bluuebunny/crossref_metadata_2025 huggingface dataset:
Continuous Improvement of Assets Through Existing and New Digital Oilfield Technology
Authors: Kamal S. Z. , Williams J. , Liddle J.
Published: June 2014

Over the past decade, upstream exploration and development companies have deployed "digital oilfield" concepts as a means to integrate and effectively utilize real-time data to influence and support operational decision making. These deployments have, in general, resulted in enhanced safety management, reduced operational risk and cost as well as increased production.

At BP, we are maturing and deploying a new generation of real-time capabilities that combine domain knowledge with technical expertise to sense, gather, analyze and synthesize information to enhance decision making to efficiently utilize technology and standard real-time work processes at our assets. In this paper, we will share our experience of taking BP’s inventory of current deployments to benchmark and assess the state of real-time instrumentation, data acquisition, transmission and staff ability as a means to identify, quantify and prioritize opportunities. This assessment includes an evaluation of each asset’s ability to sustain and adopt new capabilities in a holistic manner, resulting in prioritized implementation plans to realize potential improvements.

The scope of our assessment spans upstream processes from reservoir management all the way through export. We are specifically interested in key interfaces between the reservoir, well, facility and export lines to identify system optimization opportunities to improve functional integration and real-time decision making.
A Center of Excellence for Electrical Submersible Pumps
Authors: Spagnolo S. , Pilone S. , Corti L. , Astorino G. , Dellabianca A. , Di Renzo D. , Ogidi M.
Published: June 2014

1

The center of excellence concept is worldwide associated to new software, tools and technologies that help the team to pursue excellence in a particular area.

The increasing use of sensors and gauges in the Oil and Gas field drove eni to develop internally the Center of Excellence for Electrical Submersible Pumps, to monitor and interact directly with the worldwide Business Units and to address the ESP issues.

The tool and all the technologies behind had been developed by the Artificial Lift team, under the Completion Department, thanks to the strong effort of the IT Department in San Donato Milanese, Italy.

The Center of Excellence (from now CoE) gives mainly the following information for each well: Pump details and operative parametersWell surface dataKey Performance Indicators

All the data are collected in real time and the team can visualize any variables to perform a detailed analysis.

The CoE system is a web-based tool that is available on the eni intranet, and provide the possibility to store well-related documentation.

The most important advantage given by the CoE is the possibility to navigate through the KPIs, easily adaptable based on the field experience.

One of the analyses possible in the CoE consists of comparison of the real-time pump intake and discharge pressures and the relevant simulated values retrieved from the Prosper model stored in the CoE system.

In case of mismatch, a notification will be generated and will be sent to the technicians (via mail).

Once the wells that are producing with KPIs out of the desired range have been identified, the Artificial Lift team can immediately take corrective actions.

Presently the tool is fully operative for 20 wells in Alaska, and for 1 well in Italy and for 20 wells in Iraq and the process is ongoing to have other eni BUs online.

Definitely the CoE could be helpful to optimize the operation and to analyze the wells in a smarter way than in the past.
Solving Deepwater GoM Pore Pressure Puzzle: Multiple Activation Reamer Eliminates Trip Prior to Running Coring Bottomhole Assembly
Authors: Yi Xianjie , Corbin Kevin , Davis Jefferson , Davis Patrick , Mujumdar Hrishikesh , Nagaraj Mahavir , Yalcin Oguz
Published: June 2014

The nature of pore pressure profile on deepwater Gulf of Mexico wells dictates the need for hole enlargement while drilling (HEWD) on several intervals. HEWD is a well-established practice in deepwater GoM and allows casing programs with smaller ID clearance between consecutive casing strings.

Although the reservoir section is typically drilled as a single diameter, HEWD is required for many of the larger upper hole sections. However, in some cases drilling conditions require the operator to deviate the casing program from plan. On a recent deepwater Gulf of Mexico Lower Tertiary well, pore pressure anomalies, high mud weight and associated equivalent circulating density (ECD) required the operator to raise formation integrity test (FIT) to the maximum limit while drilling the 14½" x 16½" section. To solve the problem it required premature setting of a 14" casing string.

The subsequent12¼" section was initially planned as a single diameter drilling interval. However, to account for pore pressure variations experienced on the previous section and to avoid narrowing of the producing casing size the plan was modified to incorporate a contingency liner. The 12¼" section would have to be enlarged to 13½" in case a contingency 11-7/8" liner was needed. Adding to operational complexity, the original drilling program included a plan to core the 12¼" section. To stabilize the coring BHA would necessitate a minimum of 250ft of 12¼" rathole. To achieve all 12¼" objectives, it would require an extra unplanned trip.

To solve application intricacies, the operator elected to use a new-type ream-on-demand (RoD) system in the 12¼" section and eliminate multiple trips to change out BHAs. RoD technology is equipped with an innovative hydraulic mechanism that can be opened and closed multiple times as required while drilling.

