimizing risk, without sacrificing other operational elements.
Integrated Drilling Optimization and Downhole Drilling Dynamics Enables PDC Bits to Drill in the Colorado Region of the San Juan Unconventional Gas Basin
Authors: Pink Tony , Harrell Lisa , Perez Danny , Carrico John , Mackinnon Paul
Published: March 2011

The San Juan basin is a prolific natural gas play in northwestern New Mexico and southwestern Colorado. For more than four years, all attempts to find a poly crystalline diamond compact (PDC) solution for the northern part of the basin have been unsuccessful or uneconomic; in addition, the performance of insert bits had also reached a plateau of roughly 60 ft/hr. In order to achieve the next step change in drilling performance, it was decided that a drilling optimization process that was integrated with high speed downhole drilling dynamics was required. The optimization process required the cooperation of the client, the directional drilling company, and the optimization company. The team was challenged to find a fixed cutter solution that could drill from surface to total depth (TD) in one run and at over 100 ft/hr; these challenges thus became the project's two primary objectives.

This paper discusses how an optimization process was integrated with high speed, multiple placement, downhole drilling dynamics analysis in order to discover what was limiting the performance of fixed cutter bits. The process involved four phases - analysis, planning, execution, and evaluation - utilizing a four well project. The lessons learned from each well were then applied to the next well in the sequence. From the lessons learned, small changes were made to the drilling assembly after each well in the sequence. These changes were then analyzed on the subsequent well. On each section, the downhole drilling dynamics data was merged with surface data.

The analysis of this data demonstrated that the main limiters to drilling performance were poor weight transfer and vibration. On the fourth well in the sequence, a specially designed, six bladed fixed cutter PDC bit drilled the entire 2,858ft of the 7 7/8" section, in one run. The overall rate of penetration (ROP) including connection time, was 102 ft/hr, surpassing the goal of 100 ft/hr.
The First Successful Short-Radius Re-Entry Well in Deep Gas Drilling in Saudi Arabia
Authors: Al-Khamees Shaker , Okwa Hope , Verma Jaywant , Ganda Sukesh
Published: March 2011

This paper discusses the planning and execution of the first successful short-radius sidetrack in deep gas drilling in Saudi Arabia. ANDR-XYZ was sidetracked from vertical at 12,242 ft and built inclination to 90° with maximum dog leg severity recorded as 39°/100 ft. Thereafter, a 2,400 ft lateral was drilled in the Khuff-B reservoir. Total depth was revised because of deteriorating reservoir quality. The operating time was 53 days versus 60 days planned. The short-radius sidetrack was one of three options (option 3, below): Sidetracking in the 9 5/8-in. casing set in the Khuff formation. Apart from cost reasons, this option was discarded because of high Jilh pressure requiring the mud weight to be increased from 102 pcf to 152 pcf, which would create well control and directional drilling difficulties.Milling the 7-in. liner, drilling a new 8 3/8-in. hole, setting a new 7-in. liner, and then drilling a 5 7/8-in. hole across the reservoir. Apart from being time consuming and costly, this option did not reduce technical complexity since it might have exposed the 9 5/8-in. casing across the liner lap. The condition of this section could not be guaranteed because of a previous milling operation while drilling the original wellbore.Re-entering the well by sidetracking in the 7-in. liner below the 9 5/8-in. casing. This required drilling a short-radius curve in the 5 7/8-in. section and continuing drilling and geosteering the well through the reservoir. Such a high buildup rate had never been successfully achieved before at this sidetrack depth in the Khuff reservoirs in Saudi Arabia.

Several technical considerations were taken into account including the depth and type of whipstock, the length of rathole, design and analysis of the sidetrack bottomhole assembly (BHA) including torque and drag analysis, as well as overall operations strategy to achieve the well objectives. Several challenges were overcome and lessons were learned, which will be detailed in this paper.

