bluuebunny/crossref_metadata_2025 huggingface dataset:
Clay-Free High Performance Water-Based Drilling Fluid for Extreme High Temperature Wells
Authors: Galindo Kay A. , Zha Weibin , Zhou Hui , Deville Jay P.
Published: March 2015

Growing demands to operate in harsh high temperature environments require robust drilling fluid performance to drill in such conditions. Water-based drilling fluids offer significant environmental advantages compared to invert-emulsion fluids (IEFs). High performance (HP) water-based drilling fluids are particularly advantageous compared to conventional water-based systems because they offer faster rates of penetration (ROPs), enhanced hole cleaning and shale inhibition, and improved wellbore stability. Most HP water-based drilling fluids can only tolerate operating temperatures up to 300°F attributed to a strong dependence on biopolymer-based viscosifiers. Thus, deeper exploration in extreme high temperature reservoirs (>300°F) requires new drilling fluid technologies. A new high performance, high temperature water-based drilling fluid that is thermally stable at 400°F has been developed to meet these demands.

The new fluid system was fully formulated using a multimixer, and the resulting fluids were hot rolled at 150°F for 16 hours to condition the fluid before testing. The conditioned fluids were then further subjected to dynamic or static aging conditions with temperatures ranging from 300 to 400°F. The aged fluid viscosity was examined using a direct-indicating viscometer, and the pH was determined with a pH meter. The fluid loss properties of the fluids were determined by both API filtration and high-pressure/high-temperature (HP/HT) filtration at 350°F in according with the API recommended practice.

This paper presents the detailed study of the high performance, high temperature water-based drilling fluid formulated with 10.0-17.0 lbm/gal densities. The fluid exhibits a stable rheological profile. For example, a 14.0 lbm/gal formulation aged at 150°F for 16 hours yielded a plastic viscosity of 29 cp and a yield point of 22 lbm/100 ft2. After static aging for 48 hours at 400°F, the fluid gave a plastic viscosity of 27 cp and yield point of 24 lbm/100 ft2. The new fluid maintains stable viscosity, adequate suspension, low shear strength, shale stability, and filtration control up to 400°F.

This thermally stable, clay-free system exhibits good shale inhibition and is environmentally acceptable for both land and offshore drilling. This HP water-based drilling fluid is formulated with a novel synthetic polymer viscosifier and filtration control agent, allowing removal of thermally labile biopolymers without the addition of clay-based viscosifiers. The new formulation provides reliable thermal stability that can readily function in extreme high temperature wells, while preserving the benefits of HP water-based drilling fluids.
Innovative and Modular Equipment Design for Rheology and Compatibility Measurement of Complex Wellbore Fluids
Authors: Sairam P K , Pangu Ganesh , Gajji Bhargav
Published: March 2015

Accurately measuring the rheology of fluid systems under downhole conditions is recommended for the success of well construction. The rheological fingerprints of fluids and their admixtures deployed downhole during wellbore servicing provide a basis for predicting interfacial fluid movements and associated effects on bottomhole circulating pressures. Rheology measurements can also provide a direct indication of any detrimental physical and/or chemical reactions that might occur when the fluids intermix and/or contaminate one another during and after the placement process.

A need has existed for some time within the industry for high-pressure/high-temperature (HP/HT) rheology equipment capable of in-situ fluid transfer to change compositions on-the-fly, and easy to clean and maintain considering the abrasive and settable nature of cementitious fluids. This paper discusses an innovative design developed for a fully automated slurry rheometer capable of dosing contaminant fluids in and out of fluid samples to vary composition, mix homogenously in-situ, and measure compatibility between fluid systems at various volumetric compositions—all while maintaining in-situ wellbore test conditions.

The rheometer cell is a four-piece design that houses a novel magnetically coupled double helical rotor with cut flights and intermeshing helical blades on the stator to allow mixing and measuring at the same time while overcoming operational issues, such as wall-slip, particle settling, sample coring, and aid in-situ homogenization. A first of its kind, noncontact, zero friction magneto-resistive torsion measurement module with selectable range capabilities and large separation offset (6 to 8 in.) from moving parts is discussed in addition to its usability on both thick pastes as well as thin fluids.

A separate design of a high pressure slurry dosing unit that allows for compatibility measurements is discussed. Operating principles, design concepts, engineering development for modularity, calibration data, and slurry test results are presented.
Using Drill Cuttings Waste as Resource for Spud Mud
Authors: Taghiyev Farid , Hodne Helge , Saasen Arild
Published: March 2015

Today oil-contaminated drill cuttings are regarded as a waste in the oil industry and have to be treated before simply depositing in an onshore facility. Thermal technology to treat contaminated drill cuttings, remove most hydrocarbons and recover the subsurface material in a dry powder form exists. Due to the similarity between subsurface rock mineralogy and conventional bentonite used in the drilling fluid industry an extended laboratory study was carried out to evaluate the possibility of spud mud development using thermo-mechanically treated drill cuttings.

