bluuebunny/crossref_metadata_2025 huggingface dataset:
First Time Drilling With Steerable Drilling Liner from Semi-Submersible
Authors: Noordoven Q. , Grindhaug G. , Eidem M. , Spreckelmeyer N.
Published: March 2015

Using Steerable Drilling Liner to drill through an unstable formation has been a proven solution from fixed installations where this technology greatly increases the chance of successfully drilling a wellbore and landing a liner at planned depth. The key to the increased performance are the reduced open hole time, mechanical impact on formation and pressure fluctuation in the well.

In previous subsea wells on the Vigdis field on the Norwegian Continental Shelf, stability problems have led to setting the liner prematurely, resulting in loss of production. The stability problems seen in the offset wells have been time dependant, with few difficulties experienced during drilling. However, when running the liner afterwards, pack-offs, shallow setting of liners and problems with cementing have occurred.

The Steerable Drilling Liner solution was selected to prevent initiation of instability while drilling the reservoir and in addition to ensure the section could be secured with the liner in place before formation instability problems occur.

The implementation of the Steerable Drilling Liner enabled drilling of a nearly horizontal section with several unstable palaeosol intervals without any stability related problems, hence meeting the objective of reaching a challenging target. It has been concluded that the section would have been difficult to drill with conventional methods.

In contrast to previous Steerable Drilling Liner utilization, this well was drilled from a semi-submersible rig in rough weather conditions. These harsh conditions in the North Sea demanded high attention with respect to drilling practices and well control which had to be addressed accordingly.

In the following, the planning and execution phase, leading up to the successful drilling operation from a floating installation will be described. The paper will also touch upon some improvements for further use of the Steerable Drilling Liner technology.
Axial Oscillation Tools vs. Lateral Vibration Tools for Friction Reduction – What's the Best Way to Shake the Pipe?
Authors: Gee R. , Hanley C. , Hussain R. , Canuel L. , Martinez J.
Published: March 2015

There are many benefits to reducing friction along the drill string while drilling directional wells. Higher rates of penetration (ROP), improved tool-face control, reduced drag, and reduced stick/slip are only some of the benefits documented in previous technical papers. There are generally two types of downhole tools used to generate benign vibrations within the drill string and/or bottom-hole assembly (BHA) to reduce friction: axial oscillation tools (AOTs) and lateral vibration tools (LVTs).

This paper reviews the benefits and drawbacks of each of these types of tools and presents the results of mathematical modeling and field data to conclude which type of tool is more effective at reducing friction in horizontal wells.

Axial oscillation tools typically employ a valve driven by the mud flow to generate pressure pulses. A shock tool is run above or incorporated into the AOT to convert these pressure pulses into an axial oscillating motion. This motion travels up and down the drill string to reduce friction between the pipe and the borehole wall.

Lateral Vibration Tools (LVTs) typically employ one or more eccentric rotating masses driven by the mud flow. This creates a vibration in the lateral direction, perpendicular to the long axis of the tool, creating motion between the tool and the borehole wall and thereby reducing friction.

To investigate the potential benefits of each type of tool, a mathematical model of a BHA and drill string was created and, using finite element methods, the friction reduction effect (in terms of drag reduction) was compared between the AOT and LVT.

In each scenario evaluated in the study, a benchmark calculation was first made with no oscillation. Then, the oscillation for each tool was applied and the response of the system evaluated with respect to the improvement in weight transfer along the drill string. Afterwards, the results were compared to an actual case study for verification.

The research concludes that axial oscillation tools provide significantly more effective friction reduction, which enhances drilling performance in horizontal wells. The paper also provides several additional examples of comparative field results.
Drilling Performance: Efficient Integration of the Entire Drilling System
Authors: Greenwood Jeremy A.
Published: March 2015

