bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hybrid Drill Bit Technology Achieves Breakthrough Performance in Challenging 16-in. Section - Gas Wells in Saudi Arabia
Authors: Ortiz William , Nawaz Khalid , Mukherjee Tushar S. , Mubarak Sami , Shuwiayah Mohammed T , AlHomoad Hussainn , Rojas Pablo , Valbuena Franklin 
Published: February 2017

Abstract
Use of 16-in. vertical sections in onshore deep gas drilling operations in Saudi Arabia presents challenges with a high risk of total drilling fluid loss in interbedded formations. The formations comprise carbonates, limestones, shales, anhydrites, and abrasive sandstone with pyrite inclusions, where the rock hardness is 10 to 15 kpsi unconfined compressive strength (UCS). To minimize the risk of loss, the high bentonite mud system is implemented. The bit consumption averages two tungsten carbide insert (TCI) bits per section, and high average dull grading conditions are observed (IADC 3-4-WT), coupled with low rate of penetration (ROP) performance across the whole section.
Though an in-depth offset well study, including bottom-hole assembly (BHA) analysis, bit dull condition review, evaluating the high bentonite mud effect, and the UCS formation trend, the potential to drill the 16-in. section in a pilot well in a satellite field (using hybrid bit technology) was determined. This paper outlines the development of the best drill bit technical solution, optimizing the use of crushing (TCI inserts) and shearing effect (polycrystalline diamond compact – PDC) cutting structure configuration to drill the section in the minimal time and cost possible.
The results observed in the pilot well confirmed that one hybrid bit had the ability to drill the total section. A 138-percent increase in the rate of penetration (ROP) versus relevant offsets, and a decrease 2.3 operational days and 50% cost per foot reduction. The hybrid bit reached the total depth (TD) section without any operational issues, where the risk of losses was minimized, and a proportionate normal dull condition in the cutting structure was observed. The technical compatibility of the hybrid technology was demonstrated with outstanding performance for the operator.
Experimental Investigation of Effects of Asphaltene Stability on Interfacial Behavior of Live Reservoir Fluid Systems
Authors: Ratnakar Ram R. , Mantilla Cesar A. , Dindoruk Birol 
Published: February 2017

Abstract
Wettability alteration due to asphaltene precipitation in a reservoir affects rock-fluid interactions that have potential impacts on oil production, recovery and flow in the production network. The current predictive wettability models do not consider asphaltene stability and are inherently inaccurate. This study investigates the impact of pressure-depletion induced asphaltene precipitation on interfacial tension (IFT) and contact angle for live-oil systems at reservoir conditions (high-pressure high- temperature); and presents a graphical (quantitative) method for determining asphaltene onset pressure based on interfacial behavior.
Water/oil IFT was measured at reservoir temperature using pendant drop-shape method for a system of live-oils over a range of pressure above and below the asphaltene onset pressure (that was already independently determined via particle size distribution and solid detection system techniques). Contact angle with quartz was also measured in presence of de-ionized water as surrounding medium at the same pressure and temperature conditions. The temperature was controlled with an accuracy of ±0.1°C. Each set of measurements were performed twice to assure the reproducibility of the experiments and methodology.
This work presents the experimental study to quantify the change in interfacial behavior due to asphaltene deposition. The IFT/Contact Angle measurements above and below asphaltene onset pressure show that the interfacial behavior follows the normal trends above asphaltene onset pressure as observed in other water/hydrocarbon systems. However, when pressure was reduced below the asphaltene onset pressure, an evident relatively sharp change in the trend is observed in both IFT and contact angle caused by asphaltene migration to the interface, in a way acting as natural surfactant. As asphaltenes precipitate and deposit in the mineral substrate, the surface turns less water-wet and the contact angle naturally increases to balance the equilibrium forces.
This study sets a non-visual quantitative method to determine asphaltene onset pressure and presents new experimental data on IFT/contact angle of live-oil systems at reservoir conditions. The effects of asphaltene precipitation on interfacial properties are more meaningful than the size of aggregates (visual methods), and can be utilized to assess the potential impacts of wettability alteration due to asphaltene precipitation. For example, only when change in contact angle is large, wettability alteration should be considered in reservoir simulation of depletion processes and waterflooding performace, especially in the context of relative permeability changes.
Operations Efficiency: Improved Well Planning Methodology Based on Invisible Lost Time Smart KPIs
Authors: Al-Ghunaim Sulaiman Marzoug , Sadiq Bashayer Mohammad , Siam Mahmoud , Nassar Islam , Aissa Reda Kaci 
Published: February 2017

