bluuebunny/crossref_metadata_2025 huggingface dataset:
Chemical Sand Consolidation - Developing a Strategic Capability Across a Wide Portfolio
Authors: Aytkhozhina Dana , Mason David , Marulanda Raul , Orekha Bukola , Villesca Josue , Beaumont Paul
Published: March 2015

Mechanical sand control completions are often used to optimise hydrocarbon production from weak formations. In a few wells this primary sand control method has sub-optimal performance. There is substantial value in remediating some of these wells, but developing this capability is not a quick and simple task.

Recompleting a well could be feasible, but is often cost prohibitive. Mechanical solutions could be applied to stem sand production if the sand producing interval is known; however, in some cases chemical sand consolidation is the most effective approach. Chemical sand consolidation works by pumping chemicals downhole to strengthen the formation and stop sanding. In most cases reported in the industry, chemical consolidation has been used in short production intervals (<100m).

Our approach was to develop a laboratory programme to test various industry chemicals and to achieve a good understanding of how these can be applied. Candidate wells were matched to chemicals to identify which systems (may be more than one) would be the best fit. The strategy was to initially trial the technology in low-rate onshore wells (typically <1 mmscf/d), before moving progressively to more challenging wells (up to 2,500 bopd). The wells were split into 3 groups based on their complexity: (1) proppant flow back remediation, (2) <100m producing interval and (3) >100m intervals. Each has unique challenges, but this approach facilitated a progressive learning curve.

In proppant flow back remediation 7 field applications were conducted with 100% success rate. Longer intervals were successfully treated over time. Matrix consolidation presented a bigger challenge - 10 field trials have been carried out with a mix of successes and failures. A key learning is that adequate placement of the chemicals is critical. Chemical sand consolidation would fulfil its potential only when the chemicals can be reliably delivered to the target sand-producing zone – (often unknown), and remain static to allow sufficient curing time. Some treatments have been bullheaded (i.e pumped down the production tubing); others have been placed with coiled tubing.

Operator has successfully developed an organisational capability whereby this technology can be part of the toolkit and - where appropriate - can be applied with a reasonably high chance of success to add value. Wells have been treated in the Lower 48 states in the USA, Canada, Alaska, Azerbaijan and Egypt and other wells are constantly being evaluated. Well types include oil and gas producers, onshore and offshore, with reservoir temperatures from 29 °C to 135°C. This technology is therefore being used across a wide well portfolio.
A Guide to Relief Well Trajectory Design using Multidisciplinary Collaborative Well Planning Technology
Authors: Goobie Roger B. , Allen William T. , Lasley Barbara M. , Corser Kent , Perez Jose Patino
Published: March 2015

Existing rules for relief well planning in the Gulf of Mexico (GoM) have been revised. The US government now requires operators to submit relief well trajectories to obtain a deepwater drilling permit, and BP requires that at least two relief well locations be verified and available for use. Based on industry standard well placement procedures, this paper sets forth good practices and key parameters that should not be overlooked during the design process.

While the complexity and challenge of meeting global energy demands continue to increase and more stringent regulatory requirements must be met to acquire a permit to drill, understanding how to effectively plan a relief well is becoming a required skill for drilling engineers involved in the well planning process.

Historically, few operators created formal relief well plans before an actual blowout occurred. In addition, proprietary tools and older techniques made relief well planning appear unnecessarily complex to some operators.

To meet the new regulatory requirements, many oil and gas companies are looking for ways to produce reliable relief well plans without generating intercept plans for every casing section.

In the GoM, BP has been working to make the relief well planning process more transparent, efficient, and consistent through (1) a systematic, repeatable relief well planning methodology that establishes a standard range of boundary conditions and (2) a specialized set of engineering tools that enable teams across the organization to generate similar results.

A relief well provides a means to intercept and kill a blowout well when a surface intervention or capping procedure requires an extended period of time or as a contingency in the event of unsuccessful intervention or capping operations. Drilling a relief well presents many technical challenges to assure that the blowout well is intersected in the correct position and that the fluid pumping operations are effective.

This paper presents five phases of relief well design: data gathering, drilling, locating, tracking, and intercepting. It also discusses the development and pilot testing of a new software application specifically designed to integrate these five phases into a collaborative, multidisciplinary environment, reducing cycle time and providing a systematic approach to relief well designs.
Drilling Mud Cooler Opens Up New Automated Drilling Markets in Hot Hole Applications
Authors: El Dorry K. , Coit A. , Gutierrez C. Garza , Woolums J. , Herrington D.
Published: March 2015

Drilling automation depends on delivery of high-speed downhole dynamics data to control surface machinery. The two principal surface machine parameters controlled by high-speed downhole data are top drive rotary speed and the tripping speed of drawworks. The high-speed downhole dynamics data is delivered to surface via complex downhole dynamics electronics packages with sensors that measure vibration, loads, temperature, and pressure. As the bottomhole temperature rises above the functional thresholds of these downhole electronics packages, the life and performance of the downhole tools and sensors deteriorate, making it uneconomical to perform closed-loop control that depends on the high-speed data.