A total number of 28 spud mud compositions were prepared including two commonly used bentonite spud muds and tested in accordance with the API 13B-1 practices. An aging experiment was conducted as well to evaluate the stability of the designed fluids. Moreover, application of barite as a weighting material and short chain CMC polymer as a fluid loss control agent was investigated as well.

As a result of the conducted experiments stable seawater-based spud mud compositions with application of xanthan gum and thermo-mechanically treated drill cuttings were developed. The designed fluids have comparable properties with the conventionally used spud muds. Depending on the composition plastic viscosity varied from 6 to 12 cP and yield stress varied from 1.53 to 5.11 Pa. The fluids were stable and capable of suspending heavy barite particles. The CMC polymer demonstrated good fluid loss control qualities. The new fluids might be cost effective in case of weighted muds and when drilling through impermeable formations.

This paper shows in detail how cleaned drill cuttings can be recycled into new drilling fluid materials, which brings environmental benefits along with the economical benefits. The designed spud muds with application of drill cuttings are ready to be tested in a large-scale facility.
Accuracy and Correction of Hook Load Measurements During Drilling Operations
Authors: Eric Cayeux , Skadsem Hans Joakim , Kluge Roald
Published: March 2015

Hook load is a very important parameter used during drilling operations to control the weight on bit and to assess possible deteriorations of the downhole conditions such as poor hole cleaning or excessive tortuosity. However, the quality of the hook load measurement is often regarded as quite poor. This paper investigates the sources of uncertainties associated with the hook load measurement and proposes correction methods in order to obtain better data quality.

In practice, the hook load is normally measured indirectly, either in the travelling equipment or as a tension in the dead-line. This apparent hook load is subject to load-generating forces between the measurement location and the top of the string, including the weight of the mud hose attached to the top drive, imperfect tension transmission across sheaves and gravitational and inertia forces associated with weight and rotation of the drill line, respectively. The load contribution from these forces can amount to several metric tons and this must be accounted for whenever the true hook load is to be derived.

In this paper, a mathematical model describing the forces affecting the hook load measurement is developed. The model predicts true hook load as a function of block position, velocity and other conditions that can influence the measurement like the mud weight or whether the dolly is retracted or not. It is a generalization of the industry-standard hook load estimation technique and successfully replicates a number of trends observed in the field. Extensive model evaluation is performed by comparing model results to field measurements of simultaneous travelling equipment and dead-line tension derived hook loads. The model is also compared with data from a laboratory scale test rig equipped with distributed load cells connected to a data acquisition system.

The hook load correction model works exclusively at the software level and represents a potentially cost-efficient alternative to a direct hook load sensor installed in the internal BOP of some top drives. Assessment of model uncertainty and its effect on hook load predictions is given particular attention as this ultimately determines whether the correction method can replace direct hook load measurements in practice.
A New Technique for Calculating Downhole Rotation Speed and Torque from Surface Measurements
Authors: Kyllingstad Åge
Published: March 2015

This paper presents a new, field tested technique that provides accurate estimates of downhole variables rotation speed and torque. The estimates are based on drill string geometry and surface measurements of the same variables. The technique is more wide-ranging and accurate than previously used methods, in several ways. First, it includes many frequencies, not only the stick-slip frequency. This helps to detect higher order stick-slip oscillations and to determine maximum and minimum speed more accurately. Second, it works when the top drive speed varies substantially, which is often the case when the top drive speed control is softened as a result of activating a stick-slip mitigation tool. Third, it also provides downhole torque, not only rotation speed. Finally, the new method can be used for calculating string variables at any location, not only at the bit.

The new method has been tested with exceptionally good results, both against an advanced, comprehensive simulation model, and against field data containing synchronized and high quality downhole and surface data. It is especially encouraging that the method works well when the torque input is erratic with a low periodicity and also when the top drive speed varied substantially. This strongly indicates that the new method can be used as a reliable and low cost technique for evaluating and validating the effect of various stick-slip mitigation tools.
First Ever North Sea Deployment of Tandem DIV System Eliminates Snubbing- A Case Study
Authors: Mueller Gary
Published: March 2015

On an offshore jackup rig in the North Sea, an operator required specific drilling needs during tripping and the safe and efficient deployment of the completion string without killing the well. A solution other than a snubbing unit was required because of the length of the completion string, which included 12 swellable packers for 13 individual zones. The swellable packers were staged to prevent the heel and toe effect and to create a homogeneous production profile. Snubbing the pipe in and out of the hole presents serious Health, Safety and Environmental issues that typically lead to considerable non-productive time (NPT) due the inherent slow speed of operation associated. In addition, snubbing requires added personnel.