Abstract
To optimize drilling operations efficiency and improve well planning methodology, Kuwait Oil Company (KOC) has capitalized on the existence of the real-time drilling decision center (RTDDC) to scrutinize the breakdown of rig operations, detect invisible lost time, and explore measures to address the root causes of this lost time. Advanced data analytics were applied to real-time data to investigate the impact of invisible lost time on drilling operations and use it to benchmark rig performance. This information will now be used for better well planning and improved performance tracking, which would traditionally be hard to achieve using legacy methods such as daily drilling reports and spreadsheet reporting.
The analysis started with combining real-time data with rig daily drilling report data to perform quality control and validate the operational phases. The combined data output was used to calculate rig states within the different operational intervals throughout the lifetime of the well. Consequently, smart key performance indicators (KPIs) were calculated to map previously identified invisible lost time within the different operation phases. Such KPIs were then normalized with respect to a single frame of reference to establish the basis for comparison within a drilling campaign or across a rig fleet. Finally, the normalized KPIs were analyzed to produce a best composite matrix indicating the best performance achieved in the different operation phases to enable more accurate well planning.
This methodology was applied to two wells. From the results, a best performance analysis was conducted based on a fair comparison between the rigs/wells. Operational inefficiencies were accurately captured, and root-cause analysis was effectively categorized in terms of crew performance, flat-time operations, and tool performance. All the results were translated into a framework that enables an enhanced well planning process and an improved performance tracking methodology.
This study exemplifies how to apply advanced data analytics on high-frequency and low-frequency drilling data within a drilling project or across different rigs to identify best potential performance and how to set a benchmark, translate it into goals, and thereby improve the operational efficiency of the project/business and deliver cost savings.
Systematic Approach to Develop a Colloidal Silica Based Gel System for Water Shut-Off
Authors: Huang Jin , Al-Mohsin Ayman , Bataweel Mohammed , Karadkar Prasad , Li Wengang , Shaikh Abrar 
Published: February 2017

Abstract
Undesirable water production can significantly affect the economic life of producing wells. Excess water production results in loss of productivity, corrosion, and scaling. Also, the need for water handling facilities and reinjection of unwanted water can further add to the total cost of the project, which consequently increases the cost of production. In offshore operations, produced water can have an adverse impact on the environment.
The use of a colloidal silica based fluid system was developed for water shutoff application. A systematic experimental study was conducted to evaluate the effect of key parameters on the gelation properties of this system; that is: particle size, pH, temperature, and silica concentration. Also, the effect of different salts, as an activator agent, were tested to initiate in-situ gelation of colloidal silica. The performance of this system was evaluated by conducting static gelation tests as well as high pressure and high temperature viscosity measurements up to 150°C.
Colloidal silica solutions exhibit low viscosity. Proper selection of suitable activators can lead to in-situ gelation and formation of a high viscous gel to block the pore space. The permanent sealing of formation porosity can be achieved by building the viscosity of colloidal silica. The colloidal silica gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed quicker viscosity buildup. The gelation time can be varied by controlling the initial pH of the system. A stable system and good dispersion was achieved for the colloidal silica solution without using an activator, as confirmed from the Zeta potential results. Increasing the salt concentration and temperature or lowering the pH of the system results in unstable system that triggers the gelation process. The existence of more than one of the above factors (i.e., salt, temperature, and lower pH) results in further reduction in gelation time.
Colloidal silica has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. The fluid system presented in this paper was developed to address the needs of water shutoff applications. The environmentally friendly system is comprised of two components; colloidal silica and an activator.
Studying the Cooling Effect of Nitrified Drilling Fluid on Bottom-Hole Assembly While Drilling High-Pressure, High-Temperature Wells
Authors: Alrumaidh Abdulrahman , Abushaqra Ahmed , Elghoneimy Mahmoud , Nabhan Mohamed 
Published: February 2017

Abstract
High-Pressure, High-Temperature is a crucial technical challenge when it comes to drilling very deep wells to find and produce new hydrocarbon reservoirs. This paper studies the cooling effect of using nitrified mud as drilling fluid and compares the results to using conventional mud. This is to prevent the measuring-while-drilling & logging-while-drilling tools from failure due to High-Temperature.
The study is about taking the advantage of the huge reduction in pressure, when nitrogen gets out of the drill bit nozzles, leading to a corresponding significant drop in temperature while drilling. The analysis starts by calculating the pressure losses within the well using fluid mechanics approaches. Since the paper includes different cases, a MATLAB® code is developed to run all cases. Additionally, Autodesk® Inventor® Professional is used to build the model at the last portion of the bottom-hole assembly. Pressure data and thermal boundary conditions are used by COMSOL Multiphysics® to get temperature profile in last portion of the model. Likewise, a cost analysis is done to support that the proposed solution is economically feasible, besides being efficient, and effective.
The simulation outputs are outstanding in terms of reduction in temperature, injection pressure capacity, and cost. The maximum temperature of the pipe outer wall is reduced efficiently when the nitrified mud was used compared to conventional drilling mud. The pressure losses are larger in conventional mud which led to higher power requirements. The drilling operation costs are cheaper than drilling with conventional mud in many comparisons in this paper.
Reaching to an economical, practical, and environmentally friendly suggested solution is an evolutionary approach in facing the HPHT technical challenge. This, indeed, is not only introducing HPHT drilling technology to a whole new level, but also to do it with an integration of technology, reliability, & efficiency.
Open Hole Sand Control Optimization Using Shape Memory Polymer Conformable Screen With Inflow Control Application
Authors: Osunjaye Gbenga , Abdelfattah Tarik 
Published: February 2017

