bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimal Bit, Reamer Selection and Operating Procedures Improve Hole Enlargement Performance in Deepwater Gulf of Mexico
Authors: Ho T. , Alferez C. , Cortez M. , Nott I. , McNary X.
Published: March 2013

Hole enlargement using underreamers has become a necessary drilling practice in deepwater Gulf of Mexico. Underreaming while drilling saves operators an extra trip to open a hole, and improves drilling budgets. Further benefits include better equivalent circulating density management and optimal cement jobs because of the bigger annulus. With these benefits come great challenges that can be categorized into three classes: 1) Drilling dynamics 2) Drilling performance and 3) Hole quality. These challenges, if not addressed during the planning and execution phase, can lead to tool failure, lower penetration rates, and hole angle deflection. This paper presents a deepwater Gulf of Mexico success story where a total systems optimization approach was utilized to overcome the previously mentioned challenges, generating a scalable improvement in drilling efficiency.

This paper presents the planning and results from two sections of the subject well - 18 1/8 x 21 in. and 16 ½ x 19 in. Each section had different sets of challenges. The first section was drilled through an inter-bedded formation entering at the top of the salt, while the second section was drilled entirely in salt. To overcome these challenges, an optimization approach was followed, which consisted of four steps - 1) Offset well analysis 2) Bit/underreamer selection 3) Development of optimum drilling parameters and 4) Roadmap to manage these parameters on the rig.

According to field results, this approach improved the ROP by more than 15% in the 18 1/8 x 21-in. salt section. Drilling efficiency for both sections was enhanced by more than 65% when compared to previous offsets. For both sections, the maximum hole inclination was 0.13° or less, keeping the well vertical. Furthermore, lower axial and lateral vibrations were observed, eliminating downhole tool failures while the bit and underreamer came out with better dull conditions compared to the offsets.
Wellbore Strengthening-Nano-Particle Drilling Fluid Experimental Design Using Hydraulic Fracture Apparatus
Authors: Nwaoji Charles O. , Hareland Geir , Husein Maen , Nygaard Runar , Zakaria Mohammad Ferdous
Published: March 2013

This paper introduces a novel LCM drilling fluid blend which has been used successfully in the laboratory to acheive wellbore strengthening results in permeable and impermeable formations for water based and invert emulsion (diesel oil) based drilling fluids.

Optimum combinations of standard LCM (graphite) and in-house prepared nanoparticles (NPs) (iron (III) hydroxide and calcium carbonate) have been established by running hydraulic fracture experiments on Roubidoux sandstone and impermeable concrete cores. Different blended fluids were used to prop open and seal fractures. The blends that gave the highest increase in fracture pressure with minimal distortion in mud rheological properties were selected for both drilling fluid type. The optimal fluid blend for water based mud was repeated using impermeable concrete core to test for consistency of result and possible application to shale wellbore strengthening.

The optimal blend (iron IH hydroxide NPs) and graphite increased the fracture pressure by 1,668 psi or by 70% over the unblended water based mud with moderate impact on mud rheology. The optimal blend (calcium carbonate NPs) and graphite increased the fracture pressure by 586 psi or by 36% over the unblended invert emulsion mud with moderate impact on mud rheology. Plastic viscosity and 10 min gel strength have been noted as important markers or indicators that show when the blended fluid will give very good wellbore strengthening result. Absolute fracture sealing was noticed in two of the samples (sandstone and concrete) while running the re-opening pressure cycle which shows the excellent propping and sealing properties of the blend. A 25% increase in fracture pressure over the unblended mud was achieved in impermeable concrete core showing the applicability of the designed fluid in shale wellbore strengthening.

Future work involves field verification of the laboratory results achieved with the designed LCM blends.
Full-scale Testing Shows Advantages of a Quantitative Approach to Interpreting Negative Pressure Tests
Authors: Rahmani Reza , Bourgoyne Darryl , Smith John Rogers
Published: March 2013

Negative pressure tests are an important step in proving well integrity for some well operations. Although the concept is straightforward, there are no standard procedures for conducting and interpreting negative tests. Recent industry experience has shown the potential for these tests to be misinterpreted with disastrous results. This paper describes proper quantitative interpretation of both successful and unsuccessful tests demonstrated on two full-scale test wells.

Tests with and without water leaks are simulated in two vertical wells with 2971ft and 5884ft depths. Test results are interpreted quantitatively to distinguish successes from failures. In addition, the impact of leak rate and the differential pressure between the leak source and well are investigated. The impacts of gas as a leak fluid, different well volumes, different surface piping arrangements, and different measuring tanks are also shown.