The successful delivery of this well resulted in saving of 45 rig days compared to the other options. The well also extended the frontier of drilling and workover options and opened up avenues to reenter several wells in deep gas drilling in Saudi Arabia.
Operator's Recommendation for a Uniform Dull Grading System for Fixed Cutter Hole Enlargement Tools
Authors: Ulvedal L. , Enterline J. D. , Scott D. , Radford S. , Clinkscales J. , Shale L. , Croxton M.
Published: March 2011

An IADC standard system was defined and implemented in 1987 with revisions in 1992 to standardize and permit the accurate dull grading of fixed cutter bits. Now as hole enlargement is one of the fastest growing sectors of today's drilling industry, there is a greater need for an accurate and uniform dull grading system for fixed cutter hole enlargement tools. Through collaboration between an operator and a bit manufacturer, this new dull grading protocol is being proposed to better characterize hole enlargement tool dull conditions. The method will be described in this paper and will encompass concentric, eccentric, and expandable tools. It will define common elements of hole enlargement tool cutting structures and the dull grades relating to this BHA component as they differ from drill bits. Adoption of this new dull grading system for fixed cutter hole enlargement tools will facilitate an industry-wide standard to more accurately communicate dull conditions. This will enable operators, drilling contractors, and bit manufacturers to improve the tool's design, selection, and operating parameters for future applications.
Underreamer Dynamics
Authors: Meyer-Heye B. , Reckmann H. , Ostermeyer G.-P.
Published: March 2011

In a hole-opening application, cutting forces are applied to the drillstring simultaneously at the bit and the underreamer. Cutting forces at the reamer are known widely in the industry to cause additional vibrations of the drillstring that could harm the bottomhole assembly (BHA). This causes unnecessary downtime at the rigsite and increases costs. Expandable underreamers have very limited design envelopes for the optimization of their cutter layout. Most have only three blades and high-profile angles. Common polycrystalline diamond compact (PDC) bits have five or more blades and generate most of the cutting forces at their inner cutters. Reamers, due to their resulting forces, have significantly different characteristics compared to bits. By using appropriate bit-dynamics simulation software it is possible to explain the reasons for these different bit and reamer characteristics. An in-depth study of the cutting forces enables a better understanding of the mechanics of vibration excitation, especially for underreamers.

Dynamic cutting force models for bits and reamers have been developed based on the results of cutting force analyses. These models contain weight, torque, and residual side force. They were implemented into a highly sophisticated drillstring model using finite-element analysis. Dynamics simulations in time domain of complete drillstrings resulting from the cutting forces at the bit and reamer are shown. Interactions of the pilot bit and reamer coupled by the BHA are also investigated using this model.

A field test was conducted using a hydraulically expandable underreamer. During this test, simultaneous dynamics measurements where taken at the bit and reamer in vertical and directional well sections. The measurements validate the simulation results.
Increased Rate of Penetration Through Automation
Authors: Dunlop J. , Isangulov R. , Aldred W. D. , Sanchez H. Arismendi , Flores J. L. , Herdoiza J. Alarcon , Belaskie J. , Luppens J. C.
Published: March 2011

Drilling lags behind other industries in the implementation of automation. One reason for this is the variability of drilling operations and uncertainty in knowing what is being drilled at any given time. A closed-loop system that continually monitors drilling parameters and drilling performance in real time and constantly adjusts weight on bit (WOB) and rotary speed (RPM) maximizes instantaneous rate of penetration (ROP). The system has been tested in more than 15 drilling operations around the world in both advise and control modes. Field tests show an improvement in ROP typically greater than 10% versus nonautomated operations. Maximum benefit is realized when automation is implemented by means of a closed-loop system, whereby the set points for WOB and RPM are directly fed to the controls of the drilling rig. The algorithm, the closed-loop system, and the performance improvement delivered by this system are currently subject to certain operational constraints, but these will be addressed by future enhancements.
Remotely Operated Top-Drive Casing-Running System Combined with New Cement Head Enables Major Oil Company to Improve Zonal Isolation and Cement Bonding with Enhanced Safety and Efficiency in Caspian Sea
Authors: Cummins Tracy , Abrahamsen Egill , Killoh Ian
Published: March 2011

Using conventional methods for landing and cementing casing strings in a surface wellhead for a major operator in the Caspian Sea resulted in zonal communication, mud and cement losses, and poor cement bonding.

Historically, rig up and rig down of conventional casing-running and cementing equipment required extensive manual handling and man-riding operations to be carried out on the critical path, with times of one hour being common. During this time circulation was not possible, leaving thixotropic well fluids static and turning them to a gelled state before cementing operations had begun. This gelling lead to channeling of fluids, mud/cement losses and poor cement placement.

To address these problems, a remotely operated top-drive casing-running tool in combination with a new, remotely operated cement head were deployed. Configured with upper and lower casing-handling joints, the new cement head enabled the top-drive casing-running system to quickly pick up the cement head and make it up into the landing string as a casing joint without manual handling. The cement head was preloaded with remotely launched top and bottom cement plugs and preinstalled plug valve with a cement hose, eliminating the need for man-riding operations.

