bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Interbedded and Hard Formations with PDC Bits Considering Structural Integrity Limits
Authors: Pastusek Paul , Sanderson Derek , Minkevicius Andrius , Blakeman Zachary , Bailey Jeff 
Published: February 2018

Abstract
Although PDC bits dominate the footage drilled in the oilfield, transitions at interbedded formations and high lateral vibrations are still problematic for PDC bits and reamers.
This paper describes design features, operational parameters, and procedures found to substantially reduce cutter damage, often allowing the section to be drilled in one run, resulting in significant cost savings. It also covers data analysis needed to determine if interfacial severity is the key limiter in a given application.
Time and depth based drilling mechanics data are used to determine the sections of the hole that cause the observed cutter damage and optimize parameters.
Forensics analysis is used to determine the type of cutter damage seen when drilling these formation intervals. Structural integrity of the cutters is estimated from forensics analysis, lab tests, as well as stress analysis of cutters loaded to replicate the observed damage.
Review of the bit and BHA designs often show opportunities for design improvements and cutter selection. Drilling parameters are identified to keep the bit and cutters below the structural integrity limit.
Drilling interbedded formations causes the cutters near the nose of the profile to fracture from tangential overload, through the diamond table and carbide support. This is a significantly different failure mode than the cutter spalling fracture on the bit shoulder seen with bit whirl.
Review of drilling mechanics data showed significant reamer damage and reductions in ROP at the formation transitions when entering salt with a bit and reamer combination. Drilling parameter and BHA design changes improved drilling performance in these transitions.
Finite element studies were requested of bit vendors to estimate the structural integrity of cutters loaded in the tangential direction. Independently, forensic analysis was also used to estimate the range of loads and depth of cut that cause structural overload.
Drilling interbedded formations and transitions at a controlled depth of cut, as opposed to weight on bit control, avoids exceeding the structural limit of the cutters while only part of the cutting structure is drilling the harder formation and the rest of the profile is in softer formation. Depth of cut elements are engaged to keep the bit stable while control drilling. Other design changes are considered to eliminate cutter overload using existing designs as a starting point.
The structural integrity concept applies to hard, interbedded, conglomerate and/or vuggy formations, as well as formation transitions and shoe drill out and milling operations. Effective drilling of such interfaces can be achieved by knowing the depth of cut that can be sustained in the harder formation, while avoiding damage from vibrations. Cutters must be selected for fracture resistance in the tangential direction, and many bit vendors do not yet track this property.
Anti-Collision Best Practices Developed for Horizontal Drilling Across Pre-Existing Horizontal Wellbores
Authors: Britton E. , Grande R. 
Published: February 2018

Abstract
This paper focuses on anti-collision best practices developed and implemented by Liberty Resources for horizontal drilling across pre-existing horizontal wellbores within the same horizon in the Williston Basin. These multidisciplinary collaborative workflows have allowed Liberty Resources to successfully drill multiple complex horizontal wellbores traversing as close as 10 feet wellbore-to-wellbore to existing laterals.
As the horizontal infill development of unconventional reservoirs progresses, complex wellbore trajectories with heightened collision concerns will be required. To achieve this requires advancing the industry's anti-collision standard practices with new and more precise anti-collision methods, detailed planning, and near perfect execution. In the Williston Basin alone there are over 13,000 vertical wells, 15,000 horizontal wells, and over 1,000 re-entry and directional wells drilled to date, with the first horizontal wells introduced to the basin over 30 years ago. Historically, the horizontal wells were drilled using a vast array of well designs and orientations due to the limitations of technology, industry practices and standards, and the insufficient understanding of the reservoir. Advancements in drilling and completions technologies and a better understanding of the reservoir now allow leases to be reassessed for infill potential. This increased infill development has led to increasingly complex wellbore trajectories with collision concerns not only for existing vertical wellbores but now also for existing horizontal wellbores within the same or proximal horizons.
The anti-collision best practices include directional and geologic planning considerations, operational tolerances and requirements including zonal determination, communication protocols, and risk management practices. Creating a broad framework that allows for flexibility to adjust for distinct operational constraints.
These workflows and tolerances have been implemented in three horizontal wellbores traversing seven same-formation pre-existing horizontal wellbores. The anti-collision method was successfully applied in both the Middle Bakken and Three Forks formations, each with their own varied and unique geologic characteristics, demonstrating applicability for a wide range of reservoirs. The ability to execute complex wellbores opens new opportunities to access additional resources in previously considered "fully developed" acreage.
The methods presented in this paper have allowed the routine drilling of horizontal laterals as close as 10 feet to existing laterals. This technology can be applied to a variety of reservoirs opening new opportunities to access additional resources previously considered unrecoverable due to existing wellbores.
Modeling of Cuttings Lag Distribution in Directional Drilling to Evaluate Depth Resolution of Mud Logging
Authors: Naganawa Shigemi , Suzuki Manabu , Ikeda Kenji , Inada Norihito , Sato Ryosuke 
Published: February 2018