The success of a test should be verified with both flow and pressure checks. For the flow check, a trend between bleed off pressure and volume can be predicted based on fluid compressibility, tubing expansion, and drainage from surface piping. Deviations from that trend will identify the onset of a leak. Early detection and control of a high rate leak can reduce the formation fluid volume entering the well and the consequent risks. Detecting a low rate leak is difficult if the test duration is too short. Therefore, a 30 minute test duration was evaluated for detection of low rate leaks.

The fundamental differences between a leak and no leak are conclusively demonstrated with quantitative results. Approaches for overcoming complications to achieving conclusive tests are explained and demonstrated. These test results and the proposed interpretation methods are applicable to vertical wells. Drilling fluid properties, multiple fluids, and thermal expansion can also influence results but were not investigated in this study. Nevertheless, these results should provide a basis for improving field procedures and minimizing the risk of misinterpreting a leak as a successful test.
Shale Play Drilling Challenges: Case Histories and Lessons Learned
Authors: Jellison Michael , Brock Jim , Muradov Andrei , Morgan Dan , Rowell Jim
Published: March 2013

Shale drilling for both natural gas and hydrocarbon liquids has increased dramatically in North America over the last several years. Shale oil and gas deposits are known to exist all over the globe including Australia and the rest of the Asia Pacific. This paper discusses the requirements for drillpipe in shale drilling applications along with a review of some of the challenges and problems associated with the drillstring in these critical applications. Most wells are horizontal with long departures. Typical wells in the Bakken Shale are 17,000 ft MD, 11,000 ft TVD with a 6,000 ft horizontal reach. Drilling these wells puts huge demands on the drillpipe and rotary shoulder connections and pushes the drilling equipment and rig crews beyond the requirements of typical onshore well construction projects. Many, if not most, of the shale wells require advanced design, double shoulder connections (DSC) on the drillstring to provide the enhanced torsional strength and streamlined connection dimensions required to effectively drill these prospects. The paper presents connection design solutions along with considerations for safe and efficient running procedures. Although, the advanced DSCs are designed to be transparent to normal drilling operations, compared to standard API connections, some problems have been encountered. The paper addresses these running and handling issues and provides guidelines to mitigate these problems. Excessive tool joint and drillpipe body wear have also been encountered in several shale plays. This is discussed, along with recommendations to limit wear. Stick-slip has created drillstring problems on several wells. Stick-slip can cause damage to the drillpipe and, in the extreme, downhole connection back-offs have occurred. The paper looks at aspects of case histories to illustrate these issues and provides lessons learned to improve shale drilling operations in North America, the Asia Pacific and other regions of the world.
Cost Effective Ultra-Large Diameter PDC Bit Drilling in Deepwater Gulf of Mexico
Authors: D'Ambrosio Piero , Prochaska Ernest , Bouska Reisha , Tinsley Douglas , Hart Sofiri
Published: March 2013

Ultra-large diameter Polycrystalline Diamond Compact (PDC) bit drilling is a fast growing cost-effective solution in high-tier deepwater drilling operations in the U.S. Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller cone (RC) (IADC Code 111-115) drill bits on positive displacement motors (PDM) in these ultra-large diameter intervals. Cost savings on drilling fluid alone, in the form of Rate of Penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on Rotary Steerable System (RSS) drilling assemblies.

New robust high torque capacity top drives, stronger drillpipe connections, larger diameter RSS tools and improved mud programs have all largely contributed to this step change in drilling performance. Additionally, evolved bit and BHA design, efficient operating parameters, improved hydraulics and vibration prediction modeling have all aided in the success of these runs.

Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to: BHA steerability, rig equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling fluid displacement, drillpipe torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others.

This paper will concentrate on the multiple aspects of ultra-large diameter riserless PDC bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower cost per foot approach through the potential reduction of drilling time in these challenging applications.
Novell Drilling Fluid Design Enables Successful Drilling of Depleted Carbonate Reservoirs Offshore Republic of Congo
Authors: Thomas Seye , LELEUX Jerome , Delvaux Alex
Published: March 2013

A unique air-energized drilling fluid was developed that enabled all 13 wells in the development program of the Emeraude field, Offshore Pointe-Noire, Republic of Congo to be drilled with only 19-bbl downhole losses and zero non-productive time. The energized air-surfactant polymer drilling fluid used on the Emeraude field has potential for drilling similar depleted carbonate reservoirs in West Africa.