To address these concerns and provide for a safer, less expensive and efficient method of tripping pipe, the operator chose to employ a Downhole Isolation Valve (DIV) solution that allowed for the process to be performed in a conventional manner under conditions of complete well control. As an alternative to a snubbing unit, the DIV system was used to isolate the slightly underbalanced well. The service team installed a tandem 7-in., 32-lb, 5K DIV system (Fig. 1) on a temporary retrievable tieback casing string with premium left-hand thread connections. Specifically, a tandem DIV system was chosen as an added security measure, in the case that unforeseen circumstances required an additional unit. Figure 1Upper and lower DIV system configuration.

In this paper the author will examine and provide details of the DIV system and its' evolution. He will go on to describe how the North Sea's first ever successful deployment of a tandem downhole deployment valve (DIV) system created a reliable barrier that isolated the well formation pressure below the valve, thereby saving rig time, enhancing safety, and cutting drilling costs.
Casing Wear Factors: How do They Improve Well Integrity Analyses?
Authors: Kumar Aniket , Samuel Robello
Published: March 2015

Casing wear factors form an integral part of casing wear estimation techniques. However, the values of experimental wear factors do not match field conditions when predicted casing wear is compared to measured values. Hence, adjustments and manipulations are made to wear factors to match field data so that these calibrated values can be effectively applied for more accurate predictions. These field calibrations, which often are extensive, have resulted in casing wear factors being mainly treated as just “fudge factors.” This has led to a lot of confusion regarding the fundamentals behind using wear factors for casing wear analyses.

This paper aims to bridge this knowledge gap and provides a comprehensive treatise on casing wear factors and their underlying parameters. The paper describes the details, a clear definition, uncertainties involved, and concepts regarding the appropriate use of casing wear factors and their applications. The wear factors are inherently tied to the coefficient of friction or the friction factor, which in turn is also a proxy because of the larger uncertainties involved in the modeling process. Wear factor values are also dependent on the material properties and operation type and vary non-linearly with the wear groove shape. Additional variations in experimental values also arise resulting from downhole high-pressure/high-temperature (HP/HT) conditions, accuracy of well surveys, as well as wellbore tortuosity and torsion. Other operating parameters, such as rotational speed, rotating time, and normal contact force, can also influence wear factors.

This paper investigates, in detail, the dependency of casing wear factors on these uncertainties through several example case analyses. It provides detailed explanations to help understand the fundamental concepts and apply appropriate wear factors for accurate downhole wear estimation. Accurate prediction of casing wear is essential to enhance well integrity and further the life of the well. Hence, this paper also presents a specific example for casing integrity analysis and provides insights to improve overall well integrity by performing a comprehensive casing wear analysis. In addition, the concept of casing wear maps is introduced. These can provide a new visualization and interpretation technique and help to minimize casing wear during drilling operations.

Accurate casing wear prediction is crucial for helping to reduce the over-engineering of casing designs in increasingly complex drilling programs, as well as for helping to prevent catastrophic casing string failures caused by wear. This paper provides a sound engineering basis for future drilling engineers to effectively understand the challenges involved in selecting appropriate wear factors and the underlying uncertainties that govern casing wear estimation analyses.
Advances in the Calculation of Circulating Pressure Drop with and without Drillpipe Rotation
Authors: Hemphill Terry
Published: March 2015

Annular pressure measurements have consistently shown the direct relationship between increasing drillpipe rotation speed and increasing pressure drop. A hydraulic model that accurately predicts the hydraulic effects of drillpipe rotation can improve the pressure drop calculations. However, conventional pressure drop modeling does not take into account 100% of the calculated pressure drop that is produced with the drillpipe rotation moving the fluid in helical flow. Hence a need to better refine calculation methods is warranted.

The pressure drop calculations for flowing drilling fluids were calculated using equations previously published. Calculations for axial and helical flow were performed separately, as in the axial flow case an area of plug flow is assumed, while in the helical flow case 100% of flow area is assumed to be sheared.

Conventional pressure drop modeling uses geometry, pump rate, and drilling fluid rheological properties to calculate pressure drop across the annular gap. However, these results usually account for approximately 95% of the real pressure drop. What has been missing up to this point is the pressure drop that arises between the slipping fluid layers moving in helical flow. Secondly, the effects of drillpipe rotation are usually not taken into account, even when the drillpipe is rotating.

Theoretical calculations using the proposed solution for total pressure drop show that: 100% of the pressure drop can now be theoretically accounted for, both with and without the effects of drillpipe rotation.With drillpipe rotation taken into account, the pressure drop in the slipping fluid layers is higher than that for axial cases. A method is shown that explains how to calculate this extra pressure for both axial and helical flow cases.Pressure drops in eccentric geometry cases can rise quickly in the more-narrow annular regions. Hence when drillpipe rotation speeds are in the normal operating range of ±100 rev/min, calculated pressure drops approximate those calculated conventionally (axial flow with no drillpipe rotation).

