bluuebunny/crossref_metadata_2025 huggingface dataset:
Directional Advisor Driven Rig and Directional Operation Integration
Authors: Hildebrand G. , Schultz H. , Torre A. M. , Olesen L.
Published: February 2018

In the North America Land market, drilling operations are typically conducted by a selection of different service companies. Each is responsible for a different aspect of the well construction process, and they must work together to deliver a successful well for the operator. This operational model can lead to overlaps and gaps across the various providers in terms of responsibilities and tasks. Due to differing skill sets across rig and directional personnel, integrating rig and directional execution has practically translated into drilling contractors establishing a directional company and providing both services. While this provides a single accountability point for both, it does not fundamentally change the operational model. A new approach to integrated operations is now possible with the assistance of directional advisor software, coupled with changes in rig driller capability and accountability.

This study demonstrated that by utilizing directional advisor software directional operations could be integrated with rig operations without negatively impacting well construction performance. Through the course of a fast-paced, twenty-two (22) well program in western Canada, directional operations were transitioned through a series of steps from a traditional model of two rigsite directional drillers and two rigsite measurement-while-drilling (MWD) engineers to an integrated and reduced crew model where all directional operations were directed from a remote operations center and directional steering was executed by the rig crew.
Twist Compensation Reduces Trajectory Tortuosity and Improves ROP
Authors: Kyllingstad Åge
Published: February 2018

Twist compensation is a new, patent applied technique for improving the performance of conventional directional drilling assemblies. It is a feed-forward control technique where the reactive twist is used for controlling the angular position of the top drive thus minimizing undesired variations of the tool face. The equilibrium reactive twist is calculated as the torsional drill string compliance multiplied by the applied bit torque. This torque is provided either by direct measurements or indirectly from the mud motor induced increase of standpipe pressure. Twist compensation makes it possible to optimize bit load and rate of penetration while keeping a good directional control. In addition to providing much higher penetration rates during sliding mode, it is also a mean to minimize the wellbore tortuosity.
Measuring Drilled Cuttings and Fluid Recovery by Real Time Mass Balance
Authors: Smith B. E. , Grubb S. A. , Smith M. B. , Eller J. G. , Connelly J. S.
Published: February 2018

A mass balance method of calculating drilled cuttings recovery and fluid loss/influx is presented. Field results are shown that illustrate hole cleaning effectiveness, hole enlargement, and wellbore breathing. A drilling fluid system including mass flow and density meters on the inlet and outlet of the circulating system is used to continuously measure and trend drilling fluid density, flow rate, and drilled cuttings recovery. Drilling fluid density measurements of the inlet and outlet flow streams are compensated for temperature and pressure and then used to calculate cuttings recovery based on the drilled rock density. Mass balance calculations also account for drill string fluid displacement and fluid seepage/loss/influx across the face of the borehole.
Reconstruction of Pipe Displacement Based on High-Frequency Triaxial Accelerometer Measurements
Authors: Cayeux Eric
Published: February 2018

Heavy vibrations in the bottom hole assembly (BHA) may cause permanent damage to the bit or other BHA components, like measurement while drilling (MWD) tools or rotary steerable systems (RSS). Tool- joints along the drill-string may get warned out by high levels of whirl along the drill-string. Repetitive shocks of drill-pipes against the formation may be the origin of wellbore instabilities or cause malfunctions of the communication network of wired drill-pipe high speed telemetry communication systems.

Because of all these potential problems, it is important to better understand how pipes move inside a wellbore. High frequency recordings of triaxial accelerometer measurements at different locations inside the BHA, or along the drill-string, open the possibility to reconstruct the actual displacement of drill-string tubulars. However, because accelerometer readings are taken in a reference frame that is not in uniform movement compared to a fixed referential, the readings are subject to complex effects of centrifugal, Coriolis and Euler accelerations that make the estimation of the pipe movement rather intricate.

Without considering these so-called fictitious accelerations, it is easy to misinterpret the actual movement of the accelerometers attached to a pipe. For that reason, a numerical method has been developed to calculate the displacement of the support of the accelerometers. To validate the numerical model, a laboratory setup has been built that allows for a precise control of the movement of an element that supports three triaxial accelerometers. The known displacements of the accelerometer support and the reconstructed displacements have been compared and a methodology has been developed to use the redundant measurements to reduce the uncertainty of the estimated movement resulting from inaccuracies around the exact position and orientation of the accelerometers relatively to its support.

