bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Hydraulic Work-Over for Well Integrity Restoration
Authors: Romero Javier 
Published: January 2016

Abstract
The assurance of well integrity in the oil and gas fields has become a paramount responsibility during the field life cycle. Today this task represent a major challenge in the oil industry taking in consideration the rising of number of wells with extreme conditions with HPHT reservoirs, high fracture pressures, highly sour environments and subsea wells in ultra deep waters. After the catastrophic incident of Macondo in 2010, Process Safety (PS) and Well Integrity (WI), are the two major priorities of all Oil & Gas Companies, due to the potentially high financial and environmental impacts, in case a well barrier failure occur.
The management of the wells barrier represents one of the main targets inside the oil industry, in order to guarantee the integrity on the oil and gas wells. New standards highlight the requirement of to guarantee two barriers all the time in order to avoid any undesirable leakage of well fluids. The policy of ensuring two barriers is mandatory, and the aim is to have available a secondary barrier in case the primary barrier fail. However, immediately after any failure in the primary barrier, is also mandatory start up an emergency plan in order to recovery the primary barrier or suspend the Well properly with two temporary barriers. The emergency plan to re-establish two well barriers normally requires some special resources and an extensive risk assessment. The first challenge after the emergency plan has been activated is how to define an adequate and safer setup for the well intervention, in order to guarantee personnel safety and the integrity of the assets.
This technical paper propose a new approach for the Hydraulic Workover interventions and a workflow to enhance the Hydraulic Workover Units (HWOU) in order to make those operations safer, reliable and suitable to attend challenging interventions to restore wells with integrity issues and flexible enough and cost effective to attend conventional workovers. The idea is to develop an enhanced HWOU to compete with Rig, Hoist and CTU in different intervention scenarios. It’s presented an outline of the improvements, job analyis and the risk assessment required to define an adequate well control envelop in order to cover all the changes in the well barriers, the changes on well conditions and the expected challenges along the intervention. At the end we present the recipe to conduct the evaluation of every intervention and the tailored improvements to the intervention challenges.
Directional Casing While Drilling (CwD) Reestablished as Viable Technology in Saudi Arabia
Authors: Muñoz German , Dhafeeri Bader , Saggaf Hatem , Shaaban Hossam , Herrera Delimar C. , Osman Ahmed , Otaremwa Locus 
Published: January 2016

Abstract
To access the reservoir in a large Saudi Arabian development field, the operator is required to drill an intermediate 5,000 ft to 6,000 ft directional hole section with dogleg severity (DLS) varying from 2.5°/100 ft to 3°/100 ft. The commonly drilled 12¼-in. borehole crosses several interbedded formations comprised of limestone, shale and sands, and it is associated to a variety of hole problems, which present repeatedly in the offset wells. The main objective for the operator was to mitigate the problematic by defining alternative and suited drilling technologies. Among them, Saudi Aramco found that the recent developments in the directional casing while drilling (DCwD) technology may well provide an effective method for diminishing the associated nonproductive time (NPT).
The drilling engineering team conducted an extensive evaluation of the problems across this section, including wellbore stability, water flow, and loss of circulation; tight hole/stuck pipe incidents, severe bit/stabilizer wear while drilling abrasive sands. After a promising technical and engineering evaluation, followed by a detailed risk assessment aiming to determine the potential of the application, the selected well was planned and executed using the DCwD service.
This paper outlines the process carried out during all stages through the final deployment of the first 9⅝-in. DCwD application in Saudi Arabia, and how it successfully aided in achieving the goals by reducing the impact of some of the problems experienced while drilling the same section in previous wells in the field. Likewise, the information provided will serve as a starting point for the design and construction of subsequent wells leading to further improvement in drilling performance. Best practices and lessons learned from this implementation are expected to become a model and the know-how transferred to other areas where comparable drilling events occur.
The technological benefits have been recognized by the operator and this application reestablished DCwD as a viable technology to address a number of challenges common in many of the Saudi Arabian oil and gas fields.
High Performance Water Base Fluid Improves Wellbore Stability and Lowers Torque
Authors: DeNinno E. , Molina M. , Shipman J. , Dearing H. , Arpini F. , Bussaglia L. 
Published: January 2016