With these extra pressure drop calculations, the real pressure drops for fluid moving in helical flow can be obtained, something especially important in areas where safe drilling window margins are very narrow. As a result, better equivalent circulating density (ECD) predictions can be made.
Managing Losses in Naturally Fractured Formations: Sometimes Nano is too Small
Authors: Savari Sharath , Whitfill Donald L.
Published: March 2015

Controlling severe to total loss situations in naturally fractured and unconsolidated formations can be critical and, most of the time, these situations make it difficult to continue drilling. Conventional lost circulation materials (LCMs), such as ground marble, graphite, and nutshells might not work. In such situations, the operator generally resorts to using cement plugs or mud-cap drilling.

This paper presents novel applications in the form of engineered composite LCM solutions (ECS) successfully used to manage severe to total loss situations in naturally fractured carbonate formations. Case studies are presented from applications in North America, the Middle East, and East Africa. Engineered multimodal (MM) LCMs, which are composite LCMs with MM particle-size distribution (PSD), were developed as remedial solutions for handling severe to total losses. The MM PSD is characterized by a PSD curve with two or more concentration peaks, which help better manage uncertainty in fracture sizes. The particulate ECS was extensively tested in the laboratory for its effectiveness in terms of plugging large slots. For the most severe lost circulation cases, a combination of two ECS materials, one containing a swellable component, is proposed as a potential solution.

While drilling a severely fractured limestone formation in North America, the combination of particulate and swellable ECS, along with chopped fibers, was applied after all conventional LCM applications failed. The combination was pumped open ended and losses were totally cured, allowing circulation to be established again. With this experience, similar solutions were included in the plan for drilling a highly fractured carbonate formation for an operator in the Middle East. Most of the formations are highly fractured carbonates and are prone to severe to total losses. The ECS combination was successfully used to mitigate complete losses and continue drilling where, in some cases, as much as 90% circulation was regained.

Another application of this solution was also proposed for drilling an offshore well for an operator in East Africa. A formation that was severely fractured was to be encountered and total loss was expected. A circulating sub was recommended in the bottomhole assembly (BHA), and high concentrations of ECS were pumped. Losses were managed in most cases that were otherwise unmanageable with conventional LCMs. This enabled the operator to reach total depth (TD) and obtain necessary exploration information.
Studies of Cement Wiper Plugs Suggest New Deepwater Standards
Authors: Trogus M. , Farley D. , Gaspard G.
Published: March 2015

Well cementing is a crucial component of deepwater well construction, and a key to cementing success is the performance of the cementing plug. Plug performance is primarily based on the mechanical wiping efficiency and wear resistance of the plug. However, limited understanding of the performance has hindered the establishment of standards. While API RP10F provides recommended testing practices to evaluate the performance of cementing float equipment, it does not include cementing plugs.

This paper is the first published review of efforts to better understand cement plug performance and to establish industry standards. Through laboratory studies, it examines material loss in actual deepwater applications and evaluates the effect on wiping performance of cementing plugs. These studies provide the basis of a selection process for wear-resistant materials. The paper also examines methods of measuring wiping efficiency and overall plug performance. Based on these methods, a proposal is presented for establishing industry performance standards for setting cementing plugs.

Cementing wiper plugs provide a physical barrier to cement contamination by separating displacement fluid and wiping residual mud film and other materials from the inside surface of the pipe. Separation and wiping efficiency are directly related to plug wear resistance and to the process of balancing design to achieve optimal stiffness and pressure containment. This design balance is achieved through rigorous material testing and design refinement. Analysis of wiper cuttings samples has provided a clear understanding of the plug's ability to provide a physical barrier to separate fluids and how that affects the function of downhole tools. This cuttings evaluation has provided information on material loss and positive fin interference. Results of the evaluation are corroborated by field performance achieved in cementing lengths of casing greater than 16,000 ft.

Plug wear is of particular concern in long, high-volume, deepwater casing strings where it can lead to displacement errors and reliability problems for downhole pressure-actuated tools. These displacement errors are examined in field applications that precisely locate the plug at multiple points during the cementing process.
Hardbanding Compatibility Test Program to Stem Tool Joint Failures Caused by Reapplication of Incompatible Hardbanding
Authors: Koneti Srinivasa , Gokhale Samit
Published: March 2015

Hardbanding re-application on used tool joints is routinely performed to build up previously worn out hardbanding. Often, hardbanding reapplication is performed without checking the compatibility of the reapplied and previous hardbanding types. Different hardbanding types do not always work properly when applied over each other. This hardbanding incompatibility can lead to cracking, spalling and porosity of reapplied hardbanding. This can cause premature damage and failure of the reapplied hardbanding and even the mechanical failure of the tool joints themselves.