A breakthrough in land rig mud cooling technology now allows for much lower, safer downhole temperature gradients for the safe use of the necessary downhole dynamics tools to fully automate the drilling process. The closed-loop mud cooler was used on a series of wells in South Texas with advanced drilling automation tools to compare the results of drilling speed, efficiency, and downhole tool operational safety with the mud cooler either activated or deactivated.

During the tests, the frequency of downhole tool failures diminished from two temperature-related failures per well to zero tool failures, which in turn reduced the need for bit trips and expedited the overall drilling rate. The operator drilled the well in three days fewer than the previous well.

The high-speed downhole dynamics measurement tool that controls the automated driller at surface usually has a maximum battery life of 250 hours. When the mud cooler was used, the downhole dynamics tool was able to achieve 96% of its capacity (240 out of 250 hours) for the first time in an environment where downhole temperatures exceeded 250°F. The previous maximum tool life achieved was only 167 hours (67% of the total battery capacity); meaning run length capability was increased by 44%. Even if downhole dynamics data is transmitted to the surface at a rate insufficient for automated surface machine control, the slower data will still allow the driller to make better performance drilling decisions. The mud cooler allows for a reduction in temperature of up to 45°F (at surface) and 21°F at bottom hole in a single pass for flow rates up to 550 gallons per minute during the summer time.

This paper focuses on performance data and charts for the overall operations on multiple wells drilled as part of a drilling automation case study in a hot-hole application in South Texas (Eagle Ford Shale). A basic breakdown of the mud cooler technology will also be included, as well as installation, operation, and maintenance best practices for optimal performance.
Simulated Pressure Drop When Circulating Fluids Past Liner Hanger Equipment In An Annular Configuration: Computational Fluid Dynamics (CFD) Studies And Experimental Validation
Authors: Gomes Paulo J. , Murray Mark , Dondale Aaron
Published: March 2015

Simulation tools have been developed to predict the equivalent circulating density (ECD) induced in the wellbore annulus during cementing operations. However, little has been done to predict the velocity and pressure fields around complex geometries, such as liner hangers. This paper demonstrates the use of Computational Fluid Dynamics (CFD) to better identify opportunities for modifying the geometrical design of downhole tools to reduce pressure drop and improving the estimations of the annular pressure drop across this equipment.

In order to estimate pressure drop across complex annular sections, engineers typically use an equivalent geometry of concentric pipes for the length of interest. CFD is an iterative numeric method that calculates the flow and pressure fields for a fluid confined within a region of interest. This region, identified normally as a volume, is further divided in smaller elements where the continuity and conservation equations are solved and it is limited by boundary conditions which are mathematical restrictions that impose a final physical solution. The CFD results were validated experimentally at scale.

The equivalent geometry of concentric pipes approach can under estimate the pressure drop and resulting ECD because it assumes a fully developed laminar flow regime and overlooks the energy dissipation induced by changing the fluid flow patterns, expansions and contractions. When placing cement slurries in a well annulus, there is often a very “narrow window” of operation due to the ECD that is induced during cementing operations approaching the fracture pressure gradient in the annulus. In this work, CFD was used to evaluate the pressure drop across a liner hanger system for several typical operation flow rates: 1bbl/min up to 5bbl/min. The overall pressure drop across the liner hanger section ranged from ~80 psi to ~550 psi, respectively. Simple geometric changes were then tested using CFD resulting in up to 40% pressure drop decrease across the tool, for those flow rates.

The existing simulation tools' ability to accurately estimate the equivalent circulating density (ECD) is challenged when complex geometries such as liner hangers are used. CFD proved to be a powerful tool to gain insight into flow fields and pressure maps developed on complex annular geometry systems.
An Holistic Approach to Improving Drilling Performance in Realtime: Integrating Measured, Analysed, Modelled and Reported Drilling Data
Authors: Kucs Richard , Thonhauser Gerhard , Regan Matt , Hanson John , Haugen Jonny , Gundersen Odd Erik
Published: March 2015

The concept of enterprise level and standardised realtime data management solutions supporting drilling operations is rapidly gaining considerable recognition with dynamic and technology-comfortable Operators. Whether delivered physically in an Operations Centre or virtually via web browser, the business drivers are clear – when presented in an ergonomic fashion, the full suite of realtime drilling and geology data enables timely, informed and collaborative decision-making, leading to performance improvement and reduction in operational, and therefore financial, risk.