Every basis of design and the required configuration of the rig, drilling equipment, and services undergo a series of iterations to balance requirements and resolve conflicting approaches. Effective design and subsequent optimization of a drilling plan requires the interaction of many different technical specializations in different organizations to meet the overall well objectives. To achieve maximum operational and economic performance, these diverse and specialized disciplines must interact effectively and efficiently in the fewest number of iterations. An essential requirement for this interaction is a clearly defined process that allows everyone involved in design and execution to be aware of both the requirements and objectives for the well and also those of other team members. Most importantly, knowledge of where the connections or touch points exist between the different domains is essential so that the implications of a change to the system can be rapidly assessed by the entire engineering team and service providers to help ensure the overall goals are met. The approach is novel within the industry because of the scope of the workflow, which encompasses all engineering relationships while drilling the well; whereas previous work tended to focus more on optimizing real-time behavior to respond to conditions encountered, using reservoir simulators to plan developments, or has been limited to collaboration between only two or three disciplines (Brett et al. 1986; Adeleye et al. 2004).
Overcoming Complex Geosteering Challenges in the Cardium Reservoir of the Foothills of Canada to Increase Production Using an Instrumented Mud Motor with Near Bit Azimuthal Gamma Ray and Inclination
Authors: Suh Asong , Bradley James , Feltham Greg
Published: March 2015

The Cardium Formation is a conventional sandstone reservoir in the Western Canadian Sedimentary Basin. The Cardium Formation is currently at a phase of exploitation requiring long horizontal penetrations and large-scale, multi-stage, fracture stimulation to ensure productivity. In the Canadian Foothills, the Cardium is complexly deformed and naturally fractured. Correctly placed horizontal wellbores take advantage of these natural fracture systems which create permeability pathways resulting in extremely prolific wells. To maximize production and effective reservoir drainage, horizontal wellbores need to be drilled to intersect multiple natural fracture networks within the deformed Cardium reservoir. Sub-seismic scale folds and faults result in rapid changes in reservoir bedding orientation and/or position which requires sensitive geosteering responsiveness in order to create an optimal reservoir penetration.

The Cardium reservoir exhibits good gamma contrast and predictable character. Therefore, gamma ray has been shown to be an effective tool for geosteering. An innovative instrumented mud motor that provides azimuthal gamma ray and continuous inclination 2.7m from the bit was used for successfully geosteering several wells, and has proven to be a vital component in the horizontal drilling process. For example, a common geological scenario can result in a 5° change in apparent bedding orientation relative to the wellbore resulting in the wellbore exiting the reservoir. Reservoir re-entry can occur as quickly as 30.5m when using the instrumented mud motor compared to 56.4m when using a conventional gamma sensor positioned 15.2m behind the bit. The instrumented mud motor works by wirelessly transmitting the azimuthal gamma ray and continuous inclination measurements via short hop communication to the MWD (Measurement While Drilling) system from where it is transmitted to the surface realtime.

This paper describes the complex Cardium reservoir in the Canadian Foothills and presents the unique challenges faced when attempting to geosteer and optimize wellbore positioning within the reservoir. We review the near bit instrumented mud motor and discuss the workflow of how data was used from the instrumented mud motor to help with geosteering the well. Finally, we compare the results from several wells drilled using the instrumented mud motor to those drilled using a standard MWD gamma located 15.2m behind the motor. The use of the instrumented mud motor with near bit azimuthal gamma ray and continuous inclination proved to be a successful geosteering tool in one of the most complex environments of the Western Canadian Sedimentary Basin. Additional footage in zone and increased production in this complex geological environment displays the tool's capibilities and the benefits it could provide to other areas of the basin.
Recent Advances in Soft Torque Rotary Systems
Authors: Dwars Sicco
Published: March 2015

Many rigs have STRS, the Soft Torque Rotary System, also known in the drilling industry as SoftSpeed, EPST or RevIT. STRS expands the stick-slip free drilling envelope. Weight on bit can go up, RPM can go down. Rate of penetration goes up. Whenever STRS is in use, the frequency of tripping a drill string out and back into the hole reduces. That's because it reduces the likelihood of prematurely worn bits, for twist offs, back offs or for damaged down hole tools. From the vast amount of operational data collected by mandatory 24/7 high speed top drive torque and speed recorders, we learnt that the now mature technology could still be further improved. This paper outlines the Z-Torque approach, a novel SoftTorque controller that expands stick-slip free operating envelopes and greatly simplifies tool operation. Author of this paper is an electronics engineer, approaching the stick-slip challenge from an unusual perspective: aim to cure stick-slip vibrations with the same tools and tricks as traditionally used in high frequency printed circuit board design, in telephone lines, TV antenna coax cables, fiber optics, in seismic, and the likes.
Hydraulic Design of Shale Drill Bit Using an Integrated Numerical and Experimental Approach
Authors: Moslemi Ali A. , Rahmani Reza , Graham Ryan , Ivie Brad
Published: March 2015

Hydraulic design of drill bits for shales is challenging due to the sticky nature of the drilled formation which may cause balling. An integrated numerical and experimental approach was used to tackle this challenge. Computational Fluid Dynamics (CFD) along with a new particle tracking method was used to hydraulically design a fixed cutter drill bit for shales. Following CFD simulations, experimental tests in Pressurized Drilling Lab (PDL) were performed to validate the CFD results.