The Emeraude field is a major hydrocarbon accumulation lying offshore Pointe-Noire, Republic of Congo below water 60 to 75 m deep. The 150 m thick reservoir is a complex sequence of interbedded silt and fractured carbonates with an average reservoir pressure of 0.4 to 0.7 sg equivalent pressure. Such low reservoir pressures present considerable drilling challenges, including efficient hole cleaning in inclined wellbores up to 53°, minimizing stuck pipe risk from excessive overbalance pressures in permeable and depleted formations, and minimizing downhole fluid losses in fractured carbonate formations. Over fifty previous offset wells, which were drilled with various types of drilling fluids, suffered from total losses and subsequent poor cement jobs, as well as high water-cut hydrocarbon production.

The drilling program was very successful with very minimal downhole losses and zero non-productive time. Hole cleaning was excellent at all times as evidenced by low rotary torque, pick up and slack off weights while drilling and tripping out of hole. In addition, cementing operations were completed successfully with full returns, and initial production had zero water-cut.

This paper details case histories from the Emeraude field 13-well drilling program, focusing on the design elements of the novel drilling fluid. Best engineering practices adopted to successfully drill these challenging wells also are described in detail.
Analytical Model to Estimate the Drag Forces for Microhole Coiled Tubing Drilling
Authors: Zhang Yuan , Hao Ye , Samuel Robello
Published: March 2013

Microhole coiled tubing drilling is a new technology that provides many added advantages but at the same time poses numerous operational challenges. This manifests itself in a number of ways, all of which adversely affect the efficiency of the drilling process. These problems include increased wellbore friction, poor hole-cleaning, tubular failures, and associated problems during tripping operations. Presently conventional torque and drag models are used to calculate drag forces and surface loads during microhole coiled tubing drilling. However, these estimates might be under conservative. Therefore, an improved model and more comprehensive analysis are required.

Conditions expected during microhole coiled tubing drilling are completely different from those encountered during conventional drilling. Further complexity is added when the wellbore is undulated. This paper describes a new analytical model for estimating drag forces by assuming that pipe in the horizontal portion follows a sine function wave due to residual bends and snubbing force. In addition, the model takes into account when the wellbore is also tortuous. Fluid viscosity (an important force in the microhole) is also included so we can calculate appropriate surface loads in addition to drag. This study concludes that besides wellbore inclination, curvature, and wellbore torsion, parameters such as wave length and contact area also influence the results. This paper documents the comparison between the predicted mathematical simulation results with actual data from wells describing the accuracy and applicability of the model. The analysis results and comparison are presented along with three examples.
Practical Guide to Lost Returns Treatment Selection Based on a Holistic Model of the State of the Near Wellbore Stresses
Authors: Duffadar Ranojoy D. , Dupriest Fred E. , Zeilinger Sabine C.
Published: March 2013

This paper presents a holistic model describing the relationship between the state of the hoop stress in a given well and the selection of lost circulation treatments. While some losses are vugular, the majority of lost returns events are due to the propagation of a fracture that develops when the borehole pressure overcomes the total hoop stress, which is the stress holding the hole closed. Although methods such as casing drilling, lost circulation pills or continuous fracture sealing fluids appear dissimilar, each stops losses by modifying the hoop stress. If a treatment does not modify the stress holding the hole closed, it does not change the pressure at which the borehole will open. This unifying concept is not always apparent to engineers and operations personnel since treatments are described to act in ways as diverse and seemingly unrelated as tip plugging, sealing, smearing, etc. Consequently, those who develop and execute new treatments may not be asking important questions that could further improve treatment performance and operational practices.

In the proposed model, the potential state of the hoop stress is placed on a single pathway that is divided into four distinct regimes. At one end of the spectrum are those treatments that prevent losses by simply ensuring that the ideal hoop stress predicted by Kirsch is preserved. At the other end of the spectrum are severely depleted wells where treatments must achieve very large increases in hoop stress. Common industry treatments are categorized by the hoop stress regime in which they are applicable, and the conceptual limit to which each might enhance integrity is discussed.

The authors' purpose in describing these concepts and treatments within a holistic hoop stress continuum is to improve treatment selection, facilitate field diagnostics, and highlight the need for further research in some areas.
Operational Control and Managing Change: the Integration of Non-technical Skills with Workplace Procedures
Authors: Thorogood J L , Crichton M T
Published: March 2013

Some of the common pitfalls and problems associated with managing operations are discussed with suggestions about how these can be addressed. Existing literature on human error, operational decision-making and industrial psychology is combined with the authors' experience in researching these problems and working with operations teams. The non-technical skills required to manage operations effectively are described together with the organisational structures and work processes that best support operations. Techniques for training teams and helping them to develop the competencies for teams to manage operations safely and deal with uncertainty are explained.