Circulation through the top drive began immediately after makeup, keeping the casing and well fluids in motion to eliminate gelling. Cement was then pumped through the side port of the cement head, and the casing string was reciprocated throughout the entire operation with increased flow area past the casing hanger, allowing higher displacement flow rates, reducing formation pressures and improving cement placement. The casing string was held in tension during cement displacement.

This combination of new technologies has been successfully implemented to run several 9.625-in. and 13.375-in. casing strings in the previously problematic pseudo-ERD and conventional wells, resulting in: Decreased transition time (static pipe) between casing-running and cementing operationsReduced manual handling of equipment and elimination of man-riding operationsExcellent zonal isolation based on cement bond logsMinimized (in some cases eliminated) mud/cement losses during entire cement jobExcellent cement sealsSuccessful pressure tests
Rebuilding a Tool Joint: Best Practices to Avoid Failure
Authors: Pettit Grant , Gokhale Samit
Published: March 2011

Weld repair of tool joints ("rebuilding") has been practiced due to the manufacturing schedule and cost of new drill pipe. In rebuilding, a soft metal is welded to the tool joint surface to increase the outside diameter (OD) to meet Premium Class dimensional requirements. While expedient, welding on the outer surface of tool joints should be approached with caution, since the welding process re-heat treats the steel in an undesirable fashion, increasing the likelihood of an unexpected failure.

This paper presents the results from two failure analyses in different geographic regions. In one instance, an operator in the Middle East experienced a twistoff failure at the base of the 18° box taper. In the second case, an operator in Colorado had a washout at the same location. This second downhole failure prompted a Magnetic Particle Inspection (MPI) of the remainder of the string, which resulted in the rejection of several additional joints due to cracks in the same area, the base of the 18° box taper.

Analysis revealed that all of the problem tool joints had been rebuilt. In each case, soft metal was welded on the box OD surfaces, machined to a smooth finish, and placed back into service. The altered material properties of the tool joints made them susceptible to brittle cracking and fatigue failure.

This paper provides the lessons learned from these failure analyses, including field data and the metallurgical results. For those instances when tool joint rebuilding is performed, proper weld quality control procedures are outlined to reduce the risk of failures.
First Application of Heat-Activated, Rigid Rapid-Fluid System in Deepwater Environment in Mexico Helps to Cure Severe Loss of Circulation: A Case History
Authors: Castro Jorge , Solis Luis , Urdaneta Javier , Arreola Victor
Published: March 2011

Loss of circulation during the drilling stage in wellbore construction is a common issue, especially in a wildcat well. However, exploration is required to increase the reserves, and it frequently has to be performed in areas of difficult access and in deeper-water wells.

Loss of circulation can significantly increase the operation cost, delay the drilling program, and can involve risks for the stages or even the well. It usually consumes more resources, such as mud, rig time, logistics, and modifications in the survey, etc. The outcome can be an ineffective use of time during well construction.

A version of this paper was presented at PECOM 2009 in Mexico during the transformation through innovation providing an in-depth view of the current Mexican critical-technology issues. This manuscript focuses on how a severe loss of circulation was treated using a heat-activated, rigid rapid-fluid treatment, restoring full circulation and successfully increasing the window gradient in the first attempt in a deepwater wildcat well in the northern Gulf of Mexico. An engineered solution was proposed for the placement and calculations. It was verified through laboratory tests and in the field. In addition, this paper discusses the results of the application and how it was applied in the next drill stage based on a drill, tack-and-squeeze methodology. This method has become an alternative solution for the operator in this kind of well.
Collapse Prediction Methodology for the Solid Expandable Tubular
Authors: Agata J. , Tsuru E. , Sawamura M. , Asahi H. , Tsugihara H.
Published: March 2011

This paper summarizes an experimental and numerical study aimed at understanding the collapse resistance of expandable tubulars (EXP-T), both before and after expansion, and at constructing a prediction method for post-expanded collapse.

Post-expanded collapse resistance is one of the important properties for EXP-T, and the high-collapse EXP-T is necessary for the realization of expandable tubular monobore wells. Thus, a reliable prediction technique can be useful for casing-design utilizing EXP-T. However, the current collapse formulas widely used are not applicable to post-expanded pipes.

To solve this subject, firstly, full-scale expansion and collapse tests were performed to compare collapse resistance between two materials. Secondly, two prediction methods were validated for post-expanded collapse: finite element analyses (FEA) and the statistic formula used in conventional OCTG.