Spherical particles with diameters ranging from 0.1 mm to 10 mm were injected from cutters surface and their average velocities were calculated when leaving the drill bit using discrete particle modeling (DPM) technique. The ratio of average particle velocity to average annulus fluid velocity at a plane with one bit diameter from bottomhole, referred to as the bit Cuttings Transport Ratio (Ct), was then evaluated to study the hydraulic performance of drill bits under different conditions. Effect of nozzle orientation on drill bit hydraulic was modeled in CFD and then validated in the lab using special adjustable oriented nozzles. Furthermore, effects of nozzle count and blade height as well as flow guide on drill bit hydraulics performance were studied both numerically and experimentally.

Baseline bits with different nozzle orientations were tested in PDL. Rate of Penetration (ROP) increased up to 17% compared to the baseline bit using improved nozzle orientations. Also, it was found that higher nozzle count is helpful for drill bit cleaning improving the drill bit performance. Drill bits with different blade heights were built and tested in PDL and it was found that there is an optimum blade height which can improve the bit drilling performance. Also, the effect of flow guide on drill bit hydraulics was modeled using CFD and particle tracking method and then it was tested in PDL. Both CFD and PDL results indicated drill bit hydraulics improvement when flow guide was added to drill bit. ROP for the bit with flow guide increased 10% and 20% in high and low hydraulic conditions, respectively.

The final shale bit was designed using improved nozzle orientations, proper blade height as well as flow guide. While the final bit balling tendency decreased, the ROP increased about 35% compared to baseline bit in PDL tests indicating the significance of drill bit hydraulics in its drilling performance.
Anti-Collision Considerations for Arctic and Other High Latitude Locations
Authors: Chatar Crispin , Beck Nathan , Simeone Davide , Buchanan Andrew , Borri Luca , Occhionero Lara
Published: March 2015

A significant contribution that some oilfield services companies provide for drilling operators today is directional well planning. A major task in the process is to identify and analyze the risk of wellbore collisions. If there is a risk of collision beyond acceptable limits, risk management must be applied. The first part of this process is to collect data. The second step is to analyze the potential risk. The risk not only involves a financial aspect but also HSE (Health Safety and Environmental), so it is imperative that we make the right decision using the most effective tools. Failure to take the right precautions may result in potentially catastrophic human and environmental implications.

Generally this is already a complicated task. It gets particularly complicated when this is done at high latitudes and in certain wellbore orientations. Much of the industry today still believes that wellbores are represented accurately by surveys. While in the majority of cases this is somewhat true, the uncertainty and probabilistic nature of the measurement is often overlooked or misunderstood. Few people in the industry today actually understand how this translates to anti-collision also known as collision avoidance. Even fewer understand how much effect your latitude can have on this type of calculation.

This paper will address these complications. After a short overview on wellbore placement, the paper will first discuss some theory on what makes high latitude wellbore placement challenging and when is it a relevant consideration. How it relates to collision avoidance will be explained. The current gaps in the industry today will be revealed and options to close those gaps are discussed. Upcoming technologies for reducing risk are reviewed. The second part of the paper will focus on risk management; namely mitigation and prevention. Case studies will be reviewed. Common misconceptions will be eliminated. The paper will attempt to set a foundation of understanding of the fundamental important considerations for anyone involved in collision avoidance in high latitude locations such as the Arctic.
Time Dependent Borehole Stability: Effect of Static vs. Dynamic Mud Weight
Authors: Nes Olav-Magnar , Stenebråten Jørn , Fjær Erling
Published: March 2015

From field experience, even if a borehole is stable while drilling through a shale, it may turn unstable with time when the well is left static for a sufficiently long period of time. This may in some cases be explained by the collapse limit being located somewhere in-between the equivalent circulating density (ECD) and the corresponding static density (ESD) of the mud. In such cases, the combination of formation conditions and properties, and well conditions will determine the timing for possible onset of instability in the vicinity of the borehole wall.