Abstract
In Southern Europe, a field known to have extremely unstable formations was drilled successfully with a specialized high- performance water-based fluid (HPWBF). Prior to formulating the HPWBF, laboratory analyses were performed on the formation using x-ray diffraction (XRD). The formation was found to be high in calcite, quartz and clays. The relative concentrations of the aforementioned minerals were variable; therefore, the samples' reactivities (measured by cation exchange capacities (CECs)) were also variable, increasing the difficulty of predicting reactivities when planning an appropriate drilling fluid. Previously, wells in this area endured costly and untimely sidetracks caused by stuck pipes and collapsing wellbores. The financial impact of lost time and equipment greatly reduced the profitability of the wells.
During the drilling program a drill pipe failure and subsequent fishing operations involved a successful recovery of the lost string and bit after nine days without circulation. Based off of previous experiences1,2, the laboratory formulated and piloted a HPWBF to solve these challenges. Using various shale inhibitors and a high-performance drilling enhancer (HPDE), the fluid stabilized the wellbore and delivered a low coefficient of friction for torque reduction. The HPWBF was also customized with a unique blend of viscosifying agents to maintain rheological properties for optimum hole cleaning.
The HPWBF stabilized the wellbore, allowing the pipe and bit to be retrieved and pulled out of the hole without any issues after the nine days without circulation. This discussion will include the formation's XRD and CEC findings, general drilling fluid measurements such as lubricity coefficients, rheologies, wellbore stability, lab tests on corrosion and cement contamination, and a comprehensive overview of the well data including torque drilling days.
Torque and Drag Modeling; Soft-string versus Stiff-string Models
Authors: Mirhaj S. A. , Kaarstad E. , Aadnoy B. S. 
Published: January 2016

Abstract
The wellbore friction, torque and drag, between drill string and the wellbore wall is one of the most critical issues which limits the drilling industry to go beyond a certain measured depth. For this reason many studies on torque & drag modeling have been performed. In this regard different approaches have been used; the difference in these approaches is often on how to include bending stiffness and shearing forces in the T&D calculations. These approaches are (1) the effect of shear forces calculations with the assumption of continuous contact of the wellbore wall and the drillstring as well as constant curvature trajectory, (2) the effect of bending stiffness and shearing forces calculations with assuming of clearance between drillstring and wellbore-wall and (3) the effect of bending moment and shearing forces, assuming continuous contact of the pipe and wellbore-wall and using a non-constant curvature trajectory in which the first and second derivatives of the curve exist (i.e. spline type trajectories).
This paper consists of two main parts: first a review on literatures on the subject of stiff-string T&D will be considered. Secondly, an approach will be discussed in which despite of the assumption of constant curvature trajectory and full-contact of pipe and wellbore wall, the effect of bending stiffness on torque and drag calculations are considered. The simple and robust stiff-string model is implemented in two example wells in order to find out the importance of the stiff-string calculations.
An Advanced Workflow for Determining Fracture Geometry in Complex, Tight Oil Formations in the Sultanate of Oman
Authors: Atanayev Askar , Nadezhdin Sergey , Zeidi Omar Al , Batmaz Taner , Kurnaidi Stevanus Dwi 
Published: January 2016