However, there remains a common disconnect between: (i) primary measured and processed real-time data, (ii) unstructured data in the form of analytical results, and (iii) tertiary metadata from reports. Typically these three tiers of data, and the companies providing them, are isolated from each other. Once operations commence, dataflow may occur in one direction with realtime data feeding into analytics and reporting tools, accompanied by substantial subjective human input. This paper discusses how a major European independent Operator, with a diverse range of global assets and associated challenges, has worked with its various data solution providers to develop and implement a fully bidirectional ‘data highway’ in which realtime, analysed and reported data are seamlessly and efficiently exchanged.

This holistic approach to data-driven operations support delivers a combined value far greater than the sum of the individual applications, as the various proprietary systems enhance and complement each other. Non-productive time (NPT), as well as Invisible Lost Time (ILT) analysis, is fed back into realtime monitoring, reported comments are tied to realtime curves, planned and modeled drilling optimisation recommendations are displayed and correlated alongside live drilling data. Carefully mapped dataflows drive workflows which in turn drive sophisticated deliverables that improve standard operating practices, and hence best practice. The result is improved drilling key performance indicators (KPIs) leading to performance improvement, risk mitigation and cost efficiency: All at an enterprise level and all in realtime.
Pioneer Turbodrilling With 16 ½” Impregnated Bit in Deep Pre-Salt Well in Santos Basin
Authors: Pantoja R. , Britto G. , Buzzá J. , Vieira A. M. , Laroca F. , Appelshaeuser G.
Published: March 2015

Following the major pre-salt reservoirs discovery in Santos Basin by Petrobras in 2006, a large number of exploratory and development wells have been drilled in the area. More recently, some of those wells have been drilled in large wellbore configurations, mostly due to deeper pre-salt layers and geological uncertainties. This paper presents a case study on drilling a deep 16 ½″ vertical section at a deepwater location, where a turbine and an impregnated bit were used because of an extremely tough drilling scenario. This specific run achieved TD at more than 5000m, marking the first record ever of successfully running an impregnated bit of this size offshore.

The basic well design data is shown, as well as the drilling program and offset well and other 16 ½″ bit records. The challenges that were found on drilling deep post-salt 16 ½″ sections in other locations and on the previous BHA runs with PDC bits on this section are highlighted and analyzed with drilling parameters. The impregnated bit specifications and the turbine characteristics are outlined taking operational recommendations into account. Available power at the bit was taken into consideration and the concern with its impact on drilling performance is explained through a comparison with other bit diameters which are widely used.

The bit records, drilling parameters and UCS analysis of the section made clear that the turbine with impregnated bit was the most appropriate and effective drilling system for the scenario at the end of the section. A drilling time and cost comparison with other deep hard-formation-16 ½″ sections drilled in other locations shows that the use of this system may yield significant reduction in the total cost by shortening the overall rig time, making it the preferred option in some future challenging drilling projects.

Lastly, further turbodrilling and impregnated bit improvements are suggested, theoretically analyzed and justified considering drilling performance maximization and drilling tools and rig equipment limitations.
Breakthrough Advance in MPD Automation: A New System Manages Narrower Drilling Window with Reduced Equipment and Crew
Authors: Couturier Y. , Hansen J. , Prent F. , Thow P.
Published: March 2015

The wellbore pressure drilling window for Managed Pressure Drilling (MPD) operations is limited by the proven capabilities of the MPD system to operate within the window for both planned operations and contingency situations. The existing automated annular pressure control system integrates choke control with a real-time hydraulics model and automated auxiliary pump to best manage all states during drilling. However, opportunities to improve performance and reduce equipment footprint and system complexity have presented themselves. With this in mind, based on the strengths of the existing system, an initiative was launched aimed toward a progressive evolution of the system. This paper discusses the development of this improved system with subsequent field trials and the extensive acceptance testing procedures.

At the heart of the evolution was a new choke controller and a change to the valve used to control the choke speed and direction. The new control methodology provides quicker, more precise system control, translating into enhanced pressure control independent of drilling states. Additionally, the control lends itself to quicker calibration, saving substantial rig time.

In the first phase, connection making was developed and tested on a flow loop, followed by a full scale test facility. During phase one field trials, risk was managed by upgrading only one leg of the MPD system before the phase two upgrades were tested. Once phase two developments concluded the system was acceptance tested at a full scale test well against a comprehensive set of test scenarios aimed to validate well integrity amid drilling system failures such as power loss, pump failure and fluid blockages.

This evolution has demonstrated its capabilities in more than two hundred pressure events on actual wells. The system has shown itself to be stable in changing well conditions, requires minimal tuning and retuning, and has reduced the complexity of the system for the control system technician. The system has been validated against downhole tool data to be capable of maintaining bottom hole pressure to within +/- 36 psi (+/- 2.5 bar) in normal operating conditions and within +/- 72 psi (+/- 5 bar) in contingency situations, while minimizing the need for an auxiliary pump.
Frac Plug Drill Out Benefits from Hybrid Roller Cone Bit Design
Authors: Rose Karl , Nobile Kyle , Rodriguez Victor , Rose Randy
Published: March 2015

Improving frac plug drill out in multi-zone completions is an important step in enhancing the development of unconventional assets. The key challenges are efficiency and durability in drilling the diverse materials that make up the 15 to 40 plugs in a typical completion, and addressing the resulting pressure spikes and exposure to high-hydrocarbon fluids that can reduce bit life.