After risk assessment and pre-job planning, the 12¼" section was successfully underreamed to 13½" diameter with the RoD tool. The pressure regime was carefully monitored and it was determined the 11-7/8" contingency liner was not required. The reamer was then closed at the top of the coring section and a 12¼" borehole was drilled an additional 250ft offering the required stabilization for the subsequent coring run. Utilization of the RoD technology eliminated a round trip prior to using the coring BHA and significantly increased operational efficiency while enhancing project economics.
Innovative Heavy Landing System for Ultradeep Offshore: Extended Slip Crush Resistant Tube, Enhanced Slip Design and Heavy Weight Carrier
Authors: Franchi Jonathan , Granger Scott , Flores Vincent , Vierke Andre , Grotherr Joern
Published: June 2014

The offshore industry's current trend is driving towards ultra deepwater wells, combined with deeper total depths. In order to be able to set and run larger and heavier casing strings with hook loads approaching or exceeding 2.5 million lbs, an innovative heavy duty landing system has been developed and put on the market.

Such systems must be capable of landing heavy loads while ensuring slip crush resistance. It includes an extended slip with enhanced design (coupled with a new greasing system), a 2.5 million lbs landing carrier and a pipe with a thick walled high strength material section, a light weight tube, and a rotary shouldered connection.

One of the current operational challenges with existing heavy duty landing strings is linked to the positioning of the slips, in particular when using extended slip designs. The limited length of the slips area requires additional time for proper positioning and set up. To address these issues, a new slip proof section design has been developed: the combination of an extended crush proof section and the absence of a heat affected zone in that particular area decreases running time while completely eliminating the risk of setting the slips on a weak point.

The "Spiri-Reinhold pipe crushing" formula has been used to design this system. However, considering the approximation of this model's results, crushing performance has been assessed using the Finite Element Analysis, as well as physical tests performed with a specifically designed pulling unit. These full scale test results have been compared to the ones obtained with both the Finite Element Analysis and the standard "Spiri-Reinhold pipe crushing" formula.
Unified Team Approach: Leveraging Real-Time Capabilities Reduces NPT while Enhancing HSE Effectiveness
Authors: Ibrahim Hani , Gidh Yash
Published: June 2014

Significant improvements in remote drilling operations have been made in recent years. With proper positioning, these advances could help mitigate the challenge of replacing a retiring workforce. Another concern when transitioning from a tenured employee to one with less experience is work efficiency. While data from the USA Federal Bureau of Labor Statistics has shown the trend for injury accidents has been steadily declining, incidents of Non Productive Time (NPT) have gone up significantly. It appears the traditional approach of passing knowledge to the next generation of engineers has been broken negatively impacting the drilling industry.

To address the disturbing trend, a Middle East operator has been investigating various technologies to facilitate improvement and reduce NPT. The provider has applied a strategic combination of services and modeling systems to achieve the objective including a real-time ANN drilling parameter optimization system that provides information to ensure maximum run length from all bits and downhole tools at the highest possible ROP. Benefits of the system include extended tool life, fewer trips and the ability to manage the bit's dull condition.

The provider's mud logging managed the operation locally at the well site, while their drilling and measurement personnel monitored the processes at the operations service center in the Middle East. In Houston, the bit company offered technical assistance effectively covering the drilling operation continuously.

The unified team approach involved getting the operator engaged as a key member in the planning and execution stage. The process yielded higher data visibility, making it easier to identify and reduce NPT. It also aided in improving workflow and furnished optimized drilling parameters at the rig-site to ensure improvement in drilling efficiency and higher ROP. By leveraging real-time data, operators can optimize drilling efficiency to help bridge the experience gap until the next generation of drilling engineers are fully trained.
Development of Well Complexity Index to Improve Risk and Cost Assessments of Oil and Gas Wells
Authors: Nzeda Blaise G. , Schamp Juergen H. , Schmitt Thomas
Published: June 2014

The Well Complexity Index (WCI) is composed of Drilling Complexity Index (DCI) and Planning Complexity Index (PCI). The DCI addresses mainly subsurface challenges encountered during drilling operations (including those related to drilling rigs, equipment, weather, etc.). The PCI addresses surface challenges such as logistics, geopolitics, environments, and climate. Wintershall has developed a Drilling Complexity Index and a Planning Complexity Index, which are simple systems used to rate the complexity of well planning and operations during the project evaluation and gated planning phases; from the conceptual or pre-screening phase through the detailed design phase to the execution phase.