Abstract
Exploration drilling indicated that the Natih B formation in Oman may have a significant amount of oil locked in a challenging low-permeability, laminated, carbonate reservoir. The first completed vertical wells suggested that stimulation treatments were required for economic production. The operator applied acid fracturing stimulation techniques to establish baseline production. To further improve well performance, proppant fracturing stimulations were scheduled for several vertical and horizontal wells.
Mechanical earth models were constructed to help improve understanding of fracture geometry. The earth models revealed stress inversion between layers, differentiating stress regimes into strike-slip and thrust. Areas of different stresses within the same formation would lead to different hydraulic fracture shapes (e.g., regular planar fractures in the case of strike-slip mode or horizontal fractures in the case of thrust mode). Predicting these geometries would impact the fracture design and completion strategies. In addition, the pay zone was bounded by water-bearing zones at the top and bottom, introducing a risk of water production if any of the wells exhibited excessive fracture-height growth. Several measures helped survey fracture-height extension during initial diagnostic treatments.
In the formation's first horizontal well, uncertain stress regimes and lateral unconformities, such as natural fractures, complicated the hydraulic fracturing treatments. To overcome these uncertainties and optimize stimulation, we needed to accurately model natural and hydraulic fracture interaction. A mechanical earth model from vertical wells in the vicinity, and the horizontal wellbore itself, were combined with natural fracture network data and the staging and perforation design.
Use of a Life Cycle Drilling Simulation System on a Challenging HPHT Drilling Operation in the Norwegian Sea
Authors: Scott Laurie , Wessel Just Sverre , Nabavi Josef , Rommetveit Rolv 
Published: January 2016

Abstract
A Life Cycle Drilling Simulation System (LCDSS) was utilized during planning, training, and operation in support of a very challenging drilling operation in the Norwegian Sea. The LCDSS constitute a total modeling system tailor-made for planning, advanced training real-time simulation and decision support.
In order to utilize the LCDSS, the work processes were modified and fit-for-purpose communication lines were established.
In preparation, an advanced training session was performed using a dynamic downhole training simulator linked to a topside rig simulator, for training of the drilling teams.
Prior to operation data transfer was established so that during the operation simulations was performed in real time using the ongoing operational parameters as input.
Automatic look-ahead simulations of ECD and temperatures were performed with the calibrated models on the fly as support for decisions.
Every day drilling forecasts were made 12 to 24 hours ahead. This was done by means of a transient planning model populated with all relevant data from the operation. These forecasts were communicated to the drilling team as a basis for the upcoming operation.
This paper will first present the Life Cycle Drilling Simulation System, then elaborate on the use of this in the preparation/training phase and operational phase including forecasting. Special focus will be given to how the work process and communications were modified and the results thereof.
The operation was successful, and the LCDSS was a contributor to this.
New Concentric Dual-Diameter Fixed-Cutter Technology Bit Drills 35% Faster and Saves Operator Drilling Time Through Challenging Abrasive Sandstone in One of the Largest Reservoirs in the Middle East
Authors: Al-Ajmi Khaled , Al-Hamadi Ebrahim , Baqer Yousef , Al-Qnaai Mohammad , Fayed Moustafa , Khalil Karim 
Published: January 2016

Abstract
This paper will discuss the deployment of the concentric dual-diameter fixed-cutter bit technology, which was introduced in January 2015. The bit was deployed and tested twice in a vertical application in Burgan Field south of Kuwait and achieved the fastest penetration rate in the application.
The concentric dual-diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed-cutter bits take very little advantage of stress-relieving the rock, as it only affects the borehole wall. Concentric dual-diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress-relieved rock with lower mechanical specific energy compared to regular fixed-cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual-diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling.
The 12 ¼ in. concentric dual-diameter technology bit in conjunction with a packed rotary BHA was tested in a vertical application in the Burgan Field south of Kuwait. The bit was able to deliver improved performance, achieving the fastest penetration rate of 152.4 ft/hr. The section drilled was 762 ft in length and consisted of shale and sandstone.
The performance capability was confirmed when the same bit was reused again in a similar application subsequently and was able to deliver the same consistent record penetration rate of 152.5 ft/hr. The section length in this second run was 610 ft. and consisted of similar lithology of shale and sandstone.
The 12 ¼ in. concentric dual-diameter bit was able to surpass the average rate of penetration for the same application in the Burgan Field by 35%, saving the operator drilling time and making the concentric dual-diameter bit design the top performing drill bit in the field.
Improved Validation Method for Annular Casing Packers
Authors: Stair Todd , Makowiecki Gary 
Published: January 2016