We present a set of highly specialized hollow cylinder (HC) laboratory tests on a field shale core. While subject to a confining stress and an applied pore pressure, the borehole pressure has been systematically varied according to scaled-down field conditions to simulate the effect of ECD vs. ESD at connection on borehole stability. The laboratory results suggest that the mud weight (MW) may be kept below the classic static collapse limit for shorter periods of time, like those occurring at connections, without inducing borehole collapse due to low permeability, plastic nature, and time dependent strength of the shale. The borehole diameter may however gradually decrease due to irreversible plastic deformation induced during each low pressure cycle. When at total depth (TD) and the when well is left static, the ESD may have to be increased to maintain stability, compensating for the loss of ECD.

We illustrate the dynamic stability effect with a North Sea field case where the near horizontal well was stable while drilling, but turned unstable when left static for a period of time after reaching TD. The observations are compared to corresponding modelling of the time dependent stability.

This shows the importance of accounting for the potential time dependence of borehole stability while drilling through shale. The combined effect of ESD, ECD, and timing may determine whether the borehole will be sufficiently stable from an operational point of view, allowing the well to be drilled and completed without excessive problems.
Investigating the Benefits of Induced Vibrations in Unconventional Horizontals via Nonlinear Drill String Dynamics Modeling
Authors: Wilson J.K. , Heisig G.
Published: March 2015

Inducing vibrations while drilling is a relatively new concept that shows promise in directional applications. Instigating motion of the drill string, particularly in the sections lying on the low-side of the wellbore, can lead to substantial improvements in managing the two limiting factors of the long horizontal wells that are typically associated with today's unconventional shale plays: removal of formation cuttings from the borehole, and frictional drag between non-rotating drill strings and the wellbore wall. Minimizing these effects, by introducing controlled vibrations, increases the overall drilling efficiency and reduces the cost associated with the well. The difficulty in implementing such actions, however, is consistency. Because the behavior of drilling assemblies is inherently nonlinear, it has been difficult in the past to reliably predict their response to dynamic events. This, in turn, creates a challenge when trying to optimize the performance of arbitrary Vibration Inducing Devices (VIDs).

This paper presents a detailed analysis of the fully coupled, three-dimensional, nonlinear behavior of drill strings under the action of induced vibrations. Specific focus is given to the dynamic characteristics of a drill string, during horizontal drilling operations, in long unconventional wells and how this behavior affects the success of the well. The response of the drill string, due to induced axial and lateral oscillatory motions, is examined through linearized dynamic analysis and nonlinear timedomain simulations.

Solutions obtained from the study provide a clearer understanding of the dynamics experienced down-hole and lead to suggestions for improved practices when drilling with lateral VIDs, particularly with regards to hole-cleaning. Further insights into the sliding and rotational behavior of the drill string, while using these types of tools, are drawn from animated modeling results. Finally, the future applications of this technology are discussed.
An Experimental Study of the Swelling Properties of Unconventional Shale-Oil Rock Samples Using both Water-Based and Oil-Based Muds and Effects of Invasion on Rock Mechanical Properties
Authors: Emadi H. , Soliman M. , Heinze L. , Moghaddam R. , Samuel R.
Published: March 2015

Knowledge of swelling properties of shale-oil formations as well as the effects of various drilling fluids, including both water-based and oil-based muds (OBMs), which are of critical importance to wellbore-stability problems, requires a better understanding of shale-oil properties. Drilling through shale-oil formations is highly problematic and imposes substantial costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties.

Only few experiments have been conducted on shale-oil samples to better understand their properties. Most experiments performed thus far were run on common shale core samples, which are significantly different from shale-oil samples in the matter of mineralogy and mechanical properties. Subsequently, the results of those experiments cannot be equally applied to shale-oil and shale-gas formations.