The development & evaluation of Wintershall's Well Complexity involved the following tasks:

Definition and ranking of factors that influence a well's complexity, splitting them in surface and sub-surface factors. Development of a simple method(s) to measure the planning complexity of a well; also called planning complexity index. The planning complexity index is a single value that represents the complexity of planning the well. Development of simple method(s) to measure the drilling complexity of a well; also called drilling complexity index. The drilling complexity index is a single value that represents the complexity for drilling the well. Testing and calibrating of both numbers for different well types (exploration, appraisal and development) in various project phases and countries and comparison of the results. Comparison of Wintershall well complexity to other publicly available complexity indices and verification of the validity via an independent outside contractor. Using Wintershall well complexity tool to compare wells independently of the trajectory, type, geographical location, pressure, geology, etc. Comparing Wintershall Drilling Complexity Index tool to Rushmore's RDI and Dodson's MRI.

Both numbers represent early warning indicators that are often based on limited information. They can be used in the risk management process to identify potential risks and areas of concerns. Human and financial resources can also be allocated accordingly; based on the complexity of the drilling project.
Alternative Drilling Fluid Weighting Agents: A Comprehensive Study on Ilmenite and Hematite
Authors: Tehrani Ahmadi , Cliffe Angelika , Hodder Michael H. , Young Steven , Lee John , Stark James , Seale Suzanne
Published: June 2014

For many years, barite has been the standard weighting agent in the drilling fluid industry. Its high specific gravity has helped produce mud weights in excess of 19 lb/gal. Its hardness has rendered it easily millable to a particle size that reduces settling and minimizes losses on shaker screens and its adequate inertness has enabled it to be used in a wide range of drilling fluids containing different chemical components. Recently, however, dwindling supplies and increased consumption of premium barite have led to significant price increases across the world and a reduction in specific gravity in most commercial grades. This has led to renewed interest in alternative weight materials.

Ilmenite and hematite are two minerals that have been used sporadically in the field. Compared to barite, their higher density impacts both the rheology of the fluids and the settling rate of the weight material. A known issue with these materials is their relatively high hardness, which can give rise to abrasion/erosion in the tubular and surface equipment. Another effect that has not been addressed sufficiently is the magnetic characteristic of these iron oxide-containing minerals which has the potential to affect the operation of direction drilling and some other downhole tools.

There have been many studies on the use of ilmenite and hematite as weight agents for drilling fluids. These have dealt with the above issues individually or in a scattered manner. In this paper, we report the results of a comprehensive laboratory study on the application of ilmenite and hematite as weight materials for both water- and oil-based drilling fluids. The study includes the effects of different size grades of the materials on rheology and fluid loss, as well as dynamic and static sag.

The paper will present relative abrasiveness of the materials compared to barite as measured by two different methods, and recommend size grades that can minimize the abrasion effects. The paper will also report the results of magnetic property measurements which impact operation of several downhole tools, and compares these with that of barite and several other minerals. To complete the comparative testing of these minerals, the results of heavy metal analysis will also be reported for each test mineral.
New Generation of High Strength Sour Service Drill Pipe: A Breakthrough Innovation to Address Ultradeep and Extended-Reach Drilling Challenges Combined with H2S Environments
Authors: Rodrigues Ricardo , Flores Vincent , Godeke Kenneth , Thomazic Aurelie , Thebault Florian
Published: June 2014

"Sour Service" refers to a well environment containing Hydrogen Sulfide (H2S), which is naturally associated with acid conditions. It is well known that H2S is hazardous to human health, living organisms, and more generally to the environment. It is for this reason that wells found with Sour Gas were often carefully plugged and abandoned in the past. H2S can also lead to catastrophic brittle failure of drillstring components: the physical phenomenon associated with Sour Service Environments and affecting steel based products under applied or residual stress is known as H2S embrittlement or more specifically as Sulfide Stress Cracking (SSC).

With the increasing demand of gas worldwide, some highly sour oil and gas reservoirs are being explored, mainly in Russia, the Middle East, China and North America, and are now more and more associated with complex well profiles – such as deep reservoirs or extended reach wells. The use of high strength drill pipe is essential to achieve such drilling objectives; however it does represents significant technical challenges in terms of drill pipe integrity and operational safety with the current high strength grades available on the market, such as S-135 drill pipe. Because higher strength is generally detrimental to Sulfide Stress Cracking, innovative chemistries and new heat treatment processes are needed to push Sour Service material limits even further.

A new high strength drill pipe family has been developed to specifically address those challenges: these new grades exhibit a minimum Yield Strength (120 ksi) higher than the current Sour Service grades available on the market as described by the current industry standards (95ksi or 105 ksi Specified Minimum Yield Strength). In order to guarantee the SSC resistance of these high strength materials, pipes and tool joints are tested as per the NACE standards. A first string of this high strength material is already being commercialized and used for the first time in offshore wells in the North Sea.
Predicting the Pressure Capacity of Rotary-Shouldered Connections
Authors: Pettit Grant , Lee Kang , Gokhale Samit
Published: June 2014

API rotary-shouldered drill stem connections have a seal surface that is required to carry internal pressure. We assume that this seal will hold the pressure from routine drilling operations, but drill stem tests, stuck pipe, or other special situations can apply much higher differential pressures to the drill string. Currently, there is no analytical solution for predicting the pressure that can be safely contained by one of these industry-standard connections.