Lately, several publications have reported results from high frequency triaxial measurements at different locations along the BHA and the drill-string, while others have pointed out the risk of misinterpretation associated with the existence of fictitious accelerations. This paper presents a validated numerical method that allows for an accurate reconstruction of the displacement of drill-string and BHA elements therefore providing a unified point of view to the problem of estimating drill-pipe displacements based on accelerometer measurements.
Dynamic Axially-Stiff String Model for Tripping Operations in Directional Wellbores
Authors: Zamanipour Z. , Miska S. Z. , Hariharan P. R.
Published: February 2018

The soft string model has been widely used for torque and drag calculations. Although several modifications have been developed, the standard model in the oil and gas industry is the static soft string model, in which the string is assumed to be motionless and its stiffness is neglected. In order to estimate more realistic and accurate calculation of drillstring loading, not only the acceleration, but also axial stiffness of the string must be considered in force calculations. In this paper, a dynamic, axially-stiff string model is presented for force calculations of drillstring in tripping operations.

The mathematical model is developed to include axial stiffness of the drillstring and acceleration into the soft string model by coupling mass-spring system with the soft string model. Moreover, static friction and drilling fluid drag are taken into account. The drillstring is considered to be a system of coupled oscillators subject to external forces. Then, the motion of the individual oscillator is governed by external forces and the forces applied by its two neighboring elements. In this model, the static friction effect is included as a constraint for initiation of motion.

The drillstring configuration is considered to be drillpipe, drillcollar, and directional assembly. The developed model ("new model") is implemented for tripping-out one stand in two ideal directional wellbores plus one field case wellbore trajectory. Axial force behavior shows a trend of acceleration that is similar to that observed with the previous dynamic soft string model ("previous model": SPE-173084-MS), and the first peak contains the effect of static friction. Displacement at the end of the string shows that the whole drillstring is in motion after few seconds. The axial force using the new model is compared to that (axial force) calculated using the previous model for two different cases. In the acceleration part of the motion, the new model shows a peak about 12% higher than the maximum load in the previous model which is due to the static friction force. In the constant velocity part of the motion, depending on the amount of damping, the new model can show a result similar to that of the previous model.

The new dynamic axially-stiff string model provides a more realistic prediction of hookload, and consequently more realistic loading of the hoisting equipment and fatigue life of the drillstring. Other applications of this model are for wellbore planning, drillstring design, optimization and automation of tripping operations.
A Method to Estimate Working Range of Vibrators
Authors: Zhang Yuan , Samuel Robello
Published: February 2018

Friction reduction devices in the form of vibrators are becoming more widely used in drilling operations because of their ability to create oscillation in the string, which can reduce the amount of friction force present. Ordinarily, the placement of vibrators is based on past field experience; an improper arrangement of vibrators, however, can reduce their efficiency and lead to possible tool damage. A proper model for estimating the working range for vibrators can enhance the efficiency and safety of the vibrator.

This paper presents a new method for predicting the working range for vibrators based on the stress wave theory. The proposed method uses the stress wave theory to calculate the vibration velocity. Beginning at the vibrator, the stress wave travels a lengthy distance in the string. The friction on the string, however, diminishes the stress wave energy until the vibration velocity reaches zero. The vibrator working range is defined as the string section with a non-zero oscillation velocity.

A set of equations to calculate the stress wave traveling distance is proposed in this paper. This model provides a theoretical prediction of the vibrator working range to effectively optimize vibrator use. The stress wave traveling distance predicted from this model is likely to be a linear relationship to the acceleration generated by the vibrator, which is similar to the results obtained in the field, and can be used to better determine the most effective placement for vibrators in horizontal wells.
Operators' Group, Rig Contractors, and OEM/Service Company Work to Solve Rig Data Quality Issues
Authors: Behounek M. , Nguyen D. , Halloran S. , Isbell M. , Mandava C. , Vinay N. , McMullen J. , Hoefling C.
Published: February 2018

In the current economic climate Operators must reduce drilling costs, so they are turning to well data analytics, real-time advisory, and automation systems to make sustainable improvements (Behounek et al. 2017). Rig surface sensor data is critical to improvement; however, documented issues with consistent, reliable, quality data complicates and delays the value from these systems. The Operators Group for Data Quality (OGDQ) seeks to accelerate the adoption of standardized key measurement specifications, data storage, transmission, transformation, and integration by working with Rig Contractors, Original Equipment Manufacturers (OEMs), and Service Companies. The OGDQ effort focuses on key measurements used for important drilling process decision making.

For this paper, the OGDQ worked with Rig Contractors and an OEM/Service Company to advance recommended data quality components in work processes and commercial agreements. By bringing transparency to the process, the authors hope to contribute to the efforts to address operational data quality issues and to drive alignment and improvements among Operators, Rig Contractors, OEMs, and Service Companies. This paper outlines an approach to putting data quality into practice, including initially identifying the problem, field verification, developing key measurement specifications, constructing framework components, and anticipating management of change issues.