Abstract
To mitigate annular flow during primary cementing operations, a packer can be used to create a high-pressure seal between casing strings. Operating conditions, such as run-in-hole (RIH) speeds, circulating rates, hydrostatic pressure, static and circulating temperature, fluid type, and debris, should be considered when qualifying a product for commercial use. This paper details an improved validation method for new annular casing packer designs used in cementing applications and discusses why current industry standards for packer validation are not entirely applicable.
When designing a new annular casing packer, unprecedented qualification testing was performed, combining full-scale function testing with a high-pressure/high-temperature (HP/HT) gas test. The packer was run and set as though it were an actual operation in a well. Remaining in the set condition, the tool was then withdrawn back to surface and inserted into a test cell at 300°F. After reviewing current industry standards, applicable portions of the standards were used to perform a bidirectional pressure test on the packer with nitrogen as the test medium.
At the conclusion of the combined testing effort, the packer traveled 7,400 ft at speeds up to 5 ft/sec. It was circulated past at 17 bbl/min for more than three hours. It was functioned using simulated real-world methods and procedures at a depth of 2,200 ft with 2,800 ft of casing hung below it. It was then retrieved and pressure tested bi-directionally at 11,500 psi with nitrogen at 300°F. The fluid in the test well was a 14 to 14.5-lbm/gal water-based drilling mud. This combined testing subjected the tool to harsher than real-world conditions successfully, thus demonstrating its ability to operate properly in the well with a high level of confidence.
Operational Benefits of Designing Acid-Soluble Drilling Fluids for Horizontal Wells in HTHP Conditions
Authors: Wagle Vikrant , Al-Yami Abdullah S. , AlAbdullatif Ziad , Bubshait Abdulaziz S. , AlSafran Ali 
Published: January 2016

Abstract
Issues associated with stuck pipe result in huge losses in the world oil industry. Historically, horizontal wells drilled in Saudi Arabia have been known to present severe stuck-pipe challenges. Thus to mitigate the problems arising due to stuck-pipe issues, a new drilling fluid has been designed which employs a combination of two different weighting agents viz. barite and manganese tetroxide (Mn3O4). The use of such a combination as a weighting material in a drilling fluid provides both operational and monetary benefits.
Manganese tetroxide is spherical in nature and has a small particle size (D50=1 µm) as compared to barite (D50=20 µm) Moreover, Mn3O4 also has a higher specific gravity (4.95 g/cm3) as compared to barite (SG= 4.20 and). This high specific gravity of manganese tetroxide makes it a good weighting material to reduce solids loading and settling in drilling fluids as compared to the conventionally used barite. Another advantage of Mn3O4 is that it is acid-soluble. This acid solubility of Mn3O4 provides more operational benefits when a fluid with a combination of barite and Mn3O4 is used as weighting agent. The acid solubility of Mn3O4 makes the use of acids or acid precursors possible in partially dissolving Mn3O4-barite based filter-cakes. This partial breakage of the filter cake is expected to free the pipe thereby mitigating the problems associated with stuck pipe incidents. Another benefit of using a combination of barite and Mn3O4 would involve reduced fluid cost as compared to a fluid formulated with Mn3O4 alone as the weighting agent.
Thus, this paper presents a solution in mitigating stuck pipe issues and showcases the benefits of using such a combination of barite and manganese tetroxide as weighting materials in 100pcf, 120pcf and 150pcf drilling fluids hot rolled at 270°F /250°F/300°F respectively. The experimental work in this paper involves measuring rheological properties, HTHP filtration and static sagging resistance of the fluid at the specified temperature. The paper also describes the results of using different organic acid based filter-cake breaker fluids for the partial dissolution of manganese tetroxide based filter cake. Comparative studies of fluids formulated with 100% barite and a blend of manganese tetroxide and barite show that fluids formulated with a combination of barite and Mn3O4 provides increased sag resistance as compared to a drilling fluid formulated with barite alone as the weighting agent.
A New Class of 125 ksi SMYS Sour Service Drillpipe Offers Improved Capabilities for Drilling in Sour Gas Environments
Authors: Hehn Lucien , Uttecht Amie , Jellison Michael , Sanclemente Leianne , Delahoussaye Mike 
Published: January 2016

