bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Stochastic Model for an Active over Passive Motion Compensator for Offshore Drilling Operations
Authors: Barr A. M. 
Published: March 2015

Abstract
Active over passive motion compensators provide critical position and load control for offshore drilling operations. The larger size, high cost, and complex multiphysics of the equipment and system create significant challenges to evaluate machine performance. Empirical testing of the equipment quickly becomes cost prohibitive. This paper presents a numerical and stochastic model, which may be used to evaluate the system design, optimize the equipment setup, and predict the response of the equipment, which is useful for quantitative risk analysis. The one-dimensional multi-degree of freedom model utilizes a system of non-linear differentials equations that describe the time dependent kinematic, hydraulic, pneumatic, and electrical control aspects of the active over passive motion compensator. The equations may be solved using Runge-Kutta or Adams-Bashforth-Moulton methods. A Weibull analysis of the results reduces the time series data into a set of two coefficients, which describe the characteristic value and data spread of the probability density function. Comparison of the coefficients across different equipment designs, setups, and environments reveals valuable performance information. Knowledge of the machine performance as a function of input parameters leads to better equipment designs, optimal component setup, reduced commissioning times, forecasting of system response, and more efficient operations.
Implementation of Managed Pressure Casing Drilling and Managed Pressure Cementing Techniques in Unconventional Reservoirs
Authors: Balanza Jose Antonio , Justiniano Luis Carlos , Poletzky Isabel 
Published: March 2015

Abstract
Fields located in the southeastern area of the Neuquén Province of Argentina are widely recognized for their high formation pressures and related influxes while drilling the production section. Some of the challenges encountered when drilling using conventional techniques include kicks, losses, wellbore instability, and formation damage. They are also known for challenging cementing operations. These wellbore construction challenges can significantly impact non-productive time (NPT).
Managed pressure cementing (MPC) has been implemented for recent wells after the target is achieved with managed pressure casing drilling (MPCD). This application enables the implementation of controlled bottomhole pressure (BHP) while cementing, without killing the well. Surface backpressure (SBP) is applied in accordance with the cementing pumping schedule, taking into account varying pump flow rates and fluid densities.
In wells in which MPC was implemented, SBP was continuously applied to maintain the target equivalent circulating density (ECD) required for the cementing operation, avoiding expansion and gas migration. This paper describes the implementation, results, and behavior of the well while performing MPC.
MPCD and MPC techniques have proven to be an effective combination to help optimize drilling time, improve bottomhole conditions, and reduce cementing costs. This paper includes lessons learned and recommendations to help enhance the implementation of these techniques and optimize the overall well construction phase to improve the performance of future wells.
Dynamic Soft String Model and Its Practical Application
Authors: Miska S.Z. , Zamanipour Z. , Merlo A. , Porche M.N. 
Published: March 2015

Abstract
It is well accepted that torque and drag calculations are essential for well construction applications. To the authors' knowledge, the calculations are performed based on the concepts of the soft string model. This approach enables the wellbore designer to determine torque and other forces in the drillstring. While several modifications of the soft string model have been proposed and implemented in commercial software, the model mainly used in the oil and gas drilling industry is the static soft string model. As such, not only the string bending stiffness is neglected, but also it is assumed that the string is motionless and the direction of motion changes by merely changing the sign of friction coefficient. Clearly, there is a strong need for including acceleration effects in the soft string model to permit analysis of tripping operations and more accurate evaluation of the drillstring loading and consequently, the rig equipment (hoisting system, etc.).
In this paper, an improved dynamic soft string model is proposed that accounts for drillstring motion in 2D and 3D wellbores. This mathematical model explains how to compute forces along a moving drillstring or casing. The aims of this model are: 1) to analyze dynamic drillstring behavior, 2) to estimate local contact forces, and 3) to predict the effect of different tripping velocity profiles on axial and lateral contact forces. A system of equations for drillstring translational motion is solved using numerical methods. A computer code has been developed for practical design calculations.
The improved dynamic soft string model can be used to determine surface load and contact force as functions of time and measured depth. This model is also applied to predict surface load and contact forces in tripping operations. In particular, the model is implemented for drillpipe in two different 2D wellbores: horizontal and S-shaped, and a 3D wellbore while tripping in and out of the hole. As expected, the surface load vs. time plot shows a similar trend of tripping accelerations. Depending on the well path shape, drillstring properties, tripping acceleration, and velocity profile, the maximum dynamic loads can be in the range of 4-40% higher compared to the conventional soft string model. In addition, results for two different tripping velocity profiles (trapezoidal and parabolic) are compared. The maximum surface load is up to 4% higher with trapezoidal velocity profile which is not significant, because both velocity profiles provide 90 ft displacement. It is noted that the governing parameter for the maximum load needed is the maximum tripping acceleration, not the maximum velocity.
Improved dynamic soft string model will have significant impact on well path shape, drillstring design, drillpipe failure analysis, tripping operations optimization, and automatic control of the drawworks.
PDC Shearing Cap Technology Protects Cutters When Drilling Out Casing Bits for Increased ROP and Bit Life in the Next Hole Section
Authors: King William W. , Leon Cesar , Rumbos Teodoro , Schader Kevin W. , Cano Jose Vicente , Chevre Henri 
Published: March 2015