In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and cation exchange capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water, potassium-chloride (7% KCl) brine, and OBM. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and non-submerged areas. We also performed unconfined compressive strength (UCS) tests to investigate the effect of the invasion of various drilling fluids on the compressive strength of the core samples. The experimental setup was modified to accommodate five linearly variable displacement transducers (LVDTs) to measure Young's Modulus (E) and Poisson's ratio (v). Various experiments were run to quantify the effect of temperature on the rock compressive strength, E, and v. Experiments have shown a distinct change in the mechanical properties of the rock. The results demonstrate that the swelling properties and CEC of the shale-oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale-oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.
SMART Kick Detection; First Step on the Well Control Automation Journey
Authors: Brakel J. D. , Tarr B. A. , Cox W. , Jørgensen F. , Straume H. V.
Published: March 2015

In 2010, based on the safety performance results achieved through the automation revolution in its oil & gas downstream business, an operator set out to initiate the same revolution in its upstream business. Automating the initial well control response to an influx was identified as the initial focus area with the goal of assisting rig personnel to identify and stop any influx without delay. This led to a well control automation collaboration project being initiated between an operator, a rig contractor and a rig equipment supplier. The first phase of the project was to develop a system that could detect an influx across a broad spectrum of well construction related rig operations. This paper describes the development, deployment, and field testing of the first upgraded kick detection system from this collaboration.

To understand where to focus the kick detection system upgrade efforts, a fault tree style sensitivity analysis of kick detection and well shut-in procedures was undertaken. The results pointed to the high value of improved sensor data (both accuracy and reliability) and of improved detection software for alarming (both in terms of coverage and how the driller is alerted to respond to a confirmed kick condition). Based on this sensitivity analysis, a kick detection system upgrade functional specification was created and used to develop a trial upgrade plan for a deepwater rig.

Initial implementation operational performance results are presented to demonstrate that most of the kick detection system upgrade objectives were achieved.

Operational feedback from using the upgraded kick detection system is included which highlights the new, “SMART”, features that were designed to provide easily understood alerts to the driller; including unique pop-up kick alarm windows for drilling or circulating, making a connection, and tripping in or out.
Defining Fragile - The Challenge of Engineering Drilling Fluids for Narrow ECD Windows
Authors: Knox David , Bulgachev Roman , Cameron Iain
Published: March 2015

Over the last decade, the challenge of drilling narrow Equivalent Circulating Density (ECD) window wells has put increasing pressure on the performance of the drilling fluid. As a result of this, so-called ‘Fragile Gel’, or ‘Flat Rheology’ fluids have been developed by the industry and have become widely utilised across the globe. Although the design of these fluids is primarily aimed at optimising performance in deepwater environments, the lower pressure fluctuations imposed on the formation (as compared to more conventional invert emulsion fluids) that is attributed to these fluids has contributed to their increased use in other, non-deepwater areas, where ECD management is still viewed as critical.

Although the perceived benefits are now widely understood and accepted, the industry has not yet developed a comprehensive and universally-accepted benchmark for the properties that satisfactorily define these fluids. The authors of this paper believe this to be due to a number of factors, including the different approaches taken within the service industry in developing chemistries that either significantly reduce, or even completely replace, the requirement for conventional organophilic clay-based viscosifiers.

BP have developed an internal set of guidelines based on operational experience in regions where these fluids have been successfully implemented; however, these have limitations when universally applied, particularly as new fluids featuring novel chemistries are introduced.

This paper discusses the key engineering parameters used to define the engineering guidelines for what BP refers to as ‘Flat Rheology Fluids’. A description of these parameters and how data collected from recent field trials in Norway is being used to help refine and validate these parameters is also described.
Application of Modern Technology to a Multi-position Down Hole Drilling Electronic Circulating Valve and Integral Disconnect Mechanism
Authors: Hunter Gordon , Ollerenshaw Andy
Published: March 2015

There are several areas where modern technologies can be applied to improve hole conditions reducing the chances of tight hole and stuck pipe. Hole cleaning has always been a key issue in inclined and horizontal wells where cuttings bed form and can lead to time consuming, difficult hole conditions and sometimes stuck pipe when attempting to trip out the hole. Annular velocity is one of the critical parameters that can improve cuttings bed removal but power hungry BHA's and bit hydraulics can sometimes compromise the ability to provide sufficient flow rate to clean the hole. A circulating sub is often installed above the BHA that can be opened to bypass the BHA and provide maximum flow rate to clean the hole. It can also be used to dump high concentrations of LCM in a lost circulation situation that would otherwise block the BHA and bit nozzles. Almost all circulating subs are of a drop ball/dart type that has a limited number of cycles, usually 6 to 9. Balls have to be dropped to open and separate balls dropped to close. These subs have limitations when it comes to hole angle, as the balls require gravity to reach their seats. They are unreliable in inclinations above 65 deg, require surface intervention and are usually only two positions i.e. open or closed. In a packed off situation where the annulus is sealed around the BHA and circulation is prevented, the balls or dart sometimes do not reach their seat and the sub cannot be opened to try and relieve the pack off.