Abstract
Dispersion of cuttings transport velocity limits the depth resolution in mud logging. An attempt to model the cuttings lag depth distribution caused by the dispersion of cuttings transport velocity in directional drilling is presented. The depth resolution of mud logging in directional and horizontal wells is evaluated based on the cuttings lag experiments and lag depth simulations using the developed model. The approach of cuttings lag calculation is based on the previously developed complete physical model of transient cuttings transport behavior in directional drilling. The lag distribution is modeled using the lognormal distribution probability density function. The parameters of the distribution function are determined by lag time measurement experiments for various hole inclination angles using a large-scale cuttings transport flow loop apparatus. The implementation of lag depth calculation can be generally achieved by convolving the lag distribution functions determined for each hole section with different inclination angles. In this study, however, the linear combination of distribution functions is mathematically considered for simplicity.
Lag depth simulation studies are presented for a realistic model directional well based on a field data with consideration of variation in rate of penetration. The significant finding is that cuttings sampled at the surface can be contaminated by cuttings originated from other unintended depths to the extent being not negligible compared to the typical sampling interval of 30 ft or 10 m. This tendency of smearing in the formations and depths from which the sampled cuttings are originated would be significant if the high inclination or horizontal hole section exceeds a certain length depending on the rate of penetration. The presented approach has the ability to quantitatively evaluate the uncertainty in the depth resolution of mud logging that is crucial for improving the lateral quality of reservoir characterization which can be beneficial such as in shale oil and gas projects.
The Impact of Molecular Diffusion of Methane into Wells with Oil Based Mud
Authors: Petersen Johnny 
Published: February 2018

Abstract
A model of the diffusion of methane into a wellbore in overbalance with Oil Based Mud is described. In some situations, methane diffusion may cause unexpected gas in riser and well control problems. The situation when the OBM contaminated with diffused methane is circulated is simulated. The model has been used to analyze measurements of hydrocarbon obtained during drilling and circulation in an off-shore well in the North Sea, showing promising agreement with the model.
The tools used are: a) a finite difference diffusion program that simulates the diffusion process of methane molecules from the formation, through the mud invasion zone and into the base oil in the well bore, and b) a finite difference dynamic hydraulics model with modules dealing with the interaction of hydrocarbons entering the mud from the formation and the base oil in the mud.
The lighter hydrocarbons in OBM from the well were measured using FID gas chromatographs capable of accurately measuring the amount of C1 through C5 continuously. The measurements were analyzed using a PVT simulation program.
The diffusion was simulated in two positions in the well; the two days waiting for the 13 5/8" liner, 1850 m TVD; and the four days waiting for pipe at full depth, 4500 m TVD. The inputs to the diffusion model were based on measurements obtained while drilling in the two depths. The hydrocarbon measurements from circulations after the two and four days were compared with the amounts provided by the diffusion theory.
The distribution of the light hydrocarbon elements obtained during drilling through the formation and circulation after the delay periods, were compared. After the delay period, the relative amount of methane (compared with ethane, propane, etc.) was substantially greater. This is because methane has greater diffusion coefficient than the "larger" hydrocarbon elements.
The potential problems of having diffused gas in the base oil are shown using a hypothetical well where the OBM has been left overbalanced for days in a one kilometer long horizontal reservoir section. The contaminated OBM is circulated through the riser, and the low level of methane produces a domino-effect as it starts to boil out in the riser.
In-line gas-chromatograph measurements have provided information that shows the diffusion of methane into OBM while overbalanced.
This model used together with in-line gas-chromatograph measurements will provide additional insight in how light hydrocarbons end up in Oil Based Mud. The dynamic hydraulics model can be used to show the safety limit when leaving the well without circulation.
CFD Hydrodynamic Performance Comparison between Conventional and VIV-Mitigating Buoyancy Modules
Authors: Lai L. S. 
Published: February 2018