Mindful that "Proper planning prevents poor performance", engineers go to considerable lengths to create quality plans. A structured well delivery process is followed, complete with peer reviews, risk assessments and technical sign-offs. Deliverables include statements of requirements, basis of design documents, HAZID sessions, drill the well on paper meetings and a drilling programme.

Despite these preparations teams make decisions during operations with sometimes costly consequences, especially when surprised by an unexpected event or when facing high levels of uncertainty. This problem is not unusual and typically occurs when teams fail to prepare and actively manage the transition from planning to operations, and to anticipate the necessary change in the functioning of the team. Planning and operations require completely different modes. The lack of preparation for this transition stems from a common assumption that the team that has done the planning is more than capable of managing a dynamic operation effectively. Research has identified that two different modes are required; planning teams produce a plan designed to solve a problem, whereas an operations team has to manage a task requiring the ability to adapt dynamically to shifting demands of the situation.

Effective operations management requires a high degree of operational discipline and teams that are skilled in dealing with the unexpected and making decisions in time-constrained situations. These skills are not intuitive and must be taught, trained, practised and assessed. The protocols and decision rights must be clear and the team trained so that it executes these functions in a fluent and competent manner.
Evaluation of Filter Cake Mineralogy in Extended Reach and Maximum Reservoir Contact Wells in Sandstone Reservoirs
Authors: Ba geri B. S. , Al-Majed A. A. , Al-Mutairi S. H. , Ul-Hamid A. , Al-Sultan A. S.
Published: March 2013

Good knowledge of filter cake structure and composition leads to successful selection of drilling fluid that minimizes formations damage and selection of an effective and efficient recipe for removing the filter cake.

This study focus on an aspect which was not fully covered in the literature: the chemical characteristics of filter cake formed along the horizontal well, from its heel to its toe. High pressure fluid loss tests were performed using real drilling fluid samples from the field which were collected during drilling horizontal section of a sandstone formation. The mineralogy of the external filter cake formed by fluid loss cell is determined using both Scanning Electron Microscopy (SEM) and X-Ray Diffraction (XRD).

The results showed that for long horizontal sections, the composition of the filter cake was not constant from its heel to its toe since the small drilled cuttings or particles, that are not completely removed, were mixed with the drilling fluid during circulation and become an integral part of the fabric of the filter cake.
Operational Reliability Assessment of Conventional vs. MPD on Challenging Offshore Wells
Authors: Don Hannegan P. E
Published: March 2013

Value-added efforts towards determining the optimum approach to drilling challenging offshore prospects include applications of reliability centered strategy early in the planning process. The objective would be to determine the drilling method with highest probability of enabling a safe, on-time and on-budget drilling program that reaches total depth objective with large enough hole for viable production.

Reliability assessments focus on probability of successful functioning; fit for a purpose, resistance to failure, ability to perform a required function for a definitive period of time, and ability to fail well. The reliable performance of the hydraulics of the circulating fluids system itself, even if the encountered pressure environment is not within the predicted drilling margin of error, is critical for operational success.

This presentation applies Reliability Engineering skills to a HPHT prospect whose water depth and formation pressure map suggests risk of kick-loss scenarios, differential sticking, cementing challenges and TD with too small a hole. An offset well's actual experience with conventional drilling methods will be compared with an operational reliability assessment of applying some applicable variation of managed pressure drilling (MPD) on the proposed well.

Reliability theory became a creditable science during the early days of sail ships to inform investors of the reliability of a vessel to return safe & sound.1 The author proposes that operational reliability concepts remain valuable in marine environments and are uniquely applicable for the purpose of choosing the optimum drilling and well construction methods for drilling challenging offshore drilling programs.
New Generation Thermally Stable Cutters Deliver High Penetration Rates While Maintaining Durability in the Troll Field, Norway
Authors: Roberts Tom , Hæreid Olav
Published: March 2013

One of the main challenges drilling within the Troll field, offshore Norway is maintaining a high Rate of Penetration (ROP) while drilling through hard calcite cemented stringers (Jones et al. 2008a; Gunderson et al. 2008). The calcite distribution in this field is complex and can be difficult to predict, while it is easy to maintain a high ROP when drilling the sand sections between the stringers. Early wear or damage to the cutting structure limits the bit's ability to apply sufficient point loading to efficiently cut through the calcite and remaining lithologies, so the key aspects in solving this challenge is to retain the sharpness of the Polycrystalline Diamond Compact (PDC) cutters and minimize the risk of impact damage when hitting these thin inter-bedded stringers at high penetration rates.