Field observations identified trends in the frac plug bit dull modes, which resulted in a study of operating practices and analysis of what was being drilled. It was found that standard frac plugs have an outer component made of hardened steel, ceramic or other metal, and an inner component of softer composites and rubber. The outer sleeve can damage the bit, while the softer inner component result in large cuttings that are difficult to circulate out of the hole. The process also identified pressure spikes and high hydrocarbon exposure that raised bearing reliability issues.

Reviews with rig personnel, completions engineers, and plug manufacturers were conducted. A series of various bit designs were then run to identify how to best match the cutting structure of the bit with the plug to be drilled.

This review and design process resulted in a patent-pending hybrid roller cone bit with an outer cutting structure of tungsten carbide inserts from a 517 IADC bit, and an inner cutting structure from a 236 IADC steel tooth bit. The tungsten carbide inserts provide a much tougher cutting structure while the steel tooth cutting structure reduces the composite and rubber components to a smaller, more easily circulated cutting size.

This paper examines the review and design process, and presents field results that include the first presentation of a 57-well study conducted in the Eagle Ford shale play in south Texas, where the hybrid bit drilled frac plugs 13.6% faster than standard tooth bits and averaged 3.3 more plugs per use. The authors examine materials and manufacturing contributions, and the role of design software and simulations in optimizing durability and penetration rates. The paper includes operator perspectives on the technology's development and application.
Application of Uncemented Solid Expandable Liner for Combined Openhole Isolation and Casing Repair
Authors: Park M. , Teasdale P. , Cowling M.
Published: March 2015

Well engineers are often presented with a number of potential solutions to drilling challenges as they develop a plan to safely and efficiently execute the drilling program to meet the overall well objectives. The solutions will be evaluated and the option that presents the lowest risk while providing the maximum benefit is normally selected as the preferred solution.

The scope of this paper is to review the challenges faced by a North Sea Operator after identifying the likely presence of high pressure gas stringers in a carbonate formation on a recent brown-field data-gathering well, and the subsequent deployment of solid expandable technology to provide a safe and effective solution. Solid expandable tubulars have demonstrated value as a reliable alternative solution to conventional liners in providing zonal isolation of troublesome formations while maximising drill-through inside diameter (ID). The improved technology and increased reliability in the systems has provided greater confidence that the systems can be deployed successfully with an acceptable level of risk.

The Operator required the isolation of a high pressure gas-bearing zone located below the 9-5/8″ casing shoe to enable the safe drilling and logging of the reservoir section. The use of conventional liners was evaluated but discounted due to the reduction in internal diameter that would prevent subsequent logging and running of the planned liner in the reservoir section. Deepening the 9-5/8″ shoe to cover the high pressure stringers presented higher risks associated with drilling into the anticipated depleted reservoir. After evaluation of the various options, solid expandable technology was selected as the best option to meet the well objectives.

A 7-5/8″ 29.7 lb/ft solid expandable liner system was successfully installed to isolate the high pressure gas stringers located below the 9-5/8″ shoe. The system included an expandable liner hanger set in open hole to provide zonal isolation in place of cement. In addition, the liner lap was extended back into the 9-5/8″ casing to isolate a leaking stage tool. The application of both repairing a casing leak and isolating a high pressure open hole zone using an uncemented liner was a first for the Operator. This allowed the Operator to drill the reservoir section with a lower mud weight while minimizing the risk of differential sticking and losses, the logging program to be conducted as desired and the 5-1/2″ fibreglass liner to be installed as planned. The safe and successful drilling of the well, coupled with the capture of desired information met the Operator's well objectives, adding value to future field development.

While this was the first solid expandable installation in this size for the Operator in the area, their confidence in the technology from previous installations allowed them to adapt the system to provide the required open hole zonal isolation whilst also reinstating integrity to the 9-5/8″ casing.
High Speed, Continuous Single Well Magnetic Ranging
Authors: Hanak F. Chad , Estes Robert
Published: March 2015

Passive magnetic ranging (PMR) is a technique used to determine the range and direction to a cased well that may not be accessible during the drilling of an adjacent well. It has been used since the 1970s (wireline) in relief wells and anti-collision applications where dual-well active ranging techniques cannot be used [Grace, Robinson and Vogiatzis, 1972, Morris et al., 1978]. PMR in MWD tools is a nascent business, and encountered some early resistance [Towle and Van Steenwyk, 1999]. It requires very accurate magnetometer measurements, preferably corrected in-situ for residual bias errors, a large number of static surveys, and manual interpretation of the data. All of this has made PMR a slow process, and thus it has not been widely adopted in markets such as the steam-assisted gravity drainage (SAGD) market in Canada, where speed is essential.