Quality drilling data is essential to both rig and office personnel who are tasked with decision making for fast-paced well programs. Quality drilling data is also essential for the data-driven systems developed to assist in managing well delivery. Rig studies show several cases where Operators independently uncovered systematic errors for 10 key measurements used for drilling process decision making (Zenero 2014; Zenero et al. 2016). The 10 key measurements are listed as follows: Rotary/Top Drive TorqueJoint Makeup/Breakout TorqueHookloadRotary/Top Drive Rotational SpeedStand Pipe PressureDrilling Fluid Pump RateDrilling Fluid Tank/Pit VolumeDrilling Fluid DensityDrilling Fluid ViscosityBlock Position

Widespread agreement on data quality practices among Operators, Rig Contractors, OEMs, and Service Companies is crucial for their quick adoption, and an industry-wide approach has a profound effect on drilling operations. Widely adopted practices will support and drive requirements for sensor quality, calibration, field verification, and maintenance. This standardization will, in turn, significantly enable improved drilling operations, drilling analysis, and big data processing by correcting many errors resulting from poor data quality. This paper outlines the methodology used to develop a guide for commercial drilling components, and illustrates the application of this guide with selected drilling data use cases.
Robust MMH Drilling Fluid Mitigates Losses, Eliminates Casing Interval on 200+ Wells in the Permian Basin
Authors: Offenbacher M. , Erick N. , Christiansen M. , Smith C. , Barnard T. , Farrell R.
Published: February 2018

Mixed metal hydroxide (MMH) drilling fluid technology dates back nearly thirty years (Burba III et al. 1988), but its adoption remains limited by the expertise required to deploy the system and the sensitivity of the system to contaminants. In the Permian Basin (specifically the Delaware Basin), a robust MMH formulation mitigates losses and enables control of mud weight through a challenging salt layer of 2,000 to 5,000 feet, eliminating a casing interval. This success has been repeated on over 200+ wells with continuous optimization.

MMH systems provide a unique rheological profile as the net positively charged MMH crystals form a complex with negatively charged bentonite, resulting in near instantaneous gel strength at low shear while providing typical flow properties and pump pressures at high shear. MMH applications range from improved suspension during milling operations to minimizing losses in highly fractured formations. Historically, MMH properties break in the presence of anionic materials, such as coal, deflocculants, anionic polymers as well as at elevated salinity. The robust MMH system discussed offers greater stability and lower risk of failure associated with a variety of contaminants.

The robust MMH system was deployed to minimize washout in the salt as the highly thixotropic fluid is near static under the low shear conditions near the wellbore. Without the turbulence of conventional fluids, minimal salt incorporation results in near-gauge wellbores and stable fluid density. The original gel system in turbulent flow provides the required properties for drilling, but salt incorporation from the formation causes not only washouts but escalating density.

Conventional systems require dilution to maintain density as the salt formation blends with the drilling fluid and elevates density. The MMH system minimizes salt incorporation and allows greater flexibility with increased density as mud density induced losses were less frequent due to its high viscosity at low shear. It is estimated the MMH system performs at +0.2-0.4 lbm/gal higher mud weight than a conventional system before losses occur as the properties of MMH systems inherently limit fluid invasion through fractures. The greater operational window provides more flexibility to insure well integrity.

Overall, a combination of proper fluid selection and execution with continuous operational improvement yields great benefits, lowering overall drilling costs 40% and drilling days by 50%. A 50% reduction in dilution volumes and easier fluid management benefits were complemented by lower waste volumes and the elimination of earthen pits.
Qualification Methodology for Advanced Rotary Shouldered Threaded Connections
Authors: Du Michael , Song Fei , Li Ke , Collins Tony , Moriarty Keith
Published: February 2018

A qualification methodology for advanced rotary shouldered threaded connections is presented. It covers physical tests of connection prototypes and virtual tests with modeling and simulation techniques.

The methodology had been applied to qualify a fatigue-resistant threaded connection design that has recently been released for field testing. The qualification process consists of in-lab makeup and breakout tests, on-rig makeup and breakout tests, sealability tests, fatigue tests, torsional yield limit tests, and tensile capacity tests.

During the development of the design, modeling and simulation techniques were extensively used to optimize the design prior to physical prototyping and testing. Some of the qualification tests, such as torsional yield limit tests and tensile capacity tests, were carried out by using advanced modeling and simulation techniques. Because fatigue tests under nominal loads take a long time to complete, accelerated fatigue tests under calculated overloads were conducted to assess whether the design would meet the fatigue life requirements with low risk. After positive results were obtained from the accelerated fatigue tests, nominal loads required by the product specifications were then applied to complete the qualification fatigue tests. It was found from the experimental results that the predicted performance of the connections, such as fatigue life, critical sealing pressure, and breakout torque, matched with the physical test results well.