Abstract
This paper covers the novel application of combining shape memory polymer (SMP) conformable screen with inflow control devices (ICD) to provide operational efficiency, wellbore stability and production enhancement in unconsolidated reservoirs openhole completion.
It is not uncommon to have unconsolidated reservoirs with permeability heterogeneity. It becomes more challenging when the formation sands are non-uniform and poorly sorted. The Conventional solution for these type of reservoirs encompasses the use of gravel pack techniques in combination with sand control screens that are equipped with inflow control devices (ICD). However, operational execution is complex and risky especially when openhole isolation packers are added to isolate and compartmentalize the multiple zones. An alternative solution to this challenge is the simplified combination of SMP conformable screen with ICD.
An SMP conformable screen with ICD replaces the burdensome gravel pack operation, provides conformable sand control and maximizes the benefits of the already proven inflow control technology. This integrated application brings efficiency to well site operation by reducing the quantity of downhole accessories, reducing rig site operating hours, and saving overall capital expenditures (CAPEX) or operating expenditures (OPEX). The shape memory polymer provides improved wellbore stability and efficient sand control regardless of the uniformity of formation sands in the different reservoir layers. The combination with ICDs will ensure that production longevity and recovery are optimized by efficiently equalizing inflow profiles.
Technical contributions which include filtration performances, inflow control modeling and completion fluid management are provided to expatiate on the performance analysis of this innovative approach in resolving a critical challenge in horizontal sand control completions.
Optimization of the Curve and Horizontal Sections of ERD Multi-Lateral Wells
Authors: Verma Chandresh , ElKawass Amir A. , Mehrdad Nadem , ElDeeb Tarek , Qazi Muhammad Q. , Galaby Amir , Salaheldin Ahmed , Fakih Abdulqawi Al , Osman Ahmed , Hammoutene Cherif 
Published: February 2017

Abstract
While ERD multi-lateral wells in a large Middle East field are typically drilled in six to seven well bore sections, drilling the 8.5-in curve and the 6.125-in lateral sections represents more than 50 % of the total time spent drilling the well. Challenges while drilling the curve section with a motor include difficulty transferring weight to the bit while sliding and differential sticking in the highly poros zones of gas cap. The laterals, which can extend up to 12,500 ft of reservoir contact, are characterized by medium to hard compacted carbonate formations with high stick and slip tendency. This represents several challenges for drill-bit design engineers given that aggressive cutting structures are preferred to generate good rate of penetration even though this often leads to high bottom-hole assembly vibration. Trajectory control, hole cleaning and long circulating hours also represent significant challenges.
This paper will present details of the engineering analysis performed to optimize both 8.5-in and 6.125-in wellbore sections.
For the curve section, the first step was to change the drill string from 5 in to 4 in which considerably reduced the time taken to change the string prior to drilling the laterals. This change of drill string was accompanied by the use of a rotary steerable system and a PDC bit. This was a combination that had never been implemented since the field discovery in 1968. These changes resulted in performance improvements in excess of 50 %.
For the laterals, the engineering analysis resulted in the need of a completely new bit design. The cutting structure was modified to provide a more aggressive bit to formation interaction, and the gauge contact with the formation was enhanced to maintain the bit and BHA stability. The resulting design broke the field rotary steerable ROP record by 28 %. The bit drilled the highest single run footage in the field (12,698 ft) at the highest ROP (96.93 ft/hr) with a rotary steerable system. This was further complemented by optimizing the drilling practices and well bore cleaning practices allowing the elimination of several conditioning trips within the long laterals which resulted in three days of savings in a three lateral well.
The paper will conclude with a discussion regarding the reduced injury exposure that resulted from changing the drill string earlier within the well and a review of further improvement opportunities.
Determination of True Formation Resistivity from LWD Conventional Resistivity Measurements in a Horizontal Well
Authors: Fang S. , Boesing D. , Wessling S. 
Published: February 2017