This leads to extra cost and logistical difficulties in those instances where significant pressures are expected. Some proprietary connections are designed for this high-pressure service, but these may be unnecessary if the API connection can safely tolerate those pressure loads. Without an accurate predictive equation, however, relying upon the pressure capacity of an API connection injects uncertainty and risk into the drilling process.

This paper addresses that problem by developing a predictive pressure-capacity equation for rotary-shouldered connections.

To cover a broad spectrum of rotary-shouldered connections with the predictive equation, Finite Element Analysis (FEA) was used to model six different connection types with varying dimensions and tensile loads applied. Over 70 distinct models were created to fully describe the effects of internal pressure on a rotary-shouldered connection.

Patterns in those results were associated with physical stress and strain effects to create an analytical equation that accurately describes the stress state at the seal surface under various pressure loads. It is this equation that predicts the pressure capacity of an API rotary-shouldered connection.

In order to put this equation into use, laboratory testing is recommended to both confirm the FEA results and define an actual failure criterion (that is, at what seal stress the connection begins to leak). Possible paths forward are discussed, along with important considerations for obtaining meaningful test data.
Case Histories of Real Time Drilling Optimization Combining Drill String Modeling, Surface Measurements and Down-Hole Measurements
Authors: Frenzel Mark , Wassell Mark , Brown Craig
Published: June 2014

A novel, real time drilling optimization system is shown to improve drilling performance by increasing the rate of penetration (ROP) while extending the length of the bit run. Additionally the optimization system reduces the wear and tear on the drill string realizing additional cost savings by minimizing down-hole equipment failures. The result is lower total cost to drill the well.

The optimization system's new features include combining surface data with down-hole vibration data to get the available results in realtime. Additionally, the method uses mechanical specific energy to determine the drillability through stringers and fractures. While the average mechanical specific energy maybe minimized for a given set of surface parameters, the mechanical specific energy spikes whenever stringers, fractures or any other changes in the formation are encountered. The optimization program combines all of these features to determine the optimal parameter set points.

To date, seven wells have been drilled utilizing this optimization system. Significant cost reductions are achieved whenever the optimization recommendations are followed. The system combines analytical drill string modeling with real time drilling data. The real time drilling data includes surface data from the rig EDR system and down hole MWD data. The optimization system analyzes the data and then determines the optimized drilling set points based on the rate of penetration, mechanical specific energy, down hole vibration and data scatter. The system has the ability to identify and resolve drilling dysfunctions in real time, mitigating damage and avoiding unplanned trips.

In the planning stage, drill string modeling analyzes the proposed drill string to assess the structural integrity of the BHA, predicts the drilling tendencies to ensure the planned BHA is capable of developing the directional plan and identifies critical drilling speeds associated with excitation of the motor, bit and or drill string RPM. The modeling application also analyzes the drill string for torque and drag, stick slip and the planned hydraulics. During the drilling process the model is continuously updated accounting for differences from plan. The system optimizes drilling performance in real time and offers solutions for mitigating drilling dysfunctions that could result in unplanned trips if not addressed in a timely manner.

Several examples are discussed in depth, which illustrate the efficacy and benefits of this new drilling optimization system.
Reliable Technology for Drilling Operations in a High-Pressure/High-Temperature Environment
Authors: Ahmad I. , Akimov O. , Bond P. , Cairns P. , Eide N. , Gregg T. , Heimes T. , Nwosu A. , Wiese F.
Published: June 2014

The development of oil and gas assets is becoming more complex with reserves being found in more challenging environments. Wells are being drilled to greater depths and in areas where the temperature gradient is higher leading to the requirement for downhole equipment to withstand temperatures in excess of 302°F (150°C) and pressures in excess of 30,000 psi. Directional wells require measurement while drilling (MWD) and drilling systems that operate reliably in the challenging environments. The problem of high pressure is solved using seals to isolate the inner equipment from the wellbore fluid, protecting it from variations in material properties and geometrical dimensions. The greater challenge to electronic components is in the high-temperature environment. Conventional electronic components are generally rated to 158°F, 185°F and 257°F (70°C, 85°C and 125°C), respectively, which is far below the rating required to build a high-temperature MWD and rotary steerable system (RSS). New techniques were required in the design of MWD and RSS tools for high-temperature wells. The paper describes the development of high-temperature drilling equipment that can be used in environments up to 350°F (175°C) and at pressures of 30,000 psi.