The test results demonstrated that post-expanded collapse resistance is significantly degraded by the increase in the diameter-to-thickness ratio. There was a large difference in the reduction ratio of the collapse between the conventional and trial material, and the FEA model is capable of evaluating the precise collapse strength of post-expanded pipes by modeling the collapse governing factors. It was also clear that the distribution of residual stress after expansion is opposite to conventional OCTG, although the residual stress deteriorates the collapse resistance after expansion. Moreover, by modifying the definition of the mechanical property of the pipe, the collapse prediction formula is capable of accurately calculating the collapse pressure after expansion. This result is caused by the difference in the shape of stress-strain (S-S) curves between conventional OCTG and post-expanded pipes.

We expect that this research work will contribute to improving our understanding of EXP-T collapse, and will help form the technical basis for the reliability of EXP-T casing design.
Remote Communication Techniques From Surface to Downhole Tools
Authors: Joseph P. , Mendez L. E. , Dolyniuk D.
Published: March 2011

In this age of multizone and multilateral wells, existing technologies are always challenged to achieve desired results. During the drilling and completion phases of a well, surface communication to downhole tools is essential to either orient or activate these tools. As these wells get deeper, extended reach and complex, traditional methods of communication are challenged and stretched to the limit.

This paper will present new remote communication techniques from the surface to the downhole tools. Primary focus while developing this technique was toward downhole completion tools like packers, anchors, and flow- control devices. Two methods of communication will be discussed. The first method described will be communication to the tool using flow-induced signal patterns. The second method will be using signal patterns generated by an acoustic source at the surface. Both methods generate vibration and pressure signals that are received by transducers housed in the downhole tool. These acquired signals are then processed to determine if they match a pattern that is stored in the tool. If it does, then the command is given to activate the tool.

To test these techniques, a new tool was developed and results showed that these methods are viable means of remote communication. It is anticipated that these new techniques will enhance the ease and reliability of setting these tools without adding significant cost.
Conventionally Undrillable Open Fractured Reservoir, Drilled Using Managed Pressure Drilling Technology
Authors: Hamoudi I. , Kartobi K. , Qutob H. , Arnone M. , Torres F. , Barakat N.
Published: March 2011

The Field was discovered in 1960 during the exploration phase, this field is located between the Hassi Messaoud field and Rhourd de Nouss Central Field in the Triassic Basin in Algeria. The field represents many challenges for conventional drilling due to the complexity of the geological structures, one of these is the Hamra Quartzites formation; a gas reservoir sandstone highly tectonically fractured. The drilling history of this formation shows events of total fluid losses leading to gas kicks due to the loss of hydrostatic head in the annulus.

A 6" hole section in NZ-XX well was planned to be drilled under the Constant Bottom Hole Pressure (CBHP) technique, throughout the Gres de Ouargla and the Hamra Quartzites formations; bounding the drilling window by the estimated formation pressure as lower limit, and the fluid losses pressure (hydrostatic pressure of mud used in offset wells) for the upper limit, both estimations were done at the top of the reservoir. The drilling window for Managed Pressure Drilling-MPD was validated by determining the Bottom Hole Pressure where both, an influx from the formation and fluid losses occurred. These values were later used to establish the target Equivalent Circulating Density-ECD to drill the hole accordingly.

The ECD management was achieved by controlling both, the surface back pressure and the annular out-flow; monitored in real time. The Bottom Hole Circulating Pressure-BHCP changes recorded in a Pressure While Drilling-PWD tool, placed in the Bottom Hole Assembly-BHA.

As the drilling progressed, fluid losses were experienced and instantaneously controlled by reducing the ECD. Despite the lower and upper MPD window limits converged, drilling continued managing losses as no open operating range existed. As a contingency for this scenario, switching to the Flow Drilling technique (UBD) was proposed and planned, but due to environmental restrictions, flowing the well while drilling was not possible. The MPD operations in NZ-XX successfully achieved 191 meters of open hole; then TD was called due to a combination of increasing losses – gas influx conditions and increasing risk of total losses in the underlying Hamra faulted structure.

