bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Fluids Automix
Authors: Hestad Vidar , Gulbrandsen Arild 
Published: January 2018

Abstract
Two Schlumberger companies, Cameron and M-I SWACO, joined efforts to provide market with a drilling fluid optimization system to be used during drilling operations. Cameron delivers a complete remote-controlled and automatic drilling fluids mixing system, while M-I SWACO's technology facilitates continuous real-time measurement, analysis and optimization of mud properties. Today mud samples are measured every 6 hours or more frequently, depending on the conditions in the well. The properties are then adjusted for the most part manually, based on a mud engineer's practice.
The Cameron Automix system comprises mechanized equipment and a robot for addition of chemicals into the drilling fluid, and works in concert with the M-I SWACO RheoProfiler instrument, which measures and analyzes drilling fluid properties in real time. Schlumberger (SLB) algorithms, designed to care for the known wellbore situations, automatically create optimal recipes for the chemicals to be mixed into the drilling fluid.
The synergies between M-I SWACO's core competence in fluids and RheoProfiler technology and Cameron's competence in software and mixing equipment, result in a unique method / system of continuous stabilization and control of the wellbore through drilling fluid optimization.
With the focus on a fully autonomous ‘closed-loop’ drilling rig, the spotlight is strongly directed on the drill floor activities and their automation. The main goal of SLB, in terms of automation and closed-loop activities, is to improve the primary well barrier, keep well conditions under control, and rig safe. A combination of each company's strengths, Automix and RheoProfiler can play an essential part in moving the drilling industry towards the same philosophy of fully automated and intelligent systems. The entire drilling operation needs to be viewed as one system, with one organization working towards a common goal, reducing exploration cost without compromising safety. However, there will always be a need for the mud engineer on board.
Less visible in the general hype around automation and more efficient drilling operations, is the importance of optimized properties of the mud in the drilling process. Safety during drilling, better well bore, economy or producing reservoir are just a few of the benefits of the SLB solution.
First Fully Successful Application of a Multistage Acid Fracturing Operation to Stimulate a Carbonate Formation, Resulting in the Implementation in Other Wells in the Mature Bahrah Field, North Kuwait
Authors: Mofti M. , Al-Othman M. , Alboueshi A. , Davis J. , Eid W. , Allam A. , Hamad A. Al , Sadeddin S. , Buhamad A. , Ashkanani M. , Aloun S. , Al-Haddad M. , Al-Mehanna H. 
Published: January 2018

Abstract
Throughout the last few years, oil company strategies have moved toward recovery of the maximum oil in place from mature fields and reservoirs that were previously considered technically challenging. The Mauddud formation in the Bahrah field is a low permeability carbonate formation with moderate to high oil viscosity. Viscosity is between 2 and 7 cp at 170°F, but a 90-cp viscosity at surface conditions is commonly observed once a well is placed on production, creating challenges for a vertically drilled well that could not provide necessary levels of sustainable production. In an attempt to achieve economic continuous production, a 3,000-ft lateral horizontal well was drilled. The lateral length was designed as an optimal solution for such a challenging reservoir to help sustain the production flow. Additionally, a multistage acid fracturing (MSAF) treatment was performed.
This paper discusses the design, execution, and production of the first MSAF treatment performed in the Mauddud reservoir using a cased openhole completion with swell packers and sliding sleeves that were placed in seven stages across the 3,000-ft lateral interval. Post-operation analysis exhibited highly sustained production, creating a shift in oil company plans toward drilling new horizontal wells and applying MSAF treatments to move the Bahrah field into the development phase. Results obtained from this operation were effectively used to help improve production in similar mature formations.
Based on this pilot treatment, a wide-scale field development strategy was planned, and many wells were drilled, completed, and fractured similarly in Bahrah field.
Repair of Surface Casing Failure Allowing Production Restart of Highly Productive Well
Authors: Bourgoin S. , Mendizabal C. Rojas , Tierno S. Santiago , Portillo L. , Barbee G. 
Published: January 2018