Abstract
Vortex-induced vibration (VIV) is a significant factor in causing cyclic stress and fatigue damage in drilling risers. A new design of drill riser buoyancy is introduced with tri-helical grooves formed into the module to mitigate against VIV. The focus of this work is to characterize the hydrodynamic performance improvement of this new design helically grooved buoyancy over the conventional buoyancy design.
Computational fluid dynamics (CFD) is employed to simulate the buoyancy module hydrodynamic behavior in 3-d space. A current speed representative of offshore environment corresponding to Re = 106 is considered using a Reynolds-averaged (k-epsilon) turbulence model. This methodology is based on previously validated domain, mesh and temporal independence studies for a circular cylinder that also showed agreement with published literature. The hydrodynamic performance is characterized primarily by the in-line and cross-flow drag coefficients Cdx and Cdy.
For the helical buoyancy, Cdx is benchmarked between CFD simulation and physical town tank testing which showed similar results. Direct comparison of Cdx for the static buoyancy module (bluff body) sees Cdx being higher for the helical form compared to the circular form due to the circular form's inherent drag crisis characteristic. However simply comparing Cdx would be erroneous. A complete hydrodynamic performance representation requires the consideration of the full flow field and Cdy. This exposes that periodic vortex shedding occurs for the circular form but is mitigated for the helical form. Vortex shedding occurring for the circular form results in significantly larger Cdy values as well as potentially larger dynamic Cdx for a non-fixed bluff body. For the helically grooved form, vortex shedding is successfully mitigated and Cdy is significantly lower. The helical grooves form channels that allow flow along different directions away from the free-field flow directions which function to disrupt the downstream regular flow order. This prevents the regular formation of vortex shedding in the wake of the riser which is a pre-cursor to VIV. The omnidirectional nature of the helical grooves also ensures this mechanism for breaking regular flow is achievable regardless of the environmental current direction acting on the riser.
VIV is an increasingly significant problem with deep-water exploration in harsh weather environments. The new buoyancy design provides passive vortex shedding mitigation to top-tensioned risers which would reduce the propensity of VIV occurrence.
Modified Casing Design and Low-Viscosity Wellbore Strengthening LVWS System Overcame San Andres H2S Water Flow Challenges in Midland Basin
Authors: Chen Z. , Snider C. , Linnerud B. , Griffin L. , Breeding D. 
Published: February 2018

Abstract
Spraberry and Wolfcamp horizontal wells drilled in the Midland Basin normally have three-string casing designs and utilize "slop" mud for the intermediate salt section (9.0-9.4 ppg). However, in some areas, due to water disposal in the San Andres, 9.6-10.0 ppg fluids are required to prevent hydrogen sulfide (H2S) water flows. These potential flows restrict the use of "slop" fluids, resulting in the need for a four-string casing design. This paper reviews several cases utilizing a modified casing design and a low-viscosity wellbore strengthening (LVWS) fluid to drill these H2S water flow wells with a three-string casing design.
San Andres H2S water flow challenges were encountered while drilling the first horizontal well (Howard County - Midland Basin) with a deep intermediate casing point. This casing point was intended to isolate the depleted zones below the San Andres; however, a casing modification was required to eliminate the H2S water flow challenges. This change was implemented, resulting in a new challenge to drill the depleted zones below the San Andres and the Spraberry and Wolfcamp "A" horizontal laterals in a single hole section.
This paper presents a modified casing design that overcame the San Andres H2S water flow issues. This paper will also discuss the LVWS system that was utilized to economically drill the depleted zones and producing lateral in a single hole section by providing wellbore strengthening with an extremely low viscosity. These changes resulted in an average cost reduction of $750,000 per well.
This paper also presents how overcoming a San Andres H2S water flow challenge resulted in an improved wellbore design that has substantially reduced well costs. While these improvements were key to handling the H2S water flow issues, they should not be limited to areas with San Andres H2S water flows. This paper may be beneficial to all operators searching for lower cost alternatives to drilling Spraberry and Wolfcamp "A" horizontal wells in the Midland Basin.
Lab-Scale Drilling Rig Autonomously Mitigates Downhole Dysfunctions and Geohazards Through Bit Design, Control System and Machine Learning
Authors: Zarate-Losoya E. , Cunningham T. , El-Sayed I. , Noynaert S. F. , Florence F. 
Published: February 2018