This paper presents case studies and lessons learned from the analysis of such failures. In every case, hardbanding reapplication was performed without checking the compatibility with the existing hardbanding. Metallurgical analysis showed that the failed tool joints had two different hardbanding layers and that the tool joint failures were caused by the incompatibility of the two materials. The new hardbanding cracked and chipped off from the outside surface of the tool joints and led to tool joint failures when the cracking propagated through the base material.

In addition to discussing hardbanding incompatibility failures, this paper also provides reapplication specification requirements and inspection guidelines needed to control the reapplication processes. To confirm compatibility of different hardbanding types, a compatibility testing program was created. This paper presents the details of this compatibility test program including discussions on application geometry, procedural control, metallurgical analysis and material testing needed to confirm compatibility.
Drilling With 100% Natural Gas Engines
Authors: McEvers Jon , Kent Bill
Published: March 2015

Antero Resources decided to convert the majority of its drilling operations from diesel to 100% natural gas fueled rigs in late 2012. By September 2014, ten of Antero's largest drill rigs were retrofitted with GE Waukesha rich-burn gas engines and fueled entirely by natural gas. By operating on field gas 50% of the time and LNG for the remaining 50%, Antero realized a savings of more than $72,000 per month on its gas engine rigs versus its comparable diesel fueled rigs. This paper presents how Antero successfully deployed rich-burn natural gas engines into its Patterson-UTI Energy and Precision Drilling drill rigs.
Blowout Well-Flow Simulation for Deepwater Drilling using High-Pressure/High-Temperature (HP/HT) Black-Oil Viscosity Model
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng
Published: March 2015

One of the major risks associated with drilling an oil well is a blowout, or an uncontrolled release of hydrocarbons, which can lead to significant financial loss, environmental damage, personnel injuries or even casualties, and shaken shareholder confidence. Numerical simulation can offer some insight into well-flow parameters and wellbore integrity during a blowout event. Therefore, it is a powerful tool in casing design, blowout-preventer (BOP) stack design, drilling-process design, and well-kill design.

In this paper, a field case was investigated using a commercial thermal and flow simulator. The effects of oil flow rate on wellbore temperature and pressure profiles were studied. Load analyses show that a blowout to atmosphere scenario is more detrimental to well integrity than a blowout to seafloor. In both scenarios, the maximum collapse load of the innermost casing increases with a decreasing blowout oil rate. This implies that if reservoir pressures are the same, deepwater wells with lower productivity indices will be more problematic in terms of well integrity.

Simulation results also show that the viscous friction heat loss becomes significant at very high oil flow rates. During a deepwater-well worst case discharge (WCD) blowout, it is so significant that the wellbore temperature increases toward the surface along the smallest flow passage. The situation is even worse if the blowout fluids are discharged to the atmosphere. The physical root cause is explained in terms of fluid heat balance.

A high-pressure/high-temperature (HP/HT) black-oil viscosity model was developed through modification of the Bergman-Sutton model. The HP/HT viscosity data of different crude oils with various API gravities were used to determine the model constant through regression. The effects of this HP/HT viscosity model are quantified in detail using the case-study data. The new viscosity model yields much higher accuracy in the HP/HT regime compared to other traditional, widely used models. Consequently, it facilitates higher certainty modeling and simulation of well discharge scenarios to satisfy current casing-design regulations in well exploration and development, from deepwater to ultra-deepwater conditions.
Wired Near Bit Underreamer Connects Measurement While Drilling Tools to Rotary Steerable System While Eliminating the Under Gauge Rathole at TD
Authors: Valverde Eduardo , Goodwin Alex
Published: March 2015

Simultaneous drilling and hole enlargement is a common practice in deepwater Gulf of Mexico projects where tighter casing tolerances are required. Hole enlargement via underreaming is the most common practice, because it provides a larger diameter hole to ensure that casing reaches its required total depth (TD). Hole enlargement creates sufficient annular space to allow casing to be delivered to planned depth as well as for a properly executed cement job. The most accepted bottom hole assembly (BHA) design for hole enlargement while drilling (HEWD) places an underreamer above both the measurement while drilling / logging while drilling (MWD/LWD) and rotary steerable system (RSS) packages. This placement ensures proper installation of the activation ball in the underreamer and connectivity of the RSS and MWD/LWD so that directional work can be executed. However, this placement also leaves up to 200 feet (61 m) of under gauge rat hole to total depth (TD), forcing the operator in many cases to make a second dedicated run to underream the remaining under gauge rat hole.