Abstract
A strategic well was drilled in 2001 (highly productive well with low CO2 content despite its age). A cellar cleaning campaign was performed on 03/2016, while the well was in production (450,000 sm3/day of gas). The 20" casing was found parted below the Starting Head at the cellar level, with evidence of corrosion. The cut had been buried in sediment for an unknown period and prolonged exposure to water and sediment accumulated in cellar was suspected.
Wellhead movement due to thermal expansion (axial and lateral) was reported during monitoring. Additionally, annulus B, formed by the 13-3/8" casing × 9-5/8" casing annulus was pressured with 16 bars.
The wellhead was found not directly supported by the landing base and axial/torsional force cycles during production/shutdown periods generated fatigue on the 20" casing. This load combination, added to lack of inspections and cleaning on cellar resulted in the failure of 20" casing at surface.
Heavy workover remedial options were studied with prospective high costs and long delays. At the same time a Call for Tenders was launched to find solutions to safely put back well in production at the shortest possible delay. Boots & Coots/Halliburton proposal was selected for engineering and execution. The operation was treated as a Workover (well secured and capped with BOP). Main stages involved: Installation of Downhole plugs, monitor of annular pressures and bleed off operations.Surface installations removal. Cellar Floor and one wall removal (trench excavation).50 cm below cellar excavation to find 20" casing in good conditions. Cut corroded section of 20" casing.Build foundations and rig up Strand-Jack Crane. Cap well with BOP, install tensioning spool system and Tension the inner csg & tbg to 465 kips to get 34 mm displacement and compensate the thermal retraction (Engineering calculations using WellCat™ Software).Replace the 20" corroded section with 2 new half-moon 20" casing sections (welded).Finally release tension on an engineered landing base specially built for purpose.
The objectives were fully achieved through this innovative and multidisciplinary engineering and operational approach. Three months of preparation and engineering were required. The operations were carried out safely (0 incidents) and cost effectively (heavy workover to change wellhead avoided). The well was re-connected and put back in production in April 2017. Production is currently at former levels (430,000 sm3/day peaks-choke not fully open).
Well Control for Drilling with Casing: Theoretical and Experimental Insights into Hydraulic Behavior in Small Annular Clearances
Authors: Meza O. Grijalva , Kamp K. , Asgharzadeh A. , Bello O. , Freifer R. , Oppelt J. 
Published: January 2018

Abstract
The technique of drilling a wellbore by using casing instead of drill pipe (Casing Drilling-CD) is gaining in relevance within the Oil & Gas sector since its implementation in the last decades. This technique, aside from the evident reduction in drilling time and costs observed whenn applied is convenient to minder the effects of certain while-drilling issues as those arising while drilling unstable formations. The focus of concern in this work will be the geometry-related aspects of Casing Drilling influencing not only the drilling operation itself but its particular well control needs as well; this latter will be explained in detail.
New Technique to Evaluate the Performance of Hydraulically Fractured Horizontal Wells
Authors: Abdalla Mohamed , Hassan Amjed , Abdulraheem Abdulazeez , Elkatatny Salaheldin , Mohamed Abdelmjeed 
Published: January 2018

Abstract
The horizontal wells are applied to enhance the production rate by increasing the contact area between the wellbore and reservoir, it has been also used to access the highly heterogeneous and unconventional formations. One horizontal well can produce the same amount of 5 vertical wells with a very competitive cost and operational time. Further improvement for the productivity of horizontal well can be achieved by conducting hydraulic fracture operations, especially for low permeable or unconventional formations. This paper shows a new technique to estimate the performance of hydraulically fractured horizontal wells, without a need for using downhole valves or smart completion.
In the literature, few empirical models have been proposed to evaluate the inflow performance of such wells. However, most of these models assume constant pressure drop in the horizontal section, therefore, significant errors were reported from those models. In this work, a reliable model will be presented to predict the well deliverability for hydraulically fractured horizontal well producing from heterogeneous and anisotropic formation. Different artificial intelligence (AI) methods were investigated to evaluate the well performance using a wide range of reservoir/wellbore conditions. The significant of several parameters on the well productivity were investigated including; permeability ratio (kh/kv), number of fracture stages and the length of horizontal section.
The AI model was developed and validated using more than 300 data sets. Artificial neural network (ANN) model is built to determine the production rate with an acceptable error of 8.4%. The model requires the wellbore configurations and reservoir parameters to quantify the flow rate. No numerical approaches or downhole well completions were involved in this ANN model, which reduce the running time by avoiding such complexity. Moreover, a mathematical relation was extracted from the optimized artificial neural network model. In conclusion, this work would afford an effective tool to determine the performance of complex wells, and reduce the differences between the actual production data and the outputs of commercial well performance software.
Well Integrity Model - Klever & Tamano Collapse
Authors: Brechan Bjorn , Kornberg Even , Sangesland Sigbjorn , Dale Stein Inge 
Published: January 2018