Despite the fact that numerous rotary shouldered threaded connection designs have been developed in the oil and gas industry, there has been no formally defined qualification procedure for such designs. The objective of this paper is to introduce, for the first time, a systematic and complete qualification procedure for rotary shouldered threaded connections.
Minimizing the Risk of Casing Failures Across Plastic Salts with Tailored Cements and Software Analysis: Case Histories from the Williston Basin, North Dakota
Authors: Pereira Francis , Jandhyala Siva Rama
Published: February 2018

A significant challenge associated with cementing across salt zones in the Williston basin is mitigating risks of casing collapse or deformation. An operator (Operator A) in this area reported that six of their old wells experienced casing failures/deformation caused by salt creep. Post-job analysis showed that these older wells used conventional cement designs. Based on the lessons learned from successful cement jobs for other operators in the same region and knowledge about salt creep loads, tailored fluid systems were proposed with optimized job design and placement procedures for Operator A's upcoming wells. This study demonstrates the benefits of the proposed modifications by comparing the logs and outcomes of old and new wells. Through post-job analysis, this study highlights the importance of using cementing simulation and modeling software to design a dependable barrier.

The casing inspection logs and cement bond logs across salts from old wells indicated that deformation occurred within a few weeks of cementing. The use of a tailored cement system with enhanced mechanical properties, along with specialized spacer systems and effective centralization, showed improvement in bond logs, no casing deformation, and better casing-cement bonding in the new wells for Operator A. Pre-job simulations were performed using in-house cementing software to verify the cement job and to help ensure that the cement was effectively placed in the annulus.

Cement sheath integrity modeling software was used to simulate the actual exerted loads from plastic salt formations and subsequent drilling, completion, and production operations. This software uses a semi-empirical creep law that describes the creep process of a wide variety of salts. The cement system with enhanced mechanical properties showed sufficient endurance to provide a dependable barrier to the salt creep loads experienced in Williston basin wells. Although the use of salt vs. salt-free slurries is debated for salt zone cementing, this study shows that salt-free cements with enhanced mechanical properties can be used successfully when there is no risk of cement gelation during placement. North Dakota salts principally contain halite (NaCl), which does not pose a risk of gelation.

The case histories and field studies discussed establish cement systems and practices that can help to minimize the risk of casing deformation and improve the cement bond across salt zones in the Williston basin in North Dakota. This tailoring tool, with its unique ability to exert salt creep loads, helps to minimize the risk of cement sheath failure through tailored barrier designs. This information should help the petroleum industry to address long-term well integrity problems associated with cementing across plastic salts.
An Algorithm to Automatically Zero Weight on Bit and Differential Pressure and Resulting Improvements in Data Quality
Authors: Neufeldt Adam C. , Lai Stephen W. , Kristjansson Sean D.
Published: February 2018

Weight on bit (WOB) and differential pressure (DIFP) are two essential parameters derived from surface sensors during the drilling process. However, there can be significant errors in these measurements due to improper zeroing of these traces. Regular zeroing of WOB is important to ensure that it is calibrated for additional stands that have been added to the drill string. Similarly, regular zeroing of DIFP is important to ensure that added hydrostatic pressure, which increases with depth, is taken into account, and to ensure that DIFP has been calibrated to the correct pump rate. In this paper, we quantify the errors due to forgotten and incorrect zeroing, and discuss an algorithm which was developed to automatically zero WOB and DIFP to eliminate these errors.

This study has two main sections. In the first section, the current practice of zeroing WOB (prior to rotary drilling) is analyzed in 40 onshore wells. It is found for 86% of all stands, WOB is either zeroed incorrectly or not at all. An algorithm is developed to determine the appropriate time to perform the zero WOB operation. Using this algorithm, it is found that the average WOB error per stand due to improper zeroing is 16.8% and 17.6% in the vertical and lateral wellbore sections respectively. Further, it was found that repeated forgotten zeroes could result in large errors, particularly in the vertical where 8% of stands have WOB inaccuracies of over 30%. In the second section, the analysis is repeated for DIFP and it is found that zeroing DIFP is forgotten in 51% of all stands, resulting in errors of 17.5% and 8.9% in the vertical and lateral, respectively. In the vertical 9.9% of stands have DIFP inaccuracies of over 30% due to forgotten zeroing. Applying these algorithms to historic data can eliminate these errors, and improve the effectiveness of data-based drilling optimization and analytics. Further, these algorithms could be implemented in an electronic drilling recorder (EDR) to improve the quality of real-time data at the rig.
Optimizing the Deepwater Completion Process: Case History of the Tamar 8 Completion Design, Execution and Initial Performance - Offshore Israel
Authors: Healy John , Waggoner Steven M. , Magin Ian , Beavers Matt , Williams Kevin , Hebert Russell
Published: February 2018