The authors utilize case histories to demonstrate how the system provides a performance change in the challenging environment.
Advanced Geomechanical Analysis of Wellbore Strengthening for Depleted Reservoir Drilling Applications
Authors: Shahri Mojtaba P. , Oar Trevor , Safari Reza , Karimi Moji , Mutlu Uno
Published: June 2014

Drilling depleted reservoirs is often encountered with a host of problems leading to increase in cost and non-productive time. One of these faced by drillers is lost circulation of drilling fluids which can lead to bigger issues such as differential sticking and well control events. Field applications show that wellbore strengthening effectively helps reduce mud loss volume by increasing the safe mud weight window. Wellbore strengthening applications are usually designed based on induced fracture characteristics (i.e., fracture length, fracture width and plug location within fracture). In general, these fracture characteristics depend on several parameters, e.g., in-situ stress magnitude, in-situ stress anisotropy, mechanical properties, rock texture, wellbore geometry, mud weight, wellbore trajectory, pore pressure, natural fractures, formation anisotropy and among others. Analytical models available in the literature oversimplify fracture initiation and propagation process with assumptions such as: isotropic stress field, no near wellbore stress perturbation effects, vertical or horizontal wells only (no deviation/inclination), constant fracture length and constant pressure within the fracture. For more accurate predictions, different numerical methods, i.e., finite element, boundary element, etc., have been utilized to determine fracture width distribution. However these calculations can be computationally costly or hard to implement in near real time. The aim of this study is to provide a fast running, semi-analytical workflow to accurately predict fracture width distribution and fracture re-initiation pressure (FRIP). The algorithm and workflow can account for near wellbore stress perturbations, far field stress anisotropy, and wellbore inclination/deviation. The semi-analytical algorithm is based on singular integral formulation of stress field and solved using Gauss-Chebyshev polynomials. Proposed model is computationally efficient and accurate. The model also provides a comprehensive perspective on the formation strengthening scenarios; a tool for improved LCM design and how they are applicable during drilling operation (in particular through depleted zones). Sensitivity analysis included in this paper quantifies the effect of different rock property, in-situ stress field/anisotropy and wellbore geometry/deviation on the fracture width distribution and FRIP. Additionally, the case study presented in this paper demonstrates the applicability of the proposed workflow in the field.
Development of On-Line Sensors for Automated Measurement of Drilling Fluid Properties
Authors: Magalhães Sérgio , Scheid Cláudia , Calçada Luís Américo , Folsta Maurício , Martins André Leibsohn , Marques de Sá Carlos Henrique
Published: June 2014

The high costs associated with drilling operations, especially in offshore environments, make it necessary to optimize each step of the job. The drilling mud plays a critical role in the drilling operation, as it is responsible for several functions (solids transport, wellbore mechanical stability, signal sensor transmission, etc.). Besides that, the attention given to the control of drilling mud properties has not changed much from the last 50 years. Downhole and surface online measurements for several drilling parameters are available for anticipated diagnostics of operational problems. Drilling automation is already a reality (automated pipe handling, controlled tripping operations, etc.), but the drilling mud properties continues to be measured manually. The drilling mud sample has to be collected, transported, treated and analyzed to only then the measured property is reported.

This work aims to present the development and result of experiments performed at a large scale drilling fluid loop, aiming the evaluation of commercial and built in property sensors. The following properties were determined: rheological parameters, mud weight, water-oil content, emulsion electrical stability (for oil based muds), fluid conductivity (for water based muds) and particle size distribution.

The use of neural networks (Multi-Layer Perceptron type) allows the connection of the on-line equipment results to increase the reliability of mud properties determination. Comparisons with the results obtained from laboratory equipment were performed to train the neural networks as well validate the developed techniques.
The Latest Generation of Steerable Motor Overcomes Drilling Challenges in the Niobrara Shale Unconventional Play
Authors: Azizov Azar , Lemesany Lane , Augustine Norwood , Loesel Chad
Published: June 2014

Maximizing well productivity and improving drilling efficiency remains a major challenge while drilling horizontal wells in US-land unconventional shale plays in the last few years. Reducing drilling times and eliminating trips for the curve bottomhole assembly (BHA) requires a motor that can be rotated at high RPM in the vertical section while still achieving buildup rate (BUR) in the curve.

The challenges of horizontal well drilling in US land led to the recent introduction of a steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. These ODMs achieved higher BUR in the curves than the conventional motors at lower adjustable kick-off (AKO) sub angle.

Although the planned dogleg severities (DLS) stayed at the similar level, drilling vertical and curve sections of the horizontal wells in the Niobrara shale unconventional play posed additional challenges:

– Rotating the BHA in the vertical section with a high AKO angle – Dealing with formation challenges – Holding the toolface to achieve consistent BUR in the curve – Completing the vertical and curve sections in one run

The introduction in 2013 of the latest-generation steerable motors (LGSM) with further reduced short BTB distance design helped the operator overcome these challenges. The new system significantly improved drilling performance with excellent directional control.