Following an in-depth study of the application, the drill bit design evolved following several iterations that included computational fluid dynamics to optimize fluid impingement angles and reduce fluid induced shear stress on both the bit body and cutter substrates. Torque control components were introduced to improve the design's response to weight-on-bit, minimize stick-slip and improve directional response. Detailed laboratory tests were conducted to investigate a new edge preparation applied to a new thermally stable PDC cutter, and the cutter-rock interaction was modeled to investigate complex wear, involving impact, abrasion and thermal mechanisms, while drilling these highly inter-bedded formations.

The results of this research led to new cutter and bit technologies which have proven that the combination of improved thermal resistance and more efficient cutter geometry enables the cutters to stay sharp while drilling through the hardest stringers and maintain greater durability to complete the section. The improved designs have now drilled further and faster than any previous attempts, resulting in significant cost savings for the operator.
Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well
Authors: Gradishar John , Ugueto Gustavo , Van Oort Eric
Published: March 2013

This paper details the case history of the highly challenging extended reach deepwater A-10 well, drilled in the Ursa ("Bear" in Latin) prospect in the Gulf of Mexico. This 30,000 ft well, drilled from the Ursa TLP at a vertical depth of 18,000 ft and a horizontal displacement of 20,000 ft, targeted the Yellow sand in the Ursa-Princess section of the greater Mars-Ursa basin. During the drilling of the original hole, a subsequent sidetrack and two mechanical bypasses, a number of significant hole problems materialized which caused extensive non-productive time and an associated cost overrun. These problems were clearly associated with the drilling of a complex well that combined a high deviation and extended reach wellbore with a very narrow and pressure-depleted drilling window, characteristic of the Gulf of Mexico's challenging geopressured environment. In all, at least five independent borehole failure mechanisms were encountered while drilling the original hole and its successive sidetracks/bypasses, which were exacerbated by an additional complicating factor:

Lost circulation in natural fractures, ultimately responsible for the loss of the Ursa A-10 original hole. Lost circulation in induced fractures, with associated heavy mud losses. Borehole fatigue, caused by stress cycling on weak formations due to annular pressure fluctuations. Borehole instability caused by too low downhole hydrostatic pressure, responsible for the loss of Ursa A-10 sidetrack 1. Borehole instability caused by an in-situ fractured formation that proved hard to stabilize on wells Ursa A-10 sidetrack 1 bypasses 1 & 2, and ultimately forced the well to be completed in shallower Magenta sands. Complicating Factor: barite sag of synthetic based mud in high-deviation wellbores, which led to exacerbation and complication of the previous failure mechanisms.

An extensive lookback study was carried out on the Ursa A-10 well, leading to the development of several important lessons learned and best practices (for hole cleaning, ECD management, sag control etc.), and the development of new systems (including novel, sag-resistant synthetic-based mud formulations). A succinct overview of the Ursa A-10 case history and a comprehensive summary of its learnings are provided here in order to help the future drilling of extended reach wells in geopressured, low-margin deepwater environments.
Drilling Unconventional Shale Wells Remotely
Authors: Gongora Cesar , Awan Omar , Mota Jose , van Oort Eric
Published: March 2013

After a successful pilot application in the Haynesville Shale, Shell Upstream Americas is currently taking steps to conduct all of its directional drilling, MWD/LWD and geosteering operations in the Americas and beyond from remote drilling centers. The main drivers for the use of these centers are:

More wells can be directionally drilled with the involvement of the most knowledgeable / most experienced directional drilling / MWD/LWD / geosteering staff, while at the same time new staff can be trained and developed effectively from a central location. Safety is improved by having less staff commuting back and forth to the rig site (i.e. reducing the number of driving-related accidents), and by reducing occupational exposure through the decrease in number of people "in harm's way" present at the rig-site itself. Remote geosteering at a central facility allows for efficient communication between geologists and interpreters, with a single geosteering expert and a single geologist being able to handle a large number of geosteering operations at the same time, while at the same time greatly improving the speed of decision-making. Staying within the shale target zone and reduction of the number of geosteering corrections and doglegs while landing the horizontal section, resulting in noticeably improved wellbore quality, which yields immediate benefits in the ease of running production casing and will ultimately translate in higher hydrocarbon recovery.