A case history from Offshore Israel is presented that describes the successful delivery of one (1) ultra-high rate gas well (+250 MMscf/D) completed in a significant (11.5 TCF) gas field with 7 in. production tubing and an Open Hole Gravel Pack (OHGP). The well described, Tamar 8, was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time. A novel multi-purpose integrated tool string design enabled the sequential drilling of the pilot hole, underreaming of the reservoir section, several fluid displacements and casing cleaning in a single trip. The completions were installed with minimal operational issues (completion Non-Productive Time, NPT = 2.6%). Production commenced in April 2017. The initial completion productivity of this new well exceeded the five wells completed in 2012. Peak production rate to date is 281 MMscf/D.
Footage in STACK Lateral of Oklahoma Increased by 185% through New Non-Planar PDC Cutter Geometry Development and Implementation
Authors: Lyons N. , Izbinski K. , Pauli A. , Gavia D. , Hoffman M. , Cantrell B. , Bryant S.
Published: February 2018

The development of improved synthesis techniques for polycrystalline diamond compacts (PDC) positively impacted fixed cutter drill bit performance. Coupled with these advances, recent developments in cutter geometry show improved cutter performance in many applications. Laboratory and field testing has demonstrated that modifying the face geometry of the PDC cutter used in a fixed cutter bit is one of the most direct ways to affect the efficiency and longevity of the bit's cutting structure. This paper describes a new non-planar cutter face geometry that has increased footage drilled, rate of penetration (ROP), and improved the bit dull condition in the Meramec formation in western Oklahoma's STACK play.

A drilling mechanics focused team created a finite element analysis (FEA) model of the rock cutting process to optimize cutter face geometry for improved cutting efficiency. The new non-planar geometry enabled better cutting efficiency and improved cutter cooling. Multiple lab tests were then used to verify the model's predictions.

Results from single cutter lab tests showed an 11% increase in cutting distance as measured in a vertical turret lathe test, a 30% decrease in cutting edge temperature from a pressurized cutting test, and a 10% increase in load capacity compared to a previous non-planar geometry in a face load test. Full-scale pressurized drilling tests in the lab showed that a PDC bit with the new geometry was 15% less aggressive with equivalent-to-lower mechanical specific energy (MSE) when compared to the same PDC bit with a previous generation non-planar cutter.

Field tests were conducted with the new non-planar geometry applied to a commercial 0.529 inch [13mm] cutter on a standard 8-1/2 in. drill bit design used in the Meramec Lateral application. The paper reviews in detail three test cases in this multiple bit lateral section using the same bit design with and without the new non-planar cutters. In two test wells, we saw direct improvement of 185% distance drilled on average and an18.3% boost in ROP. At least 17 bit runs have been completed in this application using the new non-planar feature, proving it to be a beneficial enhancement. Similar performance improvement has been observed in other applications as well.

The optimized cutter geometry has led to further and faster runs, resulting in significant time savings and improved consistency. The use of advanced cutter geometries provides a significant boost in drilling performance beyond that normally achieved through fixed cutter bit design optimization and materials improvements.
HPHT Wells Spudded Utilising a Rotary Steerable System Below a 26-in × 36-in Hole Opener to Improve Tophole Drilling Performance
Authors: Hyland K. B. , Laing M. , Mathieson G. , O'Neill D. , Boyce F. , Keen A. , Tarn A. , Milne R.
Published: February 2018

This paper presents the results and lessons learned to improve the performance while drilling the 36-in tophole sections in the Culzean field field HPHT development. Seven 36-in sections were drilled in a batch sequence with less than four days between wells. This presented a challenge in quickly identifying operational and equipment changes necessary to improve performance in each subsequent well.

The first well was drilled with no operational issues; however, the rate of penetration (ROP) was lower than had been expected for this area. Borehole inclination increased in the following two wells and required significant reaming to reduce the inclination observed. Damage was also observed to the 26-in × 36-in Hole Opener, suspected to be due to the additional reaming work.