Abstract
Casing drilling technology uses a specially designed casing drill bit that is attached to a traditional casing string. The technology is typically applied when hole problems such as severe formation swelling or caving cannot be controlled with drilling mud or by rig operations, making it extremely difficult to reach the planned casing setting depth. In these applications, the casing and bit are set and cemented. To drill the next section of the wellbore, the casing drill bit, as well as the float equipment, must be drilled out.
In PDC bit applications this is typically done in two ways – using a roller cone bit for the drill out, followed by a new PDC bit for the next interval; or by using a single new PDC bit and BHA to drill out the cemented casing bit and continue drilling the next interval. Each method presents inherent inefficiencies in the drilling operation. With the first, additional drilling and trip time are required to run the two bits. The second method using a single new bit has the potential to damage the PDC cutters while drilling out the casing bit such that performance is limited in the next formation interval. The cutter damage is heightened when using a bent motor assembly. This degraded cutter condition negatively affects bit durability and performance, resulting in slower rates of penetration, shorter runs, and pulling the bit before completing the intended interval.
Milling cap technology has been developed for the single-bit method that provides a shearing action during the casing bit drill out process while protecting the primary PDC face cutters. It preserves the cutters in virtually pristine condition so that performance is optimized when drilling the formation. The shearing cap technology allows flexibility in selecting the best performing bit for the interval below the casing, and it increases the opportunity to use a bent motor assembly when drill string rotation is required during the drill out.
This paper discusses the development of the shearing cap technology and examines the two initial field tests in South America and West Africa. In the first use of the technology, drilling on a well in Colombia, an 8 ¾-in. PDC drill-out bit with shearing caps completed the drill out portion of the run in less than 15 minutes. The bit then drilled the next 4,900 foot formation interval to the next casing point with an ROP 5% higher than the field average. The bit showed no signs of reduced ROP after the drill out and came out of the hole in good condition with a dull grade of 1-2-CT-G-X-I-BT-BHA. In West Africa, a 12 ¼-in. PDC bit with shearing caps produced the best performance in the field, reducing casing bit drill out time by 44% and improving ROP in the formation by 50% compared to offsets.
Real Time Data Monitoring Experience Results in Enhanced Safety and Efficiency
Authors: Harder C. , Sutler J. , Sawaryn S. , Hale N.W. 
Published: March 2015

Abstract
This paper is about BP's experience with Collaborative Real-time Environments (CoRE) including the Houston Monitoring Center (HMC), which has resulted in enhanced safety, rig site monitoring and its associated planning, and improved operational efficiencies. Real Time Monitoring Centers have been utilized by industry for some years to improve operational efficiency in drilling processes. BP (operator) has explored extending the effectiveness of such centers by embedding them in a CoRE. In its Gulf of Mexico operations area, this operator has been rigorously applying real-time data monitoring technologies on critical operations with the intent to enhance both safety and operational efficiency through more informed operational decision making. The results of this focused operation will be described in this paper.
The term CoRE is used to describe the physical atmosphere and office arrangement of integrated teams, both operations and subsurface, sophisticated data monitoring applications and communications tools from the office to the rig site. Remotely monitoring key rig site data using highly trained and skilled personnel in a newly designed environment called a CoRE, has resulted in improvements in procedural discipline, efficacy in human factors as they relate to drilling and completion operations, and significantly improved operational decision making. These processes are underpinned by highly resilient systems and meticulous planning, delivering an uptime greater than 99.5%. To improve resilience of the system, the ability to transfer monitoring operations to an alternative location within a short time has been demonstrated repeatedly. This paper will describe the principles and demonstrated results from the CoRE philosophy.
An additional benefit of having key data streaming onshore is regulatory compliance verification by the operations team, which also would allow external review by a regulator. This enhances the compliance verification significantly and allows additional items to be verified or inspected in less time and with less impact on the field operations. The potential benefits to both internal and external stakeholders including regulatory personnel are also described in this paper.
The paper will detail the operator's journey on real time data monitoring of drilling operations which has been utilized by the company for several years. Included is a description of the numerous benefits resulting from applying advanced technologies in real-time monitoring (RTM) to the area of operational decision making including being aligned to potential future industry guidelines or standards. This paper describes the management practices which can be used to foster confidence between geographically separated team members because acceptance by field operations personnel is key to the success of any remote monitoring activity. Finally, the overarching management approach which has contributed to the success of this integrated effort is described by this paper.
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

Abstract
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 (&lt;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 &lt;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) &lt;100m producing interval and (3) &gt;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

Abstract
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

Abstract
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

Abstract
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.