This paper discusses the development of a multi-position electronic circulating valve that can be set to multiple positions by surface down linking. The circulating valve can be configured as a standalone tool or combined with a unique motorized disconnect clutch mechanism that is activated by sensing its environment, working through internal logic modes before being in a position to receive a surface signal to disconnect. This has application in a stuck pipe situation where the tool can be commanded to disconnect and the drillstring recovered avoiding the need for surface intervention and any form of wireline and explosives. This tool has application in any well but particularly high angle wells where the circulating valve can be down linked to the first position for partial BHA bypass increasing annular flow and the final, maximum bypass, position can be used for dumping LCM or fast wellbore clean up at section TD or at any point in the well. Deepwater operations with spread rates in excess of $1M per day can benefit from the time savings in wellbore clean up, response to lost circulation and flexibility and control in a stuck pipe situation without waiting for wireline crews or explosives to perform a disconnect.
Casing Collapse Strength Enhancement Due to Cement and Pipe Support via Modelling and Testing
Authors: Jammer Peggy , Hariharan Hari , Klever Frans J.
Published: March 2015

The API 5C3 collapse strength formulas are widely used in the industry for casing design. While these formulas provide estimates of the collapse resistance of pipe alone, they do not consider the supporting effect of cement sheath, outer steel pipes, or formation. Given the increasing complexity of the industry's wells, as well as the importance of safety, the ability to accurately assess a well's risk is becoming more and more important. This study aims to facilitate such a reliability-based design approach by investigating the collapse strength of a pipe-cement-pipe system.

A finite-element analysis (FEA) model was developed and used to analyze collapse behavior for various configurations and loading scenarios: casing only, or casing cemented into casing; possibly incomplete cementing scenarios; loading by annular pressure and/or external pressure; collapsing the inner pipe, outer pipe or the composite. The FEA results were benchmarked against a full-scale experimental program.

The study focused on an 11 ¾ in. 65 lb/ft P-110 HC casing cemented into a 13 ⅝ in. 88.2 lb/ft Q-125 casing, and the results clearly and consistently indicated the supporting effect of the cement sheath in providing improved collapse resistance of the casing (even with varying degrees of void in the cement). Experimental results showed an increase over the pipe-only collapse strength of about 60% (pipe-cement-pipe, annular pressure collapsing the inner pipe) or about 260% (pipe-cement-pipe, external pressure collapsing the composite pipe), for a perfectly cemented condition. The FEA results tracked the experimental values of pressures with a satisfactory degree of accuracy, while evaluating loss of collapse strength enhancement as the cement void angle increased.

The procedures and results presented in this paper may be used to assess the true risk of collapse of casings deeper in the well under worst case discharge (WCD) conditions.
Drilling Depleted Sands: Challenges Associated With Wellbore Strengthening Fluids
Authors: Chellappah Kuhan , Kumar Arunesh , Aston Mark
Published: March 2015

One way of overcoming the challenge of drilling depleted sands is to use so-called “wellbore strengthening” (WBS) techniques, whereby engineered particles are added to drilling fluids to increase the fracture initiation or propagation resistance. Although the mechanisms are not comprehensively understood, most explanations suggest that an increasing proportion of large particles is required to achieve a greater extent of ‘strengthening’. These large particles can create practical challenges while drilling; such as particle attrition, settling, and erosion of equipment. Field examples are presented which highlight these issues. Experimental work to identify solutions to the practical challenges is presented. A laboratory attrition test developed in-house confirms walnut shell as a promising material to resist grind-down when large particles need to be retained in the system. Formulations prepared using controlled size distributions of this material are shown to give a good fracture sealing performance in the laboratory. The accurate maintenance of particle size will require regular solids monitoring at the rigsite to keep the fluid within design specifications. Some data from real-time particle sizing techniques are presented. Overall, the findings presented in this paper should lead the industry towards wellbore strengthening systems which are effective, more efficient and practical operationally.
A Stochastic Model for an Active over Passive Motion Compensator for Offshore Drilling Operations
Authors: Barr A. M.
Published: March 2015

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

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

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

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

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.