A new PMR technique is outlined in the paper that achieves speed and accuracy comparable to dual-well active ranging techniques. It uses existing MWD magnetometer hardware, but does not require an excessive number of surveys or pre-magnetization of the casing in the offset well. Using Kalman filtering techniques adapted from aerospace navigation algorithms, the single-well technique provides continuous ranging output while enabling nearly uninterrupted drilling [Gelb, 1974].

The paper includes a discussion of the theoretical underpinnings of the technique and detailed field test results. The ranging algorithm was shown to be robust in above-ground testing, consistently converging in the presence of gross initial position uncertainty. A vertical test well drilled using the new ranging system demonstrated successful ranging over a wide span of well-to-well distances. The MWD ranging estimate showed good agreement with a pair of gyro surveys (test well and cased-target well) performed after tests conclusion.

MWD tools with PMR can be broadly applied to enhance accuracy, speed, and safety in markets for SAGD, anti-collision and relief well drilling.
Conical Diamond Element Bit Sets New Performance Benchmarks Drilling Extremely Hard Carbonate/Chert Formations, Perm Region Russia
Authors: German Vyacheslav , Pak Mikhail , Azar Michael , Bits Smith
Published: March 2015

Developing reserves in the northern portion of Russia's Perm region frequently requires the operator to drill extremely hard carbonates which contain high concentrations of problematic chert inclusions. Drilling the chert with PDC bits has been challenging and in many cases impossible due to the cutters' inability to withstand high impact forces which resulted in severe cutter damage. Both rotary and motor BHAs have been utilized in an attempt to mitigate shock and vibration.

Rollercone TCI bits are a viable option but slow ROP and short runs combined with high total bit revolutions caused numerous trips for tool change out. It was evident that PDC's shearing action was the most efficient rock failure mechanism and had the greatest potential to drill extended meters at higher ROP compared to a roller cone's crushing action. The operator required a new type PDC bit that could efficiently drill long intervals of carbonate/chert formation at high ROP and a cutting structure that would remain intact when encountering the chert intervals.

To develop a durable bit solution, engineers used an FEA-based modeling system to implement an innovative hybrid-type bit by strategically positioning multiple conical diamond elements (CDE) and conventional PDC cutters across the entire cutting structure from bit center to gauge. This new-style cutting structure leverages the CDE's aggressive shape and superior impact and wear resistance to create a high-efficiency plowing/shearing action that improves performance in difficult formations. The analysis indicated the new hybrid bit would improve performance and be capable of surviving shock and vibration while drilling the hard carbonate/chert formations.

The hybrid CDE bit was tested and compared against two direct offsets in Russia's North Perm Unvinskoe field. Unvinskoe field was selected for the case study because the formations and application challenges are similar to several other northern Perm fields. The first well was drilled entirely with roller cones which required 10 runs delivering average meterage of 149/bit at an average ROP of 6.05 m/hr. The second well required three roller cones and three 913-standard type PDC bits delivering average meterage of 213.4/bit at an average ROP of 9.65 m/hr. The third well was drilled with one roller cone, one standard PDC with averages of 336m at 8.2 m/hr and two hybrid CDE bits with averages of 433m at 15.6 m/hr. Performance improvement for the CDE bit runs versus offsets runs in wells were: 1) Well-1 190% more meters, 157% faster ROP; 2) Well-2 103% more meters, 62% faster ROP; 3) Well-3 29% more meters, 90% faster ROP.
Reducing Well Delivery CostsThrough Practical Experience Gained Implementing an Integrated Drillship Design and Automation of Drilling Equipment
Authors: Adams Ed , Wijning Dieter
Published: March 2015

Ultra-deepwater well construction presents very unique technical and economic challenges to deepwater operators worldwide. Wells are now being planned and drilled in water depths up to 12,000 ft and total depths beyond 30,000 ft. The technical complexity of these wells requires enabling rig technologies to get the wells drilled safely and competently. Moreover, their extended well delivery times and associated economic impact forces operators to explore new ways to control unit development costs and Returns on Capital Employed (See Slide 2). Key to achieving such cost control is improving rig efficiency and focusing on flat time reduction.