This paper describes in detail the successful MPD application which is considered a start he drilling technology to enhance Nezla field exploitation. Lessons learned and challenges encountered will also be discussed in this paper.
Results of July 15, 2010 IADC Stick-Slip Mitigation Workshop
Authors: Womer K. A. , Torkay D. R. , Villanueva G. , Geehan T. , Brakel J. , Pirovolou D. , Reid D. , Killalea M.
Published: March 2011

This paper presents the results from a workshop on stick-slip mitigation held in Houston on July 15, 2010. This workshop, sponsored by the IADC ART Future Technology Subcommittee, brought technology leaders and engineers together to discuss issues related to Stick-Slip mitigation. Led by specialists with operating and technology companies, its goal was to educate the industry regarding existing technologies available to address this issue as well as identify the need for possible future technologies. In addition to presenting technical results, the paper describes the unique structure of the workshop: (1) opening, non-commercial presentations wherein the science of stick slip and the business case for its mitigation were reviewed; (2) a series of short presentations by various providers with technologies to identify or mitigate stick-slip; (3) a round table discussion, involving both the presenters and the audience, to assess the effectiveness of these technologies and assess areas where further technology, education, or process improvement is needed. This was all condensed into an afternoon so as to accommodate the demanding schedules of the participants and audience. This workshop is the first of a series of planned workshops to address technology needs which were identified in an industry survey conducted by the IADC Advanced Rig Technology committee last year and reported in SPE 128953.
Real Time Pore Pressure Prediction Using LWD And Borehole Seismic Data Assists In Mitigating Risk On An Appraisal Well Offshore Malaysia
Authors: Ahmed Aqil , Anis Leo , Fey Scott , Hussain Riasat , Rahim Helmi , Tan Boon Hua , Mohaideen Azlan
Published: March 2011

A successful methodology was employed in drilling an appraisal well offshore Malaysia where pressure ramps were expected from the pre-drill geomechanical study. To drill to TD safely, casing point selection and mud weight management were critical during the drilling phase, Both Type 1 and Type 2 overpressure mechanisms were expected to be encountered. (Type 1 is related to undercompaction and Type 2 related to fluid expansion)

Pore pressure prediction has become a vital tool to assist drilling in challenging environments. Traditional LWD measurements like resistivity and sonic are employed but with the advent of seismic while drilling, an extra acoustic measurement is introduced to increase the confidence in pore pressure prediction workflow in real time. Combined with velocity trends extracted from the surface seismic and wireline seismic gives increased confidence in the velocity to pore pressure transforms.

The main challenge was to manage the mud weight in the 8.5 inch hole section where a second pressure ramp was expected but the uncertainties were higher both for the magnitude and depth at which it would occur. The drilling interval for this section was 1968m to 2800m TVDSS. Mud weights were expected to go as high as 16.5 ppg.

The 12.25 inch section was optimized for casing point selection by the use of real time seismic checkshots for accurate time depth conversion.

In the 8.5 inch section two interventions were made.

Using the pore pressure prediction - mud weight was increased above Formation 11 (shale) to avoid a predicted ramp in real time. The intervention was made early enough so that the mud could be weighted up in time.

The second intervention was for TD (Pressure criteria was preset). The Real Time Pore Pressure Prediction indicated pressure at TD would exceed the BOP limit so TD was called earlier at 2680m TVDSS instead of 2800m TVDSS

Pressure predictions were confirmed by a subsequent wireline formation tester run.

By employing the real time pore pressure prediction workflow Petronas were able to safely and successfully drill to TD on a challenging well.
Exploration of the Interaction Between Drill Bit Gauge Profile and Point-The-Bit Rotary Steerable Systems
Authors: Lines L. A. , Larronde M. L. , Stroud D. R.
Published: March 2011

This paper describes an investigation of bit passive gauge profiles for a latest generation point-the-bit Rotary Steerable System (RSS) shown in Figure 1. Using theoretical analyses, a methodology has been developed for exploiting lateral stability afforded by extended passive gauge, without limiting steerability or creating stick-slip or high torque. Results of laboratory testing and field studies are presented, showing a step-change improvement in drilling performance and efficiency.

Full scale laboratory testing and field studies explore the impact of extended passive gauge in maintaining lateral stability. Results show that typically much longer passive gauge length than is common can be applied without adversely affecting steerability or stick-slip. These practical results are fully explained by theoretical analyses that predict critical gauge lengths. The optimum gauge profile is shown to be dependent on hole size and formation type.