As the reaming impacted operational efficiency and equipment, a re-design of the bottomhole assembly (BHA) was initiated. To maintain verticality without the need to backream a 17.5-in Rotary Steerable System (RSS) was added between the 17.5-in Bit and the 26-in × 36-in staged Hole Opener on the fourth well. The RSS system was then used in this configuration for the remaining three wells, resulting in a 24% improvement in drilling performance over the baseline well.
Evaluation of a Casing-in-Casing Refracturing Operation in the Burleson County Eagle Ford Formation
Authors: Elbel Brittany , Modeland Neil , Habachy Steve , Nabors Johnny , Brannon Richard
Published: February 2018

Throughout the years, evolving industry practices have inspired new technology, and novel technology developments have led to new industry practices. This cycle continues, particularly since the industry has evolved to horizontal unconventional wells as one of its primary development mainstays. While unconventional fields progress beyond the early stages of development, the original wells in the field become candidates for mature asset considerations of how to economically extend the life of the aging wells. Completion design evolution in each of the major shale plays suggests that the early-time stimulations were inadequate for optimum recovery. Long laterals with reservoir exposure spanning across thousands of feet and having hundreds of perforation holes make precision during conventional restimulation methods complicated and/or costly, often with unpredictable production results.

Advancements in cement slurries and wellbore construction practices have enabled the development of a refracturing methodology that allows for complete renewal of stage isolation along the wellbore. Through installation of a smaller casing string inside a legacy well's existing production casing and effective cement isolation in the annulus, an existing wellbore can be transformed into a new closed system that can be subjected to a new completion design providing increased and accelerated reserves. Specialized casing sizes might be necessary and the refracturing completion might be rate-limited in comparison to a new drill completion, but the process has confirmed execution repeatability and less variance in production predictability than other refracturing techniques.

The successful implementation and economic return of this casing-in-casing refracturing method has caused a growth in popularity of this style of refracturing, both in total well count and in quantity of participating operators. In the Burleson County Eagle Ford formation, multiple recompletions using this technique have been performed. Of the six casing-in-casing refractures performed, five had sufficient production time to derive an average estimated ultimate recovery (EUR) increase of approximately 140% in comparison to the original well EUR in the detailed Eagle Ford acreage.
Design and Manufacture of an Original Equipment Manufacturer Deepwater Managed Pressure Drilling Integrated Solution
Authors: Dow B. , Kamps C. , Baker J. , Likki S. , Guzman C. , Liezenberg B. , Guidry J.
Published: February 2018

Objectives/Scope

Industry deepwater exploration and development continues to encounter complex reservoir challenges, demanding an alternative to conventional drilling. Applied backpressure Managed Pressure Drilling has proven to be a solution suitable for similar challenges on land and shallow water. Some projects around the world have expanded the application to deepwater. The degree of complexity for such a solution in deepwater is such that it remains niche. To deliver a successful solution, operators have relied on integrating components from multiple providers to ensure a complete system. The package is customized for each drilling rig, further adding complexity to the integration exercise. Because each component of the system is delivered from separate suppliers, the certification of the system by an appropriate agency must then be approved on a case-by-case basis to guarantee insurability of the offshore drilling unit. Beyond certification, the ability to optimize the package was limited by barriers inherent in a multi-supplier solution.

Methods, Procedures, Process

In 2016, a drilling contractor requested an integrated deepwater MPD package, aimed at adding versatility to their rig fleet. A fully integrated, single Original Equipment Manufacturer solution was designed and manufactured to meet the objective of MPD enablement for a package designed to move throughout the fleet. The design, manufacture, install and system integrity test of all components for two drilling rigs took place over a 12-month period. The system was witnessed and certified by DNV GL. First field deployment took place in late 2017.

Results, Observations, Conclusions

This paper describes the complexities of delivering a fully integrated deepwater MPD package, including RCD, riser gas handling system, MPD control system and pressure and flow management hardware as a first artifact with DNV GL OS-E101 classification.

Novel/Additive Information

The solution described is an industry first complete OEM deepwater MPD system.
Stabilizer Selection Based on Physics and Lessons Learned
Authors: Pastusek Paul E.
Published: February 2018

The objective of this paper is to share lessons on stabilizer selection with the industry that minimize drilling and tripping problems. Ideally the stabilizers and BHA will drill a round, ledge free hole, without patterns, with minimum vibration, minimum unplanned dog legs, that reach all directional targets in one run per section. They should not constrain ROP, be able to trip in and out on elevators past ledges and hole irregularities without the need for rotation.

These lessons were based on a number of forensics observations while drilling and tripping and a physical understanding of the BHA and its effects on vibrations, trajectory, and tripping in high angle holes.

A draft of these lessons were presented at a SPE Gulf Coast section meeting in 2015 and were sent to all that requested them as well as suppliers used by this operator for comments and suggestions. It is hoped that this publication and the reasoning behind the lessons will help improve this often neglected tool.