The learnings and best practices associated with the ongoing implementation of the remote drilling centers for unconventional shale drilling operations in the Americas are compiled. This includes a review of the technologies involved, the new workflows that were implemented, how the "people issues" were addressed, and what results - including a 90% improvement in the speed of decision making, clear improvements in wellbore placement and quality, and the drilling of best-in-class directional wells in the Eagle Ford Shale - were obtained. In addition, the future of remote directional drilling and its extension into drilling automation is briefly discussed.
Innovative Rolling PDC Cutter Increases Drilling Efficiency Improving Bit Performance in Challenging Applications
Authors: Zhang Youhe , Baker Ryan , Burhan Yuri , Shi Jibin , Chen Chen , Tammineni Sandeep , Durairajan Bala , Self Jordan , Segal Steven
Published: March 2013

Extended footage capabilities and high rate of penetration give PDC bits a distinct advantage over rollercone bits in many applications. However, the fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts the formation, and as the cutters wear/chip drilling efficiency declines. The industry requires new technology that can effectively utilize the entire 360° diamond cutting edge to reduce frictional heat/wear while increasing drilling efficiency and bit life.

A plan was initiated to rotate the cutter while drilling and engineers investigated different retention methods and cutting structure designs to create the optimal driving force to accomplish the objective. Several designs were implemented that hold the cutter securely in place and allow full cutter rotation. These assemblies were extensively modeled using FEA and laboratory tested to evaluate function and strength. In a test apparatus, the new shearing element (rolling cutter/RC) was able to cut an extended section of rock with a consistent force level (lbs). Conversely, the traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency.

Initial field testing targeted the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. Application challenges include slow ROP and premature tripping for a new bit. A six-bladed prototype PDC bit was manufactured with three rolling cutters positioned in the shoulder area. The bit was run on a steerable motor through the horizontal interval with good results. The next prototype was equipped with additional RCs and drilled more footage compared to offset average. Additional experiments are being conducted with RCs which will continue to increase performance. The authors will present several case studies which will document performance improvement in challenging drilling environments.
Industry's First Hydro-Mechanical Surface Controlled System for Multiple Reamer Activation/Deactivation Increases Drilling Efficiency
Authors: Torvestad Bjoern Tore , Bjoerneli Hans Magnus , Toerge Ketil , Andreassen Lars , Haavardstein Stein , Blikra Harald
Published: March 2013

Using a concentric underreamer is a widely used technique for efficient wellbore construction. Most underreamers are fitted with lock-out systems to provide a means of drilling out the shoe-track with the cutters closed before enlarging the tool below casing. Several underreamers also provide a system to lock the tool closed after reaching TD to enable full flow while POOH for best possible cleaning. However, a major limitation these systems have in common is the underreamer cannot be reactivated once closed and the tool must be placed at top BHA due to the activation method.

To increase reamer efficiency/BHA flexibility, a new hydro-mechanical system has been developed that makes it possible to perform multiple activation/deactivation of the underreamer by manipulating the flow rate in a short sequence allowing infinite open/close cycling for selective underreaming and more flexible placement opportunities within the BHA. The concept does not require any form of device to be pumped down the drill string. The system also increases the potential to save rig time on the activation/deactivation sequence.

Through the field testing stage, it has been proven that the system works as designed under difficult drilling conditions. It delivers operator value by having the flexibility to selectively activate/deactivate and save rig time. The majority of runs have been on complex rotary steerable BHAs together with MWD/LWD systems and does not interfere with those tools’ operating range. All criteria set in the comprehensive field testing plan have been met to qualify the reamer as a viable downhole tool system.

Several case studies will be presented to document successful operation of the on-demand surface controlled system with details about operator benefits including downhole flexibility, cost savings and increased safety.
Surge and Swab Effects Due to Vessel Heave in Deepwater Wells: Model Development and Benchmarking
Authors: Chandrasekhar Sharat , Bacon William , Toldo Benni , Suryanarayana P. V.
Published: March 2013

During operations in deepwater wells (such as, for instance, running smart completions), there exist periods when the axial movement of the string in the well remains uncompensated. During these periods, vessel heave is imposed on the string at the surface, resulting in transient pressure fluctuations (swab and surge effects) in the fluid downhole. The problem is further complicated by the presence of multiple flow ports in the string, and of choke and kill lines at surface, as well as float valves in the string itself. As the margin between pore and fracture pressure is narrow, these fluctuations can create conditions for an influx or lost circulation, with potentially significant consequences. While existing literature and commercial models address the classical drill pipe induced swab/surge due to tripping, they do not model multiple flow paths and/or continuous forcing functions (such as heave) at the surface of the drill string or completion string.