Abstract
Sour gas constitutes 60% of the Middle East natural gas reserves (Nersesian 2015). The term "sour" is used to refer to environments containing hydrogen sulfide (H2S). In sour wells, H2S causes sulfide stress cracking (SSC) in carbon low-alloy steels under tensile stress. A form of hydrogen embrittlement, SSC causes sudden, brittle fracture in drillpipe. To combat the effects of H2S exposure, sour service drillpipe has been manufactured to meet IRP Volume 1 - Critical Sour Drilling specifications. IRP requires SS75 ksi, SS95 ksi, or SS105 ksi specified minimum yield strength (SMYS) tubes with all three grades using 110 ksi SMYS tool joints for use in sour operations. However, these lower yield strength IRP grades have limited load capacity which restricts drilling parameters such as total depth (TD) and margin of overpull.
The next higher yield stress grade available is the API S135 grade. This grade is a non-sour service grade with SSC-resistance limitations due to its higher hardness and higher yield strength values. The SSC-resistance of S135 in an H2S drilling environment is dependent on using drilling muds with pH control (above 10.0), H2S inhibitors, and H2S scavengers. Therefore, a grade of SSC-resistant drill pipe is needed to bridge the gap between the fully SSC-resistant SS105 grade and limited SSC-resistant S135 grade.
Using advanced steel heat treatment methods, a 125 ksi SMYS grade sour service drillpipe has been developed. The 125 ksi tube is mechanically incompatible with the standard 110 ksi IRP sour service grade tool joint because of the large difference in yield strength between the two components. Therefore, a new class of sour service tool joint with an SMYS of 120 ksi was required for the 125 ksi sour service tube. This new higher yield strength tool joint needs to meet the same level of SSC-resistance as the 110 ksi IRP tool joint, i.e., pass testing in solution A method A of NACE TM0177 (100% H2S @pH = 2.7, 720 hour test) at a testing stress of 65% of SMYS. Like the high yield strength 125 ksi tube, advanced heat treatment methods were required to achieve SSC-resistance in the higher yield strength tool joint.
This paper introduces an SSC-resistant 125 ksi drillpipe with SSC-resistant 120 ksi tool joints and presents the results of NACE TM0177 testing of this new technology. The new 125 ksi drillpipe will allow for increased load capacity over IRP SS105 grade drillpipe in drilling environments with moderate to low concentrations of H2S. In addition, it can serve as an improved substitute over S135, a non-sour service grade drillpipe.
Background to the Development of a Remote Controlled Drilling Blowout Preventer (BOP) Activation Technology for Surface BOP Applications
Authors: Affleck Michael , Gilleland Monty 
Published: January 2016

Abstract
Introducing a new technology that reduces uncertainty and therefore risk of harmful, unplanned hydrocarbon release during drilling operations by providing additional secondary well control functionality in the event of rig evacuation. In most well control events, rig personnel have sufficient time to secure the well by following recognized well control operating procedures, utilizing long established well control technology. On occasion, shut-in does not occur before evacuation of the Blowout Preventer (BOP) control panel locations or, post-evacuation it is uncertain if shut-in procedures have been followed successfully. For example, if evacuation was sudden and the well remains in an unknown condition, potentially releasing hazardous hydrocarbons and associated gases to the environment. The author will discuss in detail the background and rationale to the new technology, including a review of well shut in potential versus time / incident severity and other human factors present at the moment of making the evacuation decision. The system design and intended operation will be explained including, specifically BOP function and monitoring when rig evacuation is occurring or has occurred. Several real-life scenarios will also be described for which the new technology could be operated. The system is designed to be deployed as an additional safety system, supplementing the rig's existing secondary well control technology or integrated with existing equipment to provide additional well control functionality. The novelty of the approach is that nothing is known to currently exist providing this functionality.