Abstract
Oilfield economic conditions today continue to emphasize the need to recognize and respond to drilling dysfunctions quickly to maximize performance and minimize well costs. It is important for drilling engineers planning wells to fully comprehend each dysfunction in order to develop a means to mitigate their impact. As progress is made in this effort, it has become increasingly clear that many issues facing the drilling industry cannot be solved or solutions implemented with traditional drilling technology and platforms. The automation of drilling data collection and control systems response is increasingly becoming a key aspect of advancing many aspects of drilling performance.
SPE's Drilling Systems Automation Technical Section (DSATS) now enters its third year of an international competition for universities to design and build a small drilling rig that can operate hands-free in an unknown formation. Much like engineers in the field, students from each team must develop technical skills to understand the drilling dysfunctions that affect their rig's performance and calculate their impact on drilling performance. For the first time, in the 2017 competition, students must design and build a downhole sensor integrated into their control scheme. They have applied several different sensor types and unique telemetry techniques in custom-machined bottom-hole assemblies (BHA) that follow a 1.125 in (28.5mm) bit. The collected data is being used for vibration mitigation in real-time without human intervention.
The teams realize that the measurement and control aspects of drilling are as important as the equipment design, so they must model the drilling-states to determine appropriate response algorithms. Issues must be identified, and drilling parameters adjusted before dysfunctions severely limit performance. Teams often conduct a series of structured tests in various rock types to pre-tune their drilling algorithms. With improved state-detection algorithms and new optimization techniques, the drilling parameters that maximize performance are immediately calculated and implemented. DSATS intentionally challenges each team by choosing a thin-walled pipe which limits the ability to apply weight on the bit (WOB), ultimately generating an environment that promotes bit whirl. DSATS also provides an unknown rock sample of varying material, formation dips and other "surprises."
This paper presents the results of on-site testing of the winning team, Texas A&M University, who drilled a high-quality wellbore in the shortest amount of time. It also details the decision-process for the rig's design, based on background lab tests and engineering calculations.
How to Test for Compatibility Between Fluids and Shales
Authors: Oort Eric van 
Published: February 2018

Abstract
Fluid-shale compatibility testing is as old as the drilling fluid industry itself, and remains a highly relevant topic as drilling applications explore new, more complex territory. Incompatibilities of fluids with clay-rich shale formations can lead to a plethora of operational problems, ranging from minor dispersion and accretion issues to major stuck pipe and production impairment events. The nature of fluid-shale interactions has confounded scientists since the birth of the drilling fluid industry, and has led to a variety of different test methods and protocols, many now decades old. The question remains: what are the best, most representative fluid-shale compatibility tests to characterize fluid-shale interactions and avoid making costly mistakes based on misleading test results?
Historical fluid-shale compatibility tests are often severely limited by over-emphasizing the role of clay swelling behavior, by not paying attention to shale sample condition, and by not being specific with regard to the intended purpose. Test selection is often based on a superficial assessment of the "reactivity" of the shale, and results are indiscriminately applied whether the intended purpose is maintaining cuttings integrity, promoting borehole stability or avoiding reservoir incompatibility to name a few. This paper points out the various pitfalls and problems associated with conventional tests such as atmospheric swelling tests and capillary suction time tests, which still find wide-scale application in the oil and gas industry. A case is made to abandon such tests in future. New sets of tests are proposed that may overcome the drawbacks of the conventional tests. These tests are also conducted with a clear purpose in mind. For instance, to evaluate borehole stability, it is argued to forego traditional swelling tests and instead focus on triaxial failure testing, mud pressure transmission testing and borehole collapse testing. The latter can be accomplished with a novel, low-cost alternative to the downhole simulation cell test in the form of a modified thick walled cylinder test. This new test exposes cylindrical shale samples, confined under downhole temperature and pressure, to mud formulations at overbalance for a specified period of time and assesses the failure strength of the sample thereafter.
Recommendations for shale characterization and to investigate fluid shale interactions relevant to shale cuttings integrity, borehole stability and reservoir compatibility for conventional and unconventional reservoirs are given here. The tests are illustrated with representative results obtained for novel mud systems such as high-salinity fluids and muds containing nano-particles. Recommendations with respect to applying laboratory results to field operations are provided.