An alternative underreamer technology that is gaining interest is designed to run directly above the RSS, but below the MWD/LWD package. Known as the intelligent wired underreamer, this design allows for a much shorter under gauge rathole to TD, while circumventing several common deployment challenges with conventional underreamers. Historically, placing an underreamer below the MWD/LWD prevented the operator from pumping an activation ball through the restricted internal diameter of the MWD/LWD tools. Another challenge of placing the underreamer near the bit is the fact that connectivity is severed between the MWD/LWD and RSS, which makes it impossible to use certain RSS in the BHA.

A deepwater operator drilled a development well in the Gulf of Mexico which required such a solution to simultaneously drill and enlarge the 18 1/8” and 16 ½” sections of the wellbore to 22” and 20”, respectively. The intelligent wired underreamer, with its radio frequency identification (RFID) and pump-cycle activation capabilities, allowed the operator to run the underreamer directly above the RSS and below the MWD/LWD package and successfully activate and deactivate the underreamer, without ball drop. A wire through the underreamer connected the MWD/LWD and the RSS, providing full connectivity and directional control. And the use of an intelligent wired reamer in this application eliminated a potential round trip to ream the rathole and allowed the operator to successfully drill and ream both sections to planned TD.
Look Ahead Team MXS: Transforming Knowledge in Successful Operations
Authors: Rodríguez E. , Jiménez A. , Angel J. , Bedino H. , Scagliarini S. , Salinas N. , Valdiviezo F. , Mendoza P.
Published: March 2015

This paper describes how the creation of an innovative multidisciplinary team - the Look Ahead Team (LHT) - together with ad hoc new built processes and protocols, have greatly helped minimizing both the geological and drilling risks and their impact in the very complex wells currently being drilled in the Mesozoico, Exploration and Alliance projects in Southern Mexico (MXS). Also, it explains how the integration of different knowledge domains coupled with detailed technical scrutiny, subsurface visualization, modeling and simulation, thorough multilayers risk assessments, risk management techniques, real time data acquisition and continuous application of lessons learnt, have been delivering substantial savings to the drilling operations.

Wells can be classified as deep HP/HT and/or LP/HT wells.

The objective of the LHT is to visualize and analyze drilling related risks, to generate alerts and recommendations before a new hole section is commenced, so that undesirable and detrimental subsurface events are anticipated and prevented or minimized.

Drilling engineering, geology, geophysics, geomechanics and well placement are all represented in and form an integral part of the LHT. For each new well to be drilled, the geosciences' domain experts perform an integrated subsurface interpretation considering all current information available, offset wells and real time data.

The analysis performed is twofold: a forecast drilling scenario (well trajectory and placement) which is optimized based on the calibration attained through the iteration with existing (offset) wells using sophisticated modelling and newly created work protocols that allow effective multidisciplinary workflows, subsurface assessment and detailed risk analysis by hole section.

The main outcome of the analysis is to deliver a predictive ‘look ahead’ report which contains all risks identified at least 200 m ahead of the bit together with the risk analysis matrix and the corresponding prevention and mitigation plan. Also during the program execution, the LHT provides technical support to the engineering and operations teams anticipating the next action based on risk projection re-assessment using real data streaming.

The Look Ahead Team's newly implemented processes/workflows and innovative analysis methodologies, have been tested on 21 development wells and 3 exploratory wells for a total of 72 hole sections. In just one year from its foundation, unforeseen drilling events due to geological uncertainty were reduced by 90% achieving 10MMUSD worth of savings.
Assessment of the Validity of MWD Survey Accuracy Following Multistation Analysis
Authors: Hanak F. Chad , Wilson Harry , Gjertsen Morten
Published: March 2015

The authors are concerned that the claim of increased accuracy for MWD directional surveys processed using multistation analysis (MSA) may not always be valid, resulting in incorrect assumptions regarding the probability of well collision and target intersection. Very little information is available about the MSA methods currently in use. The only relevant published work identified by the authors is an SPE paper defining the minimum survey log conditions required to validate surveys against the ISCWSA MWD error model, but the requirements do not support assumptions of increased accuracy, post correction.

It was therefore decided to determine if MSA can be used to reliably increase survey accuracy. The study also evaluated the validity of using the published minimum requirements to validate data against a typical MSA enhanced error model. The mathematical technique of consider covariance analysis was used to quantify post correction position uncertainty, and compare it to typical MSA error model assumptions. The results were validated using monte carlo simulation.