Practical experience gained through continuous development (see Slide 3) created an integrated drillship design and a new approach on how to automate, not mechanize, the drilling equipment on mobile offshore drilling units. Combined, these principles can significantly reduce flat times and, thereby, reduce well delivery costs.
A Barrier Analysis Approach to Well Control Techniques
Authors: Fraser D. , Moore D. , Staak M. Vander
Published: March 2015

Drilling fluid is one of the most dynamic and critical barriers used during the drilling process. The fluid barrier must be properly monitored and maintained at all times to be reliable as a barrier. The objective of this paper is to apply the risk-based technique of barrier analysis while utilizing key performance indicators (KPIs) in order to aid in the comparison and evaluation of well control techniques. In a barrier analysis, the fluid pressure barrier is sustained as long as the fluid pressure lies between the pore pressure and the fracture gradient of the formation. This is the critical function of the barrier. A success path is a systematic listing of the steps required to maintain the critical function of the barrier. When the development of these safety functions and success paths are combined with variances and the kick performance indicators (the Kick Detection Volume [KDV] and the Kick Response Time [KRT]) proposed in a recent paper*, the power of the approach begins to emerge. For well control, this analysis demonstrates that a combination of techniques commonly used in managed pressure drilling (MPD) can significantly reduce risk. While there are a variety of MPD techniques available, this paper focuses on the constant bottomhole pressure [CBHP] method from a floating rig as an example that illustrates a number of techniques that can be used for both subsea and surface BOP stacks, offshore as well as on land. Closing in the fluid system provides high resolution fluid pressure measurement and control along with the ability to directly measure a.) In-situ fracture gradients, and b.) Pore pressures at key places in the wellbore, without completely halting the drilling operation. By manipulating Surface Back Pressure (SBP) to hold downhole pressures relatively constant, the swab and surge effects in the wellbore can be minimized, providing even greater assurance that the critical function will be maintained. This directly eliminates or reduces the reason kicks occur during connections and while tripping out of the hole. Since these are the most common times when kicks occur*, we suggest that the overall number of kicks taken while drilling could be cut by as much as half. Measured vs. calculated input flow is also demonstrated to be beneficial for reducing risk since it reduces the likelihood of drilling fluid density error and provides for a more complete understanding of what is in the well bore at any given time. Plus it reduces the KRT by increasing confidence in detecting flow differentials to the point that action may be taken immediately. Finally, we make the observation that the barrier analysis technique used is not specific to drilling, but is an approach that can be applied in other areas to compare technologies and risk and to identify processes that can be used to mitigate process safety issues.
CFS v. MPD- Revolutionary Technology to Outshine Industry Leader?
Authors: Cunningham Justin R. , Ozegovic Alek , Grayson Brian M. , Salvo-Shook Constance
Published: March 2015

As the industry-wide adoption of managed pressure drilling (MPD) continues, the recent emergence of reliable continuous flow systems (CFS) are right on its heels, offering many parallels in wellbore pressure control and protection. The question then presents itself—does continuous flow outperform conventional MPD? Will the industry's adoption of CFS lead to the ultimate obsolescence of the current offerings, or will both coexist? This paper will examine the pros and cons of each system and their respective abilities to mitigate hazards and optimize drilling efficiency.

Conventional MPD systems utilize a rotating control device (RCD) and a choke manifold system to create a closed loop circulation system and achieve precise control of a wellbore's pressure profile during drilling and completion. CFS also works to achieve greater control of wellbore pressure through continuous circulation of drilling fluids. A large percentage of all drilling hazards related to wellbore pressure occur when mud pumps are cycled off and on during connections, which causes fluctuations in equivalent circulation densities (ECD) and downhole pressure spikes.

This paper examines and compares two state-of-the-art technologies for enhanced pressure control and drilling efficiency; CFS and choke-based MPD systems. The conclusions will highlight the directions of the two techniques and determine if they will coexist or will forever compete in the industry to be the most widely-adopted choice.
Spiraled Boreholes: An Expression of 3D Directional Instability of Drilling Systems
Authors: Marck Julien , Detournay Emmanuel
Published: March 2015

The occurrence of borehole spiraling is predicted by analyzing the delay differential equations that govern the propagation of a borehole. These evolution equations for borehole inclination and azimuth are obtained by considering the following three model components: (i) a bit/rock interaction law that relates the force and moment acting on the bit to its penetration into the rock; (ii) kinematic relationships that describe the local borehole geometry from the bit penetration; and (iii) a beam model for the bottom-hole assembly (BHA) that can be used to express the force and moment at the bit from the external loads applied on the BHA and the geometrical constraints arising from the stabilizers conforming to the borehole geometry.