This paper will discuss the design, testing and results of horizontal wells drilled using the LGSM in the Niobrara unconventional shale play.
Improving Drilling Operations Efficiency on an Ultra-Narrow Margin HPHT MPD Well with use of a Mud Cap
Authors: Oyovwevotu Joy , Low Eric , Nas Steve
Published: June 2014

As the industry pushes the boundary of technology to drill narrow margin wells, combining safe drilling practices with drilling efficiency is becoming ever more challenging. The practice of drilling with Managed Pressure Drilling (MPD) using statically underbalanced mud weight is gaining increasing acceptance in High Pressure High Temperature (HPHT) well construction. This paper describes the planning and execution of using mud cap fluid in the drilling of an ultra-narrow margin (0.50ppg window at the planning stage) HPHT well from a Jack Up rig.

Drilling Equivalent Circulating Density (ECD) with overbalanced mud weight at acceptable flow rate would have exceeded the formation fracture gradient and resulted in a loss of well integrity. To avoid this outcome, the HPHT section of the well was drilled with statically underbalanced mud weight. Displacing well to kill weight fluid at acceptable flow rates prior to any trip out of hole was not viable. Planning focused on how to maximise operational efficiency by using a cap fluid to trip in and out of hole without compromising open hole integrity and well safety.

In this paper, we discuss the design of the mud cap fluid, selection of Changeover Depth (CoD), risks associated with use of the cap fluid, determination of available window for mud cap placement and removal, planning and execution of mud cap placement and removal, challenges of running and displacing the cap fluid with a liner and, lessons learnt from repeated use of the technique throughout the well construction phase, including coring and wireline logging under MPD conditions.

Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well which would otherwise have been near impossible to drill with minimum lost time.
Measuring and Improving Land Rig Moves Using Hard Data
Authors: Dunham Thad , Elsik Wayne , Shah Mihir
Published: June 2014

As the shale revolution continues to boom, the industry is facing ever-growing pressure to increase overall efficiency when it comes to drilling operations and rig moves. This paper addresses improvements in pad-to-pad rig moves. The industry is using several different rig moving procedures, but there is a need to determine how each can be improved. Relevant data is in high demand from many players within the land rig market.

Observation and analysis of twelve different rig moves in the study yielded noteworthy data. By utilizing techniques primarily from other industries, the different "steps" of a rig move were quantified. Documentation of the entire rig move process included rig down and rig up sequences, equipment utilization, pad site layouts, as well as potential design improvements.

Through collaboration with a drilling contractor, the results of the study were converted into actual improvements. The improvements both design and process related, saved money and increased the number of wells drilled per year. Studying the entire process of moving a rig resulted in faster, cheaper, and more efficient rig moves. Contractors, operators, and oilfield suppliers throughout the industry can realize the benefits of efficient moves.
Relief Well Drilling Using Surface Seismic While Drilling (SSWD)
Authors: Evensen Kristoffer , Sangesland Sigbjørn , Johansen Ståle Emil , Raknes Espen Birger , Arntsen Børge
Published: June 2014

Magnetic survey methods are used to locate the blowing wellbore when drilling a relief well. If no magnetic material is present in the openhole section of the blowing well, the last set casing shoe is the deepest possible intersection point. A deeper intersection point will increase the hydrostatic head, increase the frictional pressure drop and allow a lower density kill fluid to be used.

A new potential method called surface seismic while drilling (SSWD), could make it possible to intersect the blowing well below the casing shoe. This method is not dependent of any casing or steel tubular present in the well to identify the relative wellbore positions. The SSWD method is based on a surface seismic source generator and a receiver array located on the seabed. Preliminary simulations indicate that it is possible to locate the wellpaths of the two wells on the seismic data. This method will allow real-time seismic monitoring of the well paths without interfering with the drilling operation. This can allow for more precise relative wellbore positioning.

To investigate the benefits of a deeper intersection, a simulation model was prepared. A vertical offshore well consisting of 2000 meters of casing, and a 1000-meter openhole section were used. The well was killed dynamically by circulating seawater at high rates into the blowing wellbore. Compared to a casing shoe intersection, simulations show that a bottom hole intersection would reduce the flow rate and pump pressure by approximately 48% and 55%, respectively. The required kill mud weight was reduced by 24 %.