The study showed that use of the published minimum data condition requirements to validate surveys against the increased accuracy claim typical of MSA error models is invalid. For the minimum requirements method to provide validation of such arbitrarily enhanced error models, new requirements must be defined specific to the MSA model. However, typical MSA error model assumptions are likely to result in requirements that can very rarely be met. Consider covariance analysis offers a reliable method of evaluating actual survey data against an arbitrarily enhanced error model on a case-by-case basis, which would allow more frequent use of the MSA error model.
Getting to Grips with Human Factors in Drilling Operations
Authors: Thorogood J.L. , Lauche K. , Crichton M. , Pollard I. , Hviid L.B. , Verweijen B.
Published: March 2015

Since the events on Montara in late 2009 and Macondo in 2010, the exploration and production industry has undergone a substantial change in culture and regulation. However, investigations still tend to focus on technological and managerial deficiencies rather than probing deeper into the causes of human error. Nonetheless, facilitated by organisations such as International Oil and Gas Producers Association (OGP), there is a growing desire to understand human and organisational factors that influence potential process safety incidents during drilling and completion operations.

A workshop was held in London in October 2014 to define and clarify the underlying ideas about human factors related to the drilling community. The objectives of the workshop were:

Introducing the concepts behind human factors and key definitions Highlighting the effects of human factors in drilling operations Operationalising human factors and the impact of the introduction of new technology Implementing training and assessment of non-technical skills Taking human factors into the mainstream of drilling operations

Attendees at the workshop discussed the principles underlying the psychological concepts of human factors, such as non-technical skills, cognitive bias, weak signals and chronic unease, as well as socio-technical systems and the impact of automation. Examples of how the influences of human factors may be recognised in routine drilling operations and how biases affect decision-making were examined. Practical applications of human factors techniques were described, along with methods currently being implemented to train and assess non-technical skills. The workshop culminated in a debate about how to operationalise human factors in drilling operations.

The main points to emerge from the presentations and ensuing discussions are summarised and references are provided for further reading. Practical tools and insights that can be applied in day-to-day operations are also presented.

In conclusion, workshop presenters and attendees, whilst acknowledging the importance of human factors on drilling operations, also recognised the challenges yet to be overcome in implementing human factors principles in the workplace. However, there are some positive signs of growing acceptance and influences. By facilitating open dialogue about human factors in drilling the goal is to encourage progress towards human factors integration being the norm rather than the exception.
Bit Trip Optimizer: Just in Time Bit Trip Decision Model
Authors: Kuesters A. , Wingate J.
Published: March 2015

This paper presents a model which aids the decision making process to determine the optimum point to trip out of hole to change a dulled drill bit.

Drill bit interaction with abrasive rock and impact damage due to vibrations causes the state of wear or damage to cutters to increase. This results in a slower rate of penetration (ROP) than with a new bit with sharp cutters. The operator faces the question whether or not to take the time to pull the bit out of hole and change it for a new one. A delayed or a premature decision of when to pull the bit can add to the overall project cost.

In the past the decision has been made using either the operator's experience or a simple cost model projecting a single bit run into the future. The model presented in this paper optimizes the bit strategy for an entire well with multiple bit runs to obtain the most economical choice of bits and bit trip strategy. The model can be used during planning, in real time implementation and for post well performance analysis. In particular, during real time and post run evaluation the model can be used for performance benchmarking of ROP by comparing an expected rate of progress with the actual field data.

This paper further presents a case study highlighting the value of each of the features of the model including potential time and cost savings. It shows that running the model real time can reduce well costs significantly in hard rock areas. The deployment of the model is not limited to any specific application and can save costs on any well where the operator has a requirement for multiple bit runs and a good understanding of drilling performance through numerous geological intervals.
Durable Bit Coating Reduces Shale Balling in Field Tests and Contributes to Longer Runs
Authors: Radford S.R. , Patel S.G. , Dee K.C.
Published: March 2015

Shale agglomeration or balling onto PDC bits is a problem in the oil drilling industry, reducing drilling speed and requiring costly bit trips to clean or change the bits. A new polymer-based bit coating was developed and introduced, which is proving to be very effective at reducing shale bit balling and is significantly more durable than previous polymer bit coatings.

This paper documents a previous coating from the same service company was superior in balling resistance compared to non-polymer coatings, such as metal or electrically charged coatings, and doubling the rate of penetration (ROP) in a Malaysia application. A new coating, and the subject of this paper, was developed and proven to be as effective but significantly more durable. The development of this new coating, its set of requirements and its intensive testing process are presented.

The authors document the history of utilizing different types of bit coatings to reduce formation balling and present limited comparisons between coatings. A set of field tests is presented wherein the new coating was applied to twenty of 233 bits run in similar wells and formations in Prudhoe Bay, Alaska by a major oil and gas exploration company. In all cases, the bits were 4 1/8-in “ream-while-drilling” eccentric bits run on coiled tubing, which, by nature restricts the flow and bit cleaning, thus increasing the probability of short runs and bit balling. Results, however, showed that the bits with the new coating stayed in the hole longer and maintained much of the coating coverage while drilling an average of 73% further than the similar uncoated bits which exhibited shale balling and ceased drilling.