For some time; short gauge drill bits have been the fashion, dominating the industry. More recently the importance of extended passive gauge to lateral bit stability has been recognised, but concerns over steerability and torque generation has limited adoption. These misconceptions are likely a consequence of early point-the-bit RSS testing in which incremental increases in gauge length unwittingly produced assemblies close to the critical length/diameter ratio for ‘cock and lock’. Until now, solutions applied have either reduced gauge length or tapered the gauge at the steering system tilt angle -solving the problem at the expense of much of the lateral stability, leaving the drilling assembly vulnerable to undesirable dynamic conditions.
Advanced Reservoir Navigation System and Drilling Technology Maximizes Productivity and Drilling Performance in the Granite Wash - US Midcontinent
Authors: Janwadkar S. , Thomas M. , Privott S. , Tehan R. , Carlson L. , Spear W. , Setiadarma A.
Published: March 2011

The Granite Wash unconventional gas and oil play of US Midcontinent has a multi-trillion cubic feet equivalent upside potential. The condensates and natural gas liquids associated with this gas play make it one of the most prolific and fastest growing unconventional fields in North America. However, efficient extraction of hydrocarbons from the Granite Wash play poses drilling and geological challenges. The Granite Wash deposit has significant lateral variation; in some locations the thickness of the sandstones bodies associated with gas shows are approx 1 to 3 feet thick, and the formations are extremely abrasive. Geological complexity of this field requires precise placement and navigation of the wellbore in real-time to overcome the variable characteristics of the reservoir. To overcome these challenges, logging while drilling (LWD) technology was used in conjunction with geo-steering. The azimuthal gamma ray image was used to determine formation bed dip and stratigraphic complexity within the reservoir. The multiple propagation resistivity measurements were used to correlate position within the reservoir and indicate formation porosity. The LWD data was transmitted in real-time via satellite to a remote reservoir navigation center where the reservoir navigation engineer incorporated the real-time data into the geological model. This strategy has been implemented to drill with excellent results as compared to the offset wells. The initial production rate obtained was 19.4 MMcfe/d. The well was completed 10 days ahead of schedule, resulting in significant cost savings. With the successful implementation of advanced real-time reservoir navigation and drilling technology, the operator has accelerated the drilling program. The results are significant organic production growth, improved drilling performance, precise placement of the wellbore and, significant reduction in rotating hours at lower drilling and production costs.
Thermally Compensated Leak Detection Results in Significant Blow Out Preventer (BOP) Testing Efficiencies
Authors: Franklin C. M. , Sargent T. L. , Brown C. R. , Owen G. W. , Griffith S. , Osmond J. W. , Cully R.
Published: March 2011

Operators, service provides, and drilling contractors established an industry consortium to advance the art of leak detection. The initial development focused on software-based testing of BOPs in deepwater. Upon completion of the pilot program on five deepwater rigs, the results exceeded original expectations. The test results proved the software was effective, efficient, and rig friendly. Once the template was filled out, with the click of the "Start" button, the software was completely automated, up to the time of printing the report.

Through an iterative and collaborative process a unique solution for the Low Pressure (LP) and High Pressure (HP) tests has been developed. Due to the subjective nature of the Circular Chart Recorder (CCR) methodology for validating a test, a small leak may not be identified for up to 30 minutes into the HP test. With this new methodology, objective identification of a slow leak normally occurs during the LP test in less than three minutes; and a good test (no leak) typically validates in the regulatory agency's minimum holding time requirements. The software provides greater assurances, transparency, and reliability as compared to the CCR. The antiquated CCR is easily manipulated in multiple ways, which is now eliminated.

This software provides the industry with a tool for objective, efficient test validation. The software generates simple, clear, concise reports and contains more information as compared to what is currently available. It archives tests in a secure format, and the software allows the users to retrieve and review the tests for any required scrutiny. It also prints the reports to a secured PDF format and archives them.

This paper discusses the current state of the development along with the associated benefits. A vision of the application development pipeline for further pressure analysis opportunities is also introduced.
Kick Tolerance Misconceptions and Consequences to Well Design
Authors: Santos Helio , Catak Erdem , Valluri Sandeep
Published: March 2011

Kick tolerance is a key and fundamental concept used in well design. It defines the appropriate number and setting depth of casing strings that are required to achieve the drilling objectives. It is also used during drilling to determine whether it is safe to continue drilling or if there is a need to run a casing string. Alternatively, it is used to indicate whether it is safe to circulate a kick out of the well or whether bullheading is necessary. During development of a new well control system, a thorough review of the fundamental concepts involved was carried out, and, in relation to kick tolerance, a few misconceptions were identified. Among those misconceptions are issues related to the calculation of the kick volume on bottom when a BHA is present, the effects of friction losses on the wellbore annulus and choke line, and confusion between kick tolerance and maximum allowable pit gain, derived from the additional formation flow into the wellbore after the well is shut in (afterflow). Another important misconception is the assumption that an approach utilizing a single bubble model and ignoring effects of temperature, influx density and gas compressibility (z) factor in the final calculation will always result in a conservative solution.