In this paper, we present the development of a semi-analytical approach to model such transient pressure problems. The transient pressure problem is solved using the method of characteristics, and draws from the seminal work of Lubinski et al. and employs the electrical analogy first proposed by Bergeron (Water hammer in Hydraulics and Wave Surges in Electricity", John Wiley, 1961). The method is extended to include Power-Law fluids (as well as Bingham Plastic and Newtonian rheological models). Arbitrary flow ports can be situated anywhere in the string, with either one or two-way flow. Both open- and closed-end pipes are considered, in addition to nozzles at the pipe end. Temperature and pressure effects on the compressibility, as well as the elasticity of the formation, are considered in the calculation of the characteristic impedance. The approach can accept any arbitrary forcing function at surface, either as a periodic wave or as a tabulated time function of displacements. Several limitations of the previous models are also addressed in the theoretical development reported in this work.

The method is implemented in a spreadsheet tool that allows the input of a wide variety of situations, incorporates different fluid PVT and rheology models, and calculates transient pressure at any point of interest in the annulus. The model is compared to several benchmark field cases in the literature, and the comparison is shown to be very satisfactory. Finally, a case of a smart completion with one to four flow ports in the lower sections that can be selectively closed or opened, subjected to sinusoidal vessel heave at surface, is examined. Results show that the pressure fluctuations can be substantial in some of the cases, and suggest that with appropriate fluid selection and operational procedure, even large heave can be sustained without initiating either underbalance or lost circulation.
Perforating Gunshock Loads - Prediction and Mitigation
Authors: Baumann Carlos , Lazaro Angel , Valdivia Paulo , Williams Harvey , Stecchini Paulo
Published: March 2013

Perforating wells calls for careful planning to maximize well productivity over the life of the well, and to prevent time and money losses due to unexpected side effects. A large class of wells and in particular high-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents applications of a simulation methodology to predict gunshock loads for tubing-conveyed and wireline-conveyed perforating jobs. With this simulation methodology we can evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, cable size, tubing size and length, number of shock absorbers, rathole length, placement and setting of packers, and early reservoir response, among many others.

When planning perforating jobs, engineers strive to minimize the risk of equipment damage due to gunshock loads. With the simulation software presented in this paper, engineers can identify perforating jobs with significant risk of gunshock related damage, such as unintentional pull-offs, bent tubing and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are made to reduce gunshock loads to an acceptable level.

Fast gauge pressure data from perforating jobs shows that wellbore pressure transients can be accurately predicted. For well prepared simulation models, typical peak sustained pressure amplitudes at the gauges are on average within 10% of simulated values. In jobs where shock absorbers were used, residual deformations of crushable elements correlate well with predicted peak axial loads; which confirms that gunshock loads on the equipment are well predicted.

With the simulation methodology described in this paper engineers can evaluate perforating job designs in a short time, and they can optimize perforating jobs by reducing gunshock loads and equipment costs. The ability to predict and mitigate gunshock damage in perforating operations is very important because of the high cost of typical high-pressure wells.
Fit-for-Purpose BHA Design for Drilling Complex Wells Offshore Brunei Leads to New Industry Benchmark
Authors: Legarth B. , Dustin S. , Montero J. , Walker J. , Mulligan R. , Maeso C.
Published: March 2013

Some of the oil fields offshore Brunei are characterized by complex reservoir geology. This requires the drilling of high-complexity, tortuous 3D horizontal wells referred to as "snake wells" for optimal reservoir drainage. These wells deliver an ultimate recovery equivalent to multiple horizontal wells drilled in the same structure. This development concept was chosen as the most beneficial with the business value drivers for the Selangkir Iron Duke (SKID) project.

Over a period of several years, drilling performance had improved but plateaued and still contained hours of nonproductive time (NPT), including hole conditioning wiper trips, rough drilling causing bottomhole assembly (BHA) failures due to vibrations, troublesome trips, and even lost production due to stuck-pipe incidents. In previous "snake well" drilling campaigns multiple additions to the BHA design to overcome tight hole problems had seen an ever more complex and rigid BHA being adopted, but without the required NPT or well cost reductions.

In an attempt to make a step change in performance the BHA design and drilling processes have undergone a comprehensive revision. The primary focus areas were to enable shoe-to-shoe runs, reduce the risk of stuck pipe, improve tripability of BHA, reduce torque and drag and last but not least improve the overall hole section progress. A more flexible, slimmer rotary steerable system (RSS) BHA design having a shorter, compact sourceless logging-while-drilling (LWD) tool was proposed to reduce damaging vibrations and ease tripping.