Abstract
In a horizontal well, apparent resistivity curves often show varied separations and increased values due to the polarization horn effects near a boundary and other effects such as adjacent beds or anisotropy. The true formation resistivity (Rt) is uncertain and can be mis-interpreted. As a consequence, saturation estimates are uncertain so that the reserves cannot be accurately predicted. A full inversion can be used to derive the true Rt. However, the instability of an inversion due to the lack of measurement variation along the measured depth makes the Rt derivation very challenging.
To determine a true Rt from the logging-while-drilling (LWD) resistivity measurements, a general full inversion is usually time-consuming and needs some inputs on formation model. This paper presents an alternative approach to derive the true Rt without input of any prior information. The alternative approach uses a simple two-layer model for the removal of horn effects and derives a solution at two steps: a) inverting resistivities of the two layers at each distance away from the boundary; b) selecting a solution with specific constraints such as using statistics in a moving window and internally consistent physical constraints to make the solution more reliable. In the first step, neural networks are developed to calculate tool responses and derivatives for the savings of computation time and memory needs.
Synthetic examples show that true Rt can be recovered when the relative dip between a borehole and a layered formation is greater than 85 degrees. The examples show that bed boundaries can be reproduced with sufficient accuracy by our approach, among others to define pay zone intervals. In addition, the resolution of the method was studied with models of different layer thicknesses and is discussed in details in the paper. As an outcome, the derived true Rt reads lower in a resistive thinner layer and reads slightly higher in a conductive thinner layer. A field example from a North Sea oil field demonstrates very promising and robust Rt results from the method.
The inversion is fully automatic and can be used in real time and downhole. Physical constraints that are special to a horizontal well and better strategies make our algorithm robust and very fast.
Why, When and How to Certify?
Authors: Noorloos Jan-Willem 
Published: February 2017

Abstract
The title of my presentation is "Why, when and how to certify?" it is about the sense and nonsense of IEC 61508 certification.
There are many examples in the business of certifications. These can be certifications of systems, devices or conformity of devices. This can have a huge impact on the safety of your process you are safeguarding. Hence it is very important to have an assessment of this certification by independent specialists.
What is the correct standard you should follow to be compliant. Do you follow a global standard or a company engineering standard? If you implement certified products or system, how can you be sure the certification of that system is sufficient enough for you? How can you make sure it will cover all your needs? This can be done by reading these certificates and reports of the systems.
Advanced Spotting Fluids for Remediation of Differentially Stuck Pipe
Authors: Hilfiger Matthew G. , Thaemlitz Carl J. , Moellendick Eric 
Published: February 2017

Abstract
Non-Productive Time (NPT) is one of the major operational and fiscal challenges of the drilling process, collectively responsible for billions of dollars in hidden cost. The greatest segment of NPT is often attributed to stuck pipe events, which may be mechanical or differential in nature. The differentially stuck pipe event is due to a differential pressure gradient, which creates a vacuum-effect upon the pipe, thereby sticking the pipe to the wall of the wellbore. Differentially stuck pipe may be alleviated at relatively low costs through application of a special fluid to help free the pipe. Such fluids useful in the release of drillpipes that are stuck due to differential pressures between the wellbore and the formation are known as spotting fluids. This paper investigates a new spotting fluid that exhibits the advantage of increased effectiveness at releasing stuck pipe in the presence of drilling fluids having high densities. In addition to this increased performance, the fluid can also be combined with a thermal activator to trigger a heat-generating fluid that is capable of exotherms from 100 to 300°F, thereby providing additional performance in treating stuck pipe.
High Performance Brine Viscosifiers for High Temperatures
Authors: Boul Peter J. , Abdulquddos Suhaib , Thaemlitz Carl J. 
Published: February 2017

Abstract
The development of oil and gas reservoirs at increasing depths has increased the demand for high density solids-free reservoir drilling fluids and completion fluids. Many viscosifiers currently used in these fluids are either incompatible with high density brines or require the use of prohibitively expensive brines such as cesium formate to achieve target densities. Therefore, there is substantial commercial benefit to developing a brine viscosifier with a higher temperature tolerance than is currently offered.
A supramolecular viscosifier package has been developed which utilizes non-covalent associations between additives to enhance the thermal resilience of divalent brine fluids. The product performance of a reservoir drilling fluid formulated with the supramolecular viscosifier package is compared with a standard starch-based reservoir drilling fluid. The enhanced performance is highlighted through static aging tests from 300 to 325°F. The fluids are analyzed before and after aging rheologically as well as for suspension stability.
It is clear from the static aging test data that the supramolecular viscosifier out performs the high performance, commercially available starch / xanthan brine viscosifier. The addition of this new polymer blend increases the brine suspendability both before and after aging at high temperature. The rheology of the new additive package also displays better rheological recovery after aging high temperature. This viscosifier package involves synergies of additives within the brine which greatly enhance the thermal stability of the polymers in the brine. The additive package presented retains its viscosity at temperatures up to 325°F and brine densities from 8.4 lb/gal to 19.2 lb/gal.