bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract

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

Abstract
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.