Comparison analysis is made between the coated and uncoated bits in this case study, utilizing several parameters and perspectives. Cost savings are estimated and the future developments of this technology presented. Examples are summarized of drilling with PDC bits, with and without this new coating in shale balling-prone areas from other regions of the world.
Experiences, Challenges, and Common Recommendations from Performing HAZOP Studies to Identify Potential Hazards Associated to Surface Gas and Mud Handling Systems During Drilling Operations
Authors: Rubiano Carolina , Sullivan Paul , Gil Frederic , Tench Jordon
Published: March 2015

This paper summarizes a number of the challenges encountered and the common findings in HAZard and OPerability (HAZOP) studies related to the surface gas and mud handling systems on drillships, jackups, semi-submersibles, and land rigs. These HAZOP studies are conducted by experienced multi-disciplined teams that combine the operations, engineering, and process safety personnel from both the oil company and the drilling contractor.
Pressure Transmission in Gelled Drilling Fluids
Authors: Oliveira G. M. , Franco A. T. , Negrão C. O. , Vadinal R. B. , Lomba B. S. , Fonseca T. U. , Martins A.L.
Published: March 2015

In deep water environments, the operational window has become narrower and narrower resulting that pressure control within the well needs more accuracy. Pressure differences between the choke line and the stand pipe in a close well operation, usually ignored in the past, may now be a determining factor on the specification of the fluid weight to control a kick. Additionally, pressure changes in the choke line that delay and undermine the transmission to the kill line and to the stand pipe have been receiving much more attention nowadays. The current work proposes a mathematical model to explain the pressure differences, delays and attenuations observed in closed well operations. The model is based on the conservation equations of mass and momentum, deals the problem as transient and compressible and the fluid motion is admitted to be one-dimensional. The drilling fluid is modeled either by the Bingham or the Power law equation. It can be anticipated that the problem is intrinsically transient and cannot be treated by a steady-state model. In addition to that, a pressure difference between two pipe ends, generated by a step change at one pipe end, can either be permanent, in case of a Bingham fluid, or reduced very smoothly, in case of a Power law fluid.
ROP Enhancement in Shales Through Osmotic Processes
Authors: van Oort Eric , Ahmad Muneeb , Spencer Reed , Legacy Nick
Published: March 2015

70%–80% of all formations drilled globally are identified as shales, i.e. argillaceous rocks that contain significant amounts of clays. In addition, the US Energy Information Administration conservatively estimates that 26% of recoverable oil and gas resources of the United States alone are contained in shale formations (EIA Annual Energy Outlook, 2014). Accordingly, there has been an increasing focus on efficient drilling of tight shaly formations, as encountered for instance in long horizontal laterals of unconventional wells. Improvements in PDC bit design and low friction cutter technology need to be mentioned in particular, which have made PDCs the bits of choice in all but the hardest formations.

The question now arises where the next step change in rate-of-penetration (ROP) improvement for PDC bits is going to come from. The answer lies in optimizing the intricate relationship between bit, intact and failed rock, and the drilling fluid. When shales are drilled with PDC cutters, a built-up “detritus” edge of failed rock will temporarily adhere to the cutter and prevent it from cutting new rock effectively. Disrupting this detritus may significantly reduce friction at the bit and improve PDC cutting efficiency. This appeared to be the case when high salinity formate muds were tested in the Deep Trek downhole drilling investigation reported on in 2007–2008. The merits of high salinity formate muds, which significantly out- drilled even oil-based mud at high densities during Deep Trek, were duly noted but never fully explained.

In this paper, it is proposed that the mechanism responsible for the Deep Trek ROP results with formate mud is chemical osmosis, which effectively draws water from the drilled shale and generates a lubricating layer between the cutter and the shale that disrupts the detritus and allows the bit to be cleaned more effectively through the hydraulic nozzle flow, thereby enhancing ROP. Support for the proposed mechanism is provided by an extensive set of laboratory tests, ranging from simple hot-rolling tests that measure accretion tendencies of shale on steel, to realistic drilling tests on full-scale equipment and actual PDC bits under downhole conditions. The results show unequivocally that high salinity muds yield consistently lower accretion tendency and 50–60% higher ROP in shales, and that the underlying mechanism appears to be chemical osmosis. Moreover, positive results of field trials conducted in Canada, where application of formate fluids allowed oil/synthetic mud drill rates to be significantly exceeded, further support the hypothesis of the merits of chemical osmosis for ROP enhancement. The osmosis phenomenon is well-known for borehole stabilization in oil/synthetic-based muds and high salinity water-based muds, but has never before been deliberately deployed for ROP enhancement in shales.