The seismic method may also be used in conventional well killing operation to provide additional information of the position of the two wellbores and potentially reduce the time needed to drill the relief well. This paper presents the SSWD method and the potential improvements in relief well drilling and well killing.
Innovative Non-Planar Face PDC Cutters Demonstrate 21% Drilling Efficiency Improvement in Interbedded Shales and Sand
Authors: DiGiovanni Anthony , Stockey David , Fuselier Danielle , Gavia David , Zolnowsky Matt , Philips Russell , Ridgway Derek
Published: June 2014

Traditional polycrystalline diamond cutter (PDC) technology has made tremendous gains over the past decade with corresponding footage and rate of penetration (ROP) improvements in drilling performance. The remaining challenge is managing interbedded formations with competent stringers while maintaining drilling efficiency and the highest ROP potential, such as those present in the 6 to 6⅛-in. Pinedale Anticline production hole and the 12¼-in. Cana intermediate section. By modifying the standard planar PDC cutter face geometry with novel shallow recessed features, a demonstrated improvement in drilling efficiency was observed in these applications and an increase in attained footage. Extensive analysis in Pinedale runs indicated this cutter design benefits a lower mechanical specific energy (MSE) in the shale and sand, shorter day curves, and higher average ROP per unit of motor horsepower. Initial runs in the Tonkawa sands of the Cana intermediate have started to show similar trends.

The successful field runs have been supported by in-depth analysis and study of cutting efficiency including, single-point cutter testing in a pressurized vessel, atmospheric vertical turret lathe testing, and full-scale PDC bit laboratory testing in a state-of-the-art downhole drilling simulator. The results of this work improved the understanding of the thermo-mechanical behavior of cuttings formed by the drilling action of a PDC cutter in these applications. This study is part of an innovative approach to manage rock cuttings, cutting efficiency, and thermal loads as it applies to PDC durability in state-of-the-art drill bit designs.

The design changes have improved cutting efficiency and aggressivity, which has improved the ROP of bits in abrasive sand and in the shale sections. This paper provides documentation and visual demonstrations of the features and benefits seen in the single-point test apparatus, the downhole simulator in the laboratory and in the field with case studies compared to offsets of standard bits with planar PDC cutters.
Finite Element Studies of Wellbore Strengthening
Authors: Arlanoglu C. , Feng Y. , Podnos E. , Becker E. , Gray K. E.
Published: June 2014

In drilling deep horizons, the mud weight window between pore pressure gradient and fracture gradient often narrows due to rock properties and underground stress state. Non-productive time (NPT) events such as lost circulation, wellbore instability, kicks, underground cross-flow, and pipe sticking are more likely. Such problems greatly increase drilling costs. Plugging preexisting natural fractures or drilling-induced fractures with lost circulation materials (LCM) is often used to increase fracture gradient and widen the mud weight window. This technique, called ‘wellbore strengthening’, includes several strengthening methods, but there are several factors affecting these procedures are not thoroughly understood.

To reduce the risk of loss circulation while drilling in formations with narrow mud weight windows such as pressure depleted reservoirs and deep-water formations, a good understanding of the mechanisms of wellbore strengthening in different down-hole scenarios helps engineers to optimize the design of drilling fluids and operation procedures.

This paper discusses the mechanism of wellbore strengthening in elastic and pore-elastic models, utilizing the finite element method to evaluate wellbore and near-wellbore stresses during fracture initiation and propagation, and after plugging fractures with LCM. Factors affecting fracture behavior such as formation stress anisotropy, LCM bridging location, initial pore pressure, and fluid leak-off are investigated. A better understanding of the several interacting events local to the wellbore and near-wellbore regions can result in improved operational practices related to lost circulation events.
Drilling Riser Conductor Monitoring: A Practical Approach for Operational Integrity Verification
Authors: Diestler Jeff , Park Mike , Das Samik
Published: June 2014

With an increase in the number of drilling operations in harsh environments and ultra deepwater, combined with the limited availability of drilling rigs and qualified personnel, it is increasingly important to maximize safety and operability while minimizing structural damage to the riser, wellhead and conductor system. Great efforts to improve drilling equipment, safety features and overall structural integrity of drilling riser systems have occurred in recent years. Subsequently, trends have shifted the focus of integrity concerns from the drilling riser onto the wellhead and conductor system. The integrity of the wellhead and conductor system is of utmost importance – as it provides a vital barrier to contain hydrocarbons and drilling mud inside of the drilling system. A structural breach of this system could have catastrophic consequences and must be avoided at all cost.

Significant challenges remain in accurately predicting and tracking actual fatigue damage on wellhead and conductor systems. This papers details the findings of several monitoring campaigns designed to track the actual vibration of the BOP and LMRP stack due to riser VIV, and its contribution to wellhead and conductor strength and fatigue concerns. The measurements have been used to provide operational guidance, validate design tools and thus provide a more realistic fatigue and strength data set for wellhead and conductor systems.

The paper will discuss the monitoring application including state of the art sensor systems with practical attachment systems that can be retrofit installed via ROV or diver. Furthermore, is discusses data processing methodologies and software with the aim to provide operational guidance to the drilling team (while providing uninterrupted continuation of drilling operations). Furthermore, detailed engineering studies are presented that correlate conductor fatigue as a function of drilling riser VIV and stack excitation. Two case studies illustrate the application of these technologies.