The analytical nature of borehole propagation equations makes it possible to conduct a stability analysis in terms of a key dimensionless group that controls the directional stability of the drilling system. This group depends on the downhole weight on bit (WOB), on properties of the BHA, on the bluntness of the bit, and on parameters characterizing its response. The directional stability of a particular drilling system can be assessed by comparing the magnitude of this group with a critical value that depends only on the BHA configuration and on the bit walk. If this dimensionless group, which depends on the actual drilling conditions, is less than the bifurcation value, the system is deemed to be directionally unstable, and borehole spiraling is likely. Stability curves for an ideal BHA with two stabilizers are shown to depend on the bit walk. An application to a field example is discussed. Borehole simulations, based on solving the equations of propagation, also are presented to illustrate that, for unstable systems, the model reproduces spiraled boreholes with a pitch, comparable to what is observed in the field.
Overcoming Barriers to Adoption of Drilling Automation: Moving Towards Automated Well Manufacturing
Authors: Ambrus Adrian , Pournazari Parham , Ashok Pradeepkumar , Shor Roman , van Oort Eric
Published: March 2015

There has been a growing interest in automated drilling in the recent decade, motivated primarily by increased well construction efficiency, enhanced safety and well quality requirements. Many drilling tasks have been successfully automated and pilot technologies have been deployed, but broader adoption has remained slow. This can be attributed to some key factors. First, no two wells or rigs are the same. So the concept of “developing one algorithm applicable to all scenarios” is difficult except in the simplest of cases where only a limited set of tightly integrated sensors and actuators are involved. Secondly, full automation requires cohesive data and information integration between multiple stakeholders: the operator, the service provider, the drilling contractor and the equipment manufacturer. No efficient mathematical construct has been adopted for integrating data / information from these different stakeholders. Thirdly, any drilling automation task requires the full buy-in of the drilling crew, which is often difficult when these algorithms are presented as black-box solutions and it is unclear how to bring the rig to a safe condition when automation fails.

A mathematical construct, and the methodology / architecture is presented that would enable one to combine information and data from multiple sources in a meaningful way and the rapid development of intuitive control algorithms that can be easily understood without advanced degrees or training is demonstrated. The algorithm development process is purposefully simplified, allowing for well engineers to easily develop their own control strategies while enabling rig- and site-specific customization. Additionally, the visual nature of the methodology enables easy monitoring by the rig crew for troubleshooting purposes. Automation scenarios are presented for tripping and Managed Pressure Drilling operations that demonstrate the ease of use. Multiple control strategies are developed for each task, and compared against criteria that include easy comprehension of the algorithm and optimality. This automation approach can help reduce some of the current barriers to broad scale adoption of automation.
Expert Real-Time Drilling Performance Prevents Twist-offs and Reduces Bit Damage in the Permian Basin
Authors: Hood James , Taylor Richard , Morris Paul , Riley Brian , Plouzek Damian , Wilson John , Metz Mike , Alam Rashid
Published: March 2015

Sudden growth of the Permian's Delaware Basin, exploiting multiple unconventional targets, has increased the number of drilling rigs in the area to well over 550. This rapid expansion of drilling rigs has diluted the pool of experienced drillers and operators in the region, which in turn has caused numerous drilling optimization problems such as poor penetration rates and accelerated wear on drillstring components. To enhance the learning curve and address these drilling practices, a number of operators have requested real-time downhole dynamics and mechanics information to improve drilling performance.

Previously, a dedicated ‘down-hole drilling dynamics service’ was successfully deployed to the Permian for recording the down-hole drilling dynamics environment in memory mode. This service confirmed strong dynamic events occurring, and subsequently allowed adjustments to be made to the drill string components and operational parameters. However, the memory only approach meant a delayed improvement cycle, never reaching its full optimization potential or technical capabilities.

Providing a ‘real-time down-hole drilling dynamics service’ delivered immediate improvements to performance through real-time drilling parameter adjustments, as well as enabling optimum bit and bottom hole assembly selection for subsequent wells. The continuous performance improvement loop highlighted the best drilling practices, permitting the development and implementation of refined drilling procedures, and further enhanced performance and safety.

This paper addresses drilling dynamics challenges encountered and overcame while drilling vertical sections in six wells (on four rigs) by one operator in the Permian Basin. The data and examples presented in this paper provide an understanding of the benefits of managing drilling parameters in real-time and express the best drilling practices. Using a ‘real-time down-hole drilling dynamics service’ reduced overall operator costs by an average of 24% per well when compared to previous wells. Additionally, real-time down-hole weight on bit functionality offered an increased safety feature over a conventional drilling system, while the use of close-to-bit rotational inclination provided enhanced vertical control versus the standard survey system of a conventional straight-hole drilling assembly.
Seasonal Fluctuation of Soil Carbon Dioxide Emission in Differently Managed Pastures
Authors: Brito Liziane F. , Azenha Mariana V. , Janusckiewicz Estella R. , Cardoso Abmael S. , Morgado Eliane S. , Malheiros Euclides B. , La Scala Newton , Reis Ricardo A. , Ruggieri Ana Cláudia
Published: March 2015