The paper discusses engineering solutions implemented to mitigate risks associated with complex well geometries which consequently contributed greatly to deliver the high-complexity extended-reach drilling (ERD) wells with top quartile and even best-in-class performance in the Rushmore's Drilling Performance Review (DPR).
Little Things, Big Effect-Identifying Causes and Addressing Vibrations Issues in Challenging Deepwater Applications
Authors: Mensa-Wilmot Graham , Benet Paul , Ramchune Devanand , Maddoux Blake
Published: March 2013

As performance dysfunctions1, Vibrations2 have drastic consequences on drilling operations. The challenges presented by vibrations get amplified on deepwater drilling programs. Vibrations cause downhole tool failures, thereby forcing multiple bottomhole assembly (BHA) trips. In some instances, connections become over-torqued and cannot be broken out on rigs. This situation creates logistical problems for service partners and operators alike (due to the requirement to have multiple back-ups for various tools), and with huge implications on project costs. Vibrations also create drilling inefficiencies with regards to borehole verticality and directional performance. Considering the total measured depths (TD) on deepwater projects, borehole verticality is usually a critical operational requirement. In other instances, the need to achieve specific wellbore trajectory requirements directionally based on project specifics also becomes critical. As a result, rotary steerable systems (RSS) are commonly used on these projects. However, and as documented extensively, vibrations compromise achievement of these goals even when RSS tools are used. Additionally, vibrations have negative effects on rate of penetration (ROP). This is why vibrations control continues to preoccupy the industry, particularly on deepwater projects. Considering the complexities associated with these projects and their much higher rig and spread rates, vibrations control is critical for project success.
The Use of Along String Annular Pressure Measurements to Monitor Solids Transport and Hole Cleaning
Authors: Coley Christopher J. , Edwards Stephen T.
Published: March 2013

For many years the oil industry has been limited by the fact that measurements are only taken at the BHA and at surface during well construction operations. This has led to a reliance on modeling to help understand the measurements made and to understand the conditions in regions of the wellbore that are not being directly monitored. The advent of sensors that can be deployed along the drill string has created an opportunity, for the first time, for operators to observe the downhole environment not just at the BHA but throughout the entire wellbore.

In order to realise the value of these measurements it is necessary to expand existing analysis techniques and develop new methods specifically designed to make use of this expanded sensor capability. BP was the first operator to commercially deploy the along-string measurement sensors in a development well (2008) and has been making use of the technology ever since. This paper presents some of the analysis methods used in these deployments as well as some of the lessons learned. It is shown that, while the addition of along-string sensors can increase the complexity of analysis, the information that can be gleaned from this data can be very valuable.
BOP Testing - Qualification Tests, Test Facilities and the Efficient Means of Operating Them
Authors: Springett F. B. , Johnson C. , Shah M.
Published: March 2013

In the world we know today, BOP performance is in the limelight all the way from the manufacturers to governmental levels. Greater performance objectives require higher testing standards. Testing and qualification of BOP equipment as dictated by API 16A involves facilities with the capability to test BOP's in multiple environments and operating scenarios. This paper will discuss the test set up for each type of test, the criteria for acceptance and the type of facility required to perform it. The types of tests to be discussed as defined in API 16A are fatigue testing, high temperature, low temperature, stripping, hang off, sealing characteristics, shear testing etc. The paper will also discuss some of the potential future testing requirements as well as the equipment required to perform it based on industry discussions of these requirements. Finally, the paper will discuss the process by which a multimillion dollar R&D lab was developed and operated from the ground up. It's not only about capability; it's about capacity. Applying manufacturing principles to the design and operation of an R&D Test facility achieved significant gains in the quality and output of tests performed. In summary, this paper will examine the needs of a modern BOP test facility and the methods used to deliver on those needs effectively.
Upstream E&P and Drilling Safety and Optimization – Lessons from the BioPharma R&D Industry: The Role of Translational Analytics and Informatics
Authors: Madhavan Suresh , Dalgliesh Jeff , Kimball Jon
Published: March 2013

There is an uncanny resemblance between the Upstream Oil and Gas Exploration and Production (E&P) industry and the BioPharma R&D Industry, which discovers, develops and markets drugs and vaccines. This paper will describe these comparisons; discuss some of the new trends in the BioPharma industry and show why there are lessons there that are just as valid and important to the Upstream Oil and Gas industry: Translational analysis across traditional development (departmental) data silos to get a better understanding of the underlying nature of the asset being developed is important. ○Discovery, Nonclinical, and Clinical development of a drug candidate in Pharma R&D;○Earth Science, Reservoir, Drilling and Production data in Upstream Oil and Gas of a potentially producible oil field.The BioPharma industry has recognized the need to extract enriched metadata and patterns from collected raw data; and it is now moving towards building models with these patterns for decision making. ○This is relevant for the Oil and Gas industry particularly for drilling safety and prediction.Dealing with disparate data types and their volumes has proven difficult with traditional data warehouse technologies and elusive in meeting the goals of a flexible innovation platform for the future.