This paper utilizes four example wells to demonstrate the effect of each component on the final kick tolerance calculation. In order to make it easier to understand, each effect is calculated individually using the same single bubble model that has been historically used. The results show that some components have more impact than others, and the consequence is not always in the same direction. Additionally, the effects on deepwater wells are more dramatic due to the long choke line. Therefore, generalization and simplification of the kick tolerance calculation in well design is not possible.
Interoperability: An Enabler for Drilling Automation and a Driver for Innovation
Authors: Andreas Sadlier , Laing Moray
Published: March 2011

Drilling automation promises to reduce costs, increase safety margins, and improve the overall efficiency of drilling operations whilst maintaining a high-quality wellbore. However, realizing this vision necessitates that components which acquire, process, provide intelligence for "situational awareness," and automatically execute instructions, share complete information. Effective decision support capabilities and the automated control of the drilling process can only occur with seamless communication based on standards that provide interoperability through an event-driven architecture.

Many standards already exist in both the oil and gas and other manufacturing process industries. Yet, the lack of adoption of these standards and best practices is predominantly due to the fear of intellectual property being compromised. We have witnessed through message-based standards the mobile handheld market's unprecedented proliferation of applications that will automate just about anything for your PDA (think Apple Inc.'s "There's an app for that"). Independent software vendors provide solutions that work seamlessly to interconnect business processes and other software systems enabled by the standards developed and adopted as a result of the Internet and the service-oriented architecture (SOA) movement. Key to this development has been the protection of individuals’ intellectual property through the encapsulation of processing and control logic. Harvesting innovation from these next-generation solution developers requires standardized messaging architectures and communication protocols.

This paper will examine several industry segments to highlight how standardization at the level of interconnectivity has affected both their interoperability and innovation. Business models that promote and reward open innovation will ultimately drive solutions for automation. But interoperability will drive more than just automation; it is the key to shattering the myth around service complexity. Protecting intellectual property (IP) requires encapsulation of process and control logic and the adoption of appropriate interface standards. Standards enable the prospect of greater interoperability, reduce system complexity through modular packaging, and drive innovation.
Well Construction Hydraulics in Challenging Environments
Authors: Martins A. L. , Aragão A. F. , Aranha P. E. , Folsta M. G , Waldmann A. T.
Published: March 2011

Hydraulics plays a major role in well construction, especially in narrow operational window scenarios, where the difference between pore and frac pressures approaches zero. Besides, special geometry wells, where annular friction losses contribute expressively to downhole pressures, are becoming attractive alternatives to enhance production. Efficient drilled cuttings transport, minimization of contamination during fluid substitution operations and gravel packing are critical operations to be performed. The hydraulic targets for such projects require multidisciplinary technological development, including real time monitoration of downhole pressure, density and friction reduction concepts, chemicals and equipment, rheology optimization and reliable multiphase models. This article focuses on the application of latest design, chemicals, software, and equipment technology for drilling and completing (including sand control) in challenging scenarios, such as ultra deepwater exploratory wells, extended reach offshore wells, 2000 m horizontal section in shallow water carbonate reservoirs, 1200 m horizontal section gravel packing in deep water non consolidated sandstone reservoirs, managed pressure drilling onshore experiences, extended reach onshore wells for offshore reservoir exploitation, including slant rig drilling and open hole gravel packing with synthetic low viscosity fluids. Finally, the hydraulic challenges for the future will be highlighted.
Improving the Quality of Ellipse of Uncertainty Calculations in Gyro Surveys to Reduce the Risk of Hazardous Events like Blowouts or Missing Potential Production through Incorrect Wellbore Placement
Authors: Ekseth Roger , Weston John , Ledroz Adrian , Smart Barry , Ekseth Astrid
Published: March 2011

Wellbore position uncertainty estimation (error modeling) is a key element in safe and cost effective drilling. The quality of error modeling has improved a lot over the last 10 – 15 years through the publication of SPE papers like SPE-67616, 90408, 103734 and 105558. These papers taken together form a good framework for error modeling calculations with one exception. None of these papers supplies the drilling industry with realistic publicly documented uncertainty estimates for gyroscopic survey tools. It has been left to the gyro service providers themselves to supply the rest of the industry with the necessary gyro model inputs, mainly without any external review/audit process. This is not an ideal situation, and represents a potential safety hazard. The gyro service providers do not only compete on price, but also on survey accuracy. This paper is an attempt to start a process to close this safety gap by presenting the actual derivation of a brand new set of realistic uncertainty estimates for some of the existing gyroscopic tools based on real downhole data and guidelines given in the above mentioned SPE-papers.
Quality Assurance of Wellbore Stability Analyses
Authors: Aadnoy Bernt S.
Published: March 2011

It has become clear that many wellbore stability studies suffers from various inconsistencies. These lead to incorrect results, or results that may not be extrapolated to other well configurations.