A few significant events initiated this work. The first was a mechanical sticking event in 17 ½ inch hole where the BHA could be rotated and moved downward, but hung up trying to trip out. The formation being drilled at high angle was a vuggy limestone. Inspection of the BHA and stabilizer design found that there was a sharp, 75 degree, transition taper on one of the rotary steerable system stabilizers. This coupled with a formation ledge made it impossible to ream or trip, resulting in a lost BHA and sidetrack.

The second key event was a 6 ¾ BHA that required control drilling to avoid plugging the near bit stabilizer. This showed up as an increase in standpipe pressure and a decrease in an annular pressure gauge located above this stabilizer. The root cause was low bypass area on the near bit stabilizer.

The third event was in 12 ¼ inch high angle hole in soft rock. This required circulation on the trip out of the hole on some wells and not others. The wells requiring circulation on the trip out had high spiral stabilizers that packed off rather than passing the cuttings bed.

A practical set of lessons have been developed that may be used as a starting point for developing industry best practices. The physics behind these lessons are given so that they can be improved over time. One improvement expected is the requirement for low coefficient of friction on the stabilizer OD to minimize whirl and on the end tapers to reduce tripping hang up.
Well Control Simulator: Enhancing Models with Compositional PVT Models and Kinetics
Authors: Bjørkevoll Knut S. , Skogestad Jan Ole , Frøyen Johnny , Linga Harald
Published: February 2018

Details of the interaction between natural gas and oil in drilling fluids currently not taken into account, will in extreme cases be significant for the safety of drilling and well control operations. The paper describes such effects, in particular time dependence (kinetics) and compositional PVT with dense phase included. The importance of validation and tuning of PVT calculations, even when using state-of-art tools, is demonstrated by integrating new methods in a well control simulator.

We consider sub-models for kinetics (time dependence of gas dissolution and boiling) and compositional PVT for the drilling fluid-natural gas mixture, and study different effects and assumptions numerically by integration in a well control simulator. Available laboratory data are used for model development and tuning of existing software. The dense phase may be important to consider in HPHT wells, where the conditions allow for the drilling fluid-gas mixture to exceed the critical point. This influences the gas absorption capability of the drilling fluid, as well as the density.

The paper illustrates the impact of kinetics and improved PVT calculations through a sensitivity analysis using realistic well and fluid data. Two specific base-oils, a refined mineral oil and a linear paraffin, are used in combination with methane gas. The simulations show how kinetic effects can be important in some cases, both for early interpretation of a kick and for the response seen at surface as gas approaches and enters topside equipment. Furthermore, it demonstrates that dense phase effects can be significant, and that even state-of-art PVT software requires tuning when used with new combinations of oil-base fluids and hydrocarbon gases. Although the effects discussed are small compared to safety margins for many wells, ignorance may cause drilling teams to run into severe risks without knowing in advance for other wells.

Combining advanced PVT models capable of representing dense phase behavior and a kinetics model with hydraulic flow modelling represents a leap forward in simulation of well control events. In addition, the importance of tuning adds valuable knowledge. These elements enable earlier detection and safer handling, thus increasing the safety on the rig.
Reducing Stick-Slip by Avoiding Auto-Driller Control Dysfunction
Authors: Adam Derek
Published: February 2018

Analysis of historical drilling data in the Delaware Basin revealed stick-slip was being initiated by the rig control system. It was determined that a weight-on-bit (WOB) road map with calibrated range values delivered near-maximum rate of penetration (ROP) and reduced stick-slip. This was achieved by simplifying the auto-driller's parameter limits and avoiding differential pressure control. Details of the statistical analysis process and results from field trials is presented and compared to historical performance.

The road map was developed using data from top performing offset wells. The standard deviation of the auto-driller's active control limiters was cross-plotted against the standard deviation of the ROP. Intervals in which the differential pressure was the primary control or the ROP range was excessive displayed a high standard deviation, indicating unstable control behavior. Data from the non-dysfunctional areas determined the WOB and ROP ranges to be targeted through an interval. Use of these range limits steadied the application of WOB and reduced the need to control the auto-driller via differential pressure.

Wells using the parameter road map were compared to high-performing offsets. The comparative analysis focused on ROP, mechanical specific energy (MSE), downhole accelerations, and bit damage. Performance in formations known to cause dysfunction are highlighted. Benefits have been observed in the rotary steerable control collar RPM data. Depth-of-cut (DOC) through the Brushy Canyon was improved by use of the road map. Traditional auto-driller limiters (torque and differential pressure) were avoided due to the limits of the drilling system embedded within the road map's setpoints. Data are presented showing that differential pressure control can result in stick-slip. This dysfunction is avoidable with the use of a road map employing accurate range values for WOB and ROP to control the auto-driller.