Through research findings and field application, this paper summarizes the operational benefits of an integrity monitoring systems for the wellhead and conductor system from an operator perspective. The target is to increase the understanding of Drilling Riser VIV and its effect on the wellhead and conductor systems. This provides assurance to the operator that the system has not been compromised during a specific drilling campaign and that any risk and uncertainties have been captured and has been evaluated.
In-Situ Analysis of the Microscopic Thermal Fracture Behavior of PDC Cutters using Environmental Scanning Electron Microscope
Authors: Zhan Guodong (David) , Patin Alexander , Pillai Raju , Gilleylen Russell , Castagna Marc
Published: June 2014

While significant advancements have been made in the field of Polycrystalline Diamond Compact (PDC) cutter technology over the years, understanding of the thermal fracturing behavior of these cutters is still limited. Traditionally, analysis of thermal fracturing was conducted by heating the cutter to the fracture point in normal atmospheric or vacuum/inert conditions, and then allowing it to cool down and polishing it for easy observation prior to microscopic analysis. This method limits findings, as the environmental conditions do not accurately reflect those experienced downhole, and this process does not allow for an in-depth understanding of the precise fracturing behavior of the cutter.

To gain a more in depth understanding of thermal fracturing behavior and its causes, a specialized environment was prepared that allowed in-situ observations of fracturing behavior in simulated drilling conditions. This included equipping a Scanning Electron Microscope (SEM) with a heating-stage furnace accessory to allow for real-time observations and filling the chamber with a simulated atmosphere consistent with downhole conditions. Cutter cross-sections were selected and polished using new methods to ensure maximum clarity and then heated to fracturing temperatures, with the SEM recording all changes as they occurred.

The observed thermal fracturing behavior, analysis of the microstructure degradation and EDS chemical analysis led to some valuable insights into cutter failure mechanisms. In the unleached areas of the cutters, fracturing began at significantly higher temperatures than expected, while the cobalt binder compound began melting at lower temperatures than commonly accepted. In addition, fracturing behavior was not universal, but began with a few major cracks appearing in the PDC structure, from which a network of smaller cracks progressed outwards through the cutter. With deep leached cutters, microcracking appeared in the diamond grains rather than intergranular fracturing, degrading the integrity of the cutter and indicating that graphitization, not fracturing, is the primary thermal failure mechanism of these cutters.

The data from these tests provides valuable insights into how PDC cutter and deep leach technology can be effectively used in the field. Due to the lower melting point of the cobalt binder compound, the temperatures used in manufacturing can be adjusted to ensure maximum cutter stability. In addition, these tests demonstrate a greater-than-expected wear resistance for deep leach cutters and a higher fracturing or degradation temperature of both unleached and deep leached cutters, meaning that they are suitable for a wider range of applications.
Innovative Dual-Diameter PDC Bit Design Provides Unique Solution to Successful Drilling of Challenging Volcanic Interval
Authors: Teasdale Paul , John Gareth , Davis Ron , Baudouin Nicolas
Published: June 2014

Drilling hard, abrasive volcanic rock has presented significant technical challenges to bit manufacturers over the years, creating a dilemma for operators designing a strategy to efficiently drill difficult volcanic intervals.

This paper will focus on the development of a unique concentric two-stage, dual-diameter PDC bit coupled with a low-speed, high-torque motor, providing an alternative solution for drilling a challenging section featuring a hard volcanic layer for a major international operator in a remote location West of Shetland.

The paper reviews the design concepts of the bit that allows an initial smaller pilot hole to be drilled, relieving the stress of the surrounding rock. The larger reamer section subsequently enlarges the hole to the desired diameter through stress-relieved rock, thus requiring less energy to remove a comparative volume of rock. The unique design concept was tested in an in-house pressurized drilling laboratory with basalt samples of varying compressive strengths to evaluate its performance in these challenging rock types. Alternate bit designs with a variety of cutter geometries and cutter layouts were also evaluated and an optimum design was selected for the field test to deliver lower vibrations and increased ROP.

A strategy was formulated to drill the interval in a single run with the optimal dual diameter PDC bit and a low-speed, high-torque mud motor. Downhole dynamics data recorders were placed in the BHA to capture downhole dynamic activity to evaluate performance and provide information to help further optimize performance through the interval.

On the subject well, the new dual-diameter PDC design successfully drilled the entire 12 ¼-in hole section in a single run, including 67 m of volcanics. The design achieved a record ROP for the section, saving five days of drilling time and resulting in significant cost savings for the operator.

In addition to providing measurable stability and drilling efficiency benefits in conventional applications, the unique concentric dual-diameter PDC bit also provides a technical solution to operators looking at more cost-effective means of drilling these challenging formations in a high-cost drilling environment.