Soil carbon dioxide emission (ECO2) is a process determined by biotic and abiotic factors influenced by land use and management practices. In grassland ecosystems, grazing intensity may affect C input from plants into soil, and thus may also change soil respiration rate. Indeed, limited information is available regarding the effects of grazing management on ECO2. This study was conducted to evaluate ECO2 seasonal variation, and its relationship to soil temperature (Tsoil) and precipitation, in an area with different pasture heights of Marandu palisade grass [Brachiaria brizantha (A.Rich.) Stapf.]. The pasture heights (15, 25, and 35 cm) were distributed in a completely randomized design with 12 repetitions in each area. The evaluations of ECO2 and Tsoil occurred from January 2011 to February 2013, totaling 73 d of observation that were distributed according to climatic seasons. The results showed that seasonal variation of ECO2 was directly related to variations in precipitation and Tsoil. Soil CO2 emission was higher in summer and lower in winter. The data variability of ECO2 was higher in rainy, hot summers than in dry, cold winters. A positive linear association between ECO2 and Tsoil was observed in summer and autumn. In most seasons measured, ECO2 reduced with increasing pasture height. Accordingly, 2‐yr data indicated that accumulated ECO2 decreased with increasing pasture height. Thus to better understand the effect of pasture height on ECO2, a shorter period of measurements is not suitable since a different result was observed in the first year of evaluation.
Resistance of ‘Zhongmai 155’ Wheat to Powdery Mildew: Effectiveness and Detection of the Resistance Gene
Authors: Sun Huigai , Song Wei , Sun Yanling , Chen Xinmin , Liu Jianjun , Zou Jingwei , Wang Xiaoming , Zhou Yinfu , Lin Xiaohu , Li Hongjie
Published: March 2015

Powdery mildew, caused by the biotrophic parasitic fungusBlumeria graminisf. sp.tritici(Bgt), is a prevalent disease in many wheat (Triticum aestivumL.)–producing regions throughout the world. To reduce yield losses and avoid environmental pollution caused by fungicide application, growing resistant cultivars is the preferred means for managing wheat powdery mildew. ‘Zhongmai 155’, a commercial winter wheat cultivar released in 2012, was resistant to 92 of the 115Bgtisolates originating from northern China. Using segregating F2and F2:3populations derived from Zhongmai 155 × ‘Han 4564’ cross, genetic analysis indicated that a single dominant resistance gene, tentatively designatedPmZ155, was responsible for the resistance of Zhongmai 155 to theBgtisolate E09. The gene was subsequently localized on chromosome 5DS on the basis of the results of molecular marker analysis. The flanking markersSCAR203 and Xcfd8are linked to genePmZ155at genetic distances of 0.3 and 4.9 cM, respectively, and were physically mapped to the deletion bin 5DS‐1‐0‐0.63; therefore,PmZ155is located in this region of chromosome 5DS and shares the same molecular markers asPm2. However, Zhongmai 155 differed from Ulka/8*Cc (CI 14118), which carries genePm2on chromosome 5DS, in its reactions to 26 of 111 commonly tested isolates, of which 18 isolates were avirulent on Zhongmai 155 but virulent on Ulka/8*Cc, while 8 isolates were virulent on Zhongmai 155 but avirulent on Ulka/8*Cc. Zhongmai 155 also differed from ‘Tabasco’ (carryingPm48on chromosome 5DS) in its reaction to 14 of 62 isolates. On the basis of its chromosome position, close linkage to the molecular markersXcfd8andSCAR203, but different responses to an array ofBgtisolates, it appears thatPmZ155is most likely an allele of locusPm2.
Genetic and Heterosis Analyses using Hayman's Six‐Generation Model for Grain Yield and Yield Components in Maize
Authors: Chen H.M. , Zhang Y.D. , Jiang F.Y. , Huang Y.X. , Yao W.H. , Chen X.H. , Kang M.S. , Fan X.M.
Published: March 2015

This study aimed to (i) estimate additive (a), dominance (d), aa, ad, and dd genetic variances and effects; (ii) investigate the differences for five genetic variances or effects among crosses between a maize (Zea mays L.) line from the Suwan‐1 heterotic group and five inbred lines from other groups; and (iii) develop a theory to explain the results from Hayman's model and low‐, mid‐, and high‐parent heterosis. Hayman's model was used to evaluate the genetic effects in five six‐generation sets between the Suwan‐1 cross with five lines from other groups. The magnitude of variance was consistent among all crosses for grain yield (GY) and ear length (EL) but different for ear diameter (ED), row number per ear (RE), kernel number per row (KR), and 100‐kernel weight (KW). The a, d, aa, ad, and dd effects were similar for EL among crosses between lines from different groups, indicating that the effects for EL could be used to differentiate Reid and non‐Reid heterotic groups. We postulated a ‘linked coexpressed genes’ (LCG) model to (i) explain why a, d, aa, ad, and dd variances and effects might be different when a common line is crossed with other lines and (ii) serve as an improved model explaining heterosis. The LCG model explains what dominance–overdominance theories can explain and explains what dominance–overdominance models do not. For example, it can explain why an inbred line cannot perform like a hybrid and why an F2 population for a quantitative trait has a normal distribution.