Improved auto-driller range management addressed a specific source of dysfunction and positively impacted performance at the bit. The visual road map conveyed WOB and ROP guidance directly to the driller, which accelerated the rig's learning curve. When combined, the product of these data-driven concepts increased bit life and ROP.
Probability of Wellbore Intercept Made Easy
Authors: Codling Jeremy
Published: February 2018

Wellbore intercept probability calculations are important not only for avoiding collisions but also for relief-well planning and planning for wellbore reentry in abandonment projects. This study reviews the current methods for calculating probability and their sensitivity to the input variables. A probability of intercept calculation is presented that is proven, robust, and can be implemented in a spreadsheet as input-wellbore positions and survey-error dimensions.

Given the lack of availability of empirical wellbore collision-frequency data, it was necessary to model the wellbore-intercept scenario using a Monte Carlo simulator constructed by breaking the two wellbores into short segments. The validity of the simulator is highly sensitive to the probability distribution of the input-survey errors. The input-probability distribution of well separations in the high side and lateral directions is determined from survey-comparison studies for both systematic and random-error sources. The simulator is used to compare the accuracy and reliability of different probability integration types and sensitivity to the input data and distribution of errors.

It is observed from survey comparisons that the distribution of survey inclination and azimuth errors behave as "heavy tailed" probability distributions such as Laplace or Student's t. This increases the probability of intercept at higher sigma levels than the previously assumed normal distribution.

The results of this study exhibit the sensitivity of the probability result to the degree of sophistication of the probability calculation from simple one-dimensional (1D) projection to three-dimensional (3D) integration of probability density. There is a law of diminishing returns with the sensitivity of complex models being lost in the reliability of the input-error values and assumptions on probability distributions.

One observation is that there is no "pedal curve" effect for high-angle well crossings. The simple point-to-point collision calculations using this vector method do not include the confidence in the relative direction of the two wellbores. Therefore, probability calculations and separation-factor calculations that engage the pedal-curve distances are overly conservative.

A reliable prediction of wellbore-intercept probability is achieved using a relatively simple method. This study shows the importance of the angle of intercept to enhance interception probability for relief wells and abandonment re-entry operations.
Attenuating Heave-Induced Pressure Oscillations using Automated Down-hole Choking
Authors: Kvernland M. , Christensen M. Ø. , Borgen H. , Godhavn J.-M. , Aamo O. M. , Sangesland S.
Published: February 2018

In this paper, a new tool to be placed in the bottomhole assembly (BHA) is introduced for the purpose of counteracting heave-induced down-hole pressure oscillations in offshore drilling. The tool contains a control choke, sensors and computing capability, and will operate autonomously with minimal implications for standard drilling procedures. A small-scale prototype is developed and successfully tested in laboratory experiments showing significant reduction in down-hole pressure oscillations. Realistic, full-scale cases investigated using computer simulations also show good performance. The paper gives a description of the small-scale lab as well as the mathematical model used for the computer simulations. A full-size autonomous choke prototype is currently being constructed for further testing under more realistic conditions. Design aspects of the prototype are presented in the paper.
Case Study: Reactive Torque Failure Prevention
Authors: Pettit G.
Published: February 2018

Reactive torque failures occur when an underreamer or hole opener stalls suddenly. The right-handed momentum in the components underneath the stalled tool applies a left-handed torque to the connections. If this left-handed torque is high enough, the connection can back off.

In fact, an operator had a reactive torque failure in just this manner. We study that failure as an example in this paper, outlining the way to prevent it in the future. In short, the makeup torque applied to the connection must remain higher than the left-handed torque that the tool might see. While simple enough, the complication comes when trying to calculate the magnitude of left-handed torque under a stalled underreamer.

The simplest method is to apply an energy approach when calculating the left-handed torque. This is straightforward mathematically, and in most cases it is conservative due to the lossless assumptions that are used.

Unfortunately it is becoming common that something more sophisticated is necessary. This is due to the fact that vibrations are typically ignored in a simple energy model. Since in many holes friction will quickly damp out any vibrations caused, this often does not cause problems. However, if reaming a very big hole—as was the case in our study, and is often true of the larger hole sizes in deepwater operations—the friction may be low enough that torsional vibrations will play a significant role.

In order to calculate the reactive torque that might be applied in these latter instances, a numerical approach must be employed that considers the torsional shock wave applied to the components underneath the stalled hole opener.

This paper considers these different mathematical approaches, particularly as they were applied to both the reactive torque failure and the resulting preventative design processes.