In this paper typical wellbore fracturing and collapse models are investigated with respect to the accuracies in the input data. It is shown that the cumulative uncertainty is considerable. To reduce this uncertainty, constraints on the in-situ stress states are invoked. The paper further advocates the need for model calibration. In addition to using leak-off, breakout and wellbore image data, methods such as establishing bounds on the in-situ data, data normalization and inversion methods are proposed to improve accuracy and to provide quality assurance. Examples are provided in the paper.
Which Material is Less Resistant to Buckling: Steel, Aluminum or Titanium Drill pipe?
Authors: Bensmina S. , Menand S. , Sellami H.
Published: March 2011

Access to reservoirs in ultra-deep and extended reach drilling projects leads the industry to develop new resistant and higher-strength materials. Drilling equipments manufacturers and drilling contractors have to meet higher requirements of operators to manufacture and operate quality tubulars in these severe environments. However, with the increasing complexity (deep, long, high-pressure/high-temperature, sour service) of drilled wells, steel may become a limiting drill pipe material. A non-steel alternative material may exist such as aluminum, titanium or composite materials.

Buckling of steel, aluminum and titanium tubulars inside wellbore has been the subject of researches and articles in the past. According to some authors, the light Young Modulus of lightweight drill pipes does not affect their buckling response: the relative low stiffness of the pipes would be balanced by reduced contact forces with the wellbore.

This paper presents a full study discussing clearly the buckling response of steel and lightweight drill pipes in both experimental bench and real field conditions.

This paper shows a full comparative study between steel, aluminum and titanium drillstrings in Extended Reach Drilling (ERD) wells and studies the opportunity to use aluminum and titanium drillstring in ERD wells while the buckling, drilling efficiency and drillstring integrity stay acceptable. Critical buckling loads for each drill pipe material and dimension is reviewed and presented, using our numerical model and in the form of charts which could be used by drilling engineers. Along this comparison, we also focus on drillstring rotation, tool-joints and dimensions effects on buckling loads.

Finally, this paper should give a better comprehension of the mechanical behavior of lightweight material for drill pipe, which can improve significantly well planning to drill wells with an increasing depth, length and complexity.
Pre-perforated Liner Design and Coiled-Tubing Acidizing of Maximum-Reservoir-Contact (MRC) Wells Offshore Abu Dhabi
Authors: Jorden John , Jackson Alfred , Keller Stu , Shuchart Chris , Alvarez J. Oliverio , Quigley Scott
Published: March 2011

This paper describes the design and installation of the lower completion and acid stimulation of two 20,000-ft-measured-depth extended-reach (ER) wells in a major oil field offshore Abu Dhabi. The wells each had 10,000-ft horizontal completion intervals in a carbonate reservoir. One well was a producer, and the second well was a parallel water injector. The wells were each completed with an engineered, pre-perforated liner run with ten swell packers. The acidizing was performed using a specially-designed 2.375-inch coiled tubing string run with a spiral jet nozzle bottomhole assembly.

About 180,000 holes were pre-drilled in each 6.625-inch completion liner using a special hole pattern based on computational fluid dynamics and finite element design. The liners were run to total depth; these are believed to be the longest high-hole density pre-drilled liners ever run. Pre-stimulation logs were run to determine the inflow and outflow and pressure profiles. Blank pipe placed above and below the swell packers helped determine the contributions from each reservoir unit. These data were used to optimize the design of the acid stimulation treatments. The acid treatments were placed by varying the pulling speed of and the pump rate into the coiled tubing. Simultaneous annular water injection was used to help divert acid away from the heel portion of the injector well.

These wells serve as pilot wells to help confirm the feasibility of developing the field using maximum-reservoir- contact (MRC) wells rather than the current practice of using much shorter (e.g., 3,000 ft) openhole completions. The use of MRC wells is expected to significantly reduce development costs over the life of the field.