Abstract
Better understanding of collapse resistance of casing and tubing can unlock significant value in support of Asset Life Extension (ALE), support routine Well Integrity assessments in every day work and save significant cost by omitting costly oversized designs. Many operators still use the traditional API collapse model, which were accurate for tubulars produced 50 years ago but now underestimate collapse resistance and predicts typically 80 – 85% of the real collapse pressure. Adding to the excess dimensioning is the standard procedure of applying a safety factor to this prediction.
Early 2000, a joint API/ISO Work Group 2b (WG2b) under the Steering Committee 5 (SC5) for tubular goods reviewed casing and tubing performance property equations. ISO/TR 10400:2007, equivalent to API TR 5C3, presents the results from the extensive testing, and the Klever and Tamano (K&T) model for collapse prediction was found to be most accurate. Building on the test data from WG2b/SC5 group, a model was made for collapse pressure prediction of tubulars - hereafter referred to as the "Ultimate Limit Strength (ULS) model", where the simulation result is a prediction of tubular failure. Its predictive accuracy is calibrated with a complete set of data from 113 actual collapse tests offered by the Drilling Engineering Association (DEA). The ULS model was used to predict collapse strength of 9 5/8 inch 53.5 ppf, P-110 casing, using parameters with probability density functions (PDF) for the relevant type of pipe, e. g., quenched & tempered (Q&T), hot rotary straightened (HRS). The PDFs for each input parameter were obtained by measurements of the 113 samples and compared with the PDFs obtained by the WG2b/SC5 group. Random value generators in a mathematical spreadsheet allowed for Monte Carlo simulations to output 100 000 collapse strength predictions for the 9 5/8 inch casing in question. With confidence level of 97.5%, the basic strength was 9900 psi using PDFs from the DEA data set. Using ensemble PDFs, the basic strength was 9500 psi – 19.5% greater than API's standard rating of 7950 psi.
Performing casing and tubing design, the industry practice is to develop load cases to identify the design limiting loads for the well. Once identified, the pipe selected needs to be investigated for factors reducing the collapse capacity further, e.g. axial / triaxial loads and wall loss from wear and tear. Axial loading is accounted for in the ULS model through the theories of Klever & Tamano. Aspects briefly discussed and not fully incorporated in the prototype ULS model are the linear derating factors considering imposed ovality, casing wear and experimental formulas derived for increased collapse strength of pipe in compression. These were conservatively approximated by polynomial curve fitting of an alternative formulation of yield collapse strength and tried in a version of the prototype model.
Pressurized Mud Cap Drilling Drastically Improves Drilling Efficiency in Exploration Well, South Sumatra
Authors: Dipura Yongki Suharya , Ardiyaprana Faruk Bima , Putra Ery M. 
Published: January 2018

Abstract
ARG-1 exploration sour and high CO2 gas well was drilled vertically in South Sumatra, Indonesia, with a total depth (TD) of around 5000 ft-MD. The operation has been facing many challenges in drilling and completion phase; one of them is the occurrence of massive fluid losses in fractured limestone formation. Pressurized mud cap drilling (PMCD) technique is the possible solution to complete this well without sacrifice drilling fluids in enormous volume and minimize non-productive time (NPT).
PMCD is one of managed pressure drilling (MPD) techniques applied in situations when drilling without return to the surface and with a full annular fluid column which is maintained above the formation. The key of successful PMCD technique is the rotating circulating device (RCD) which is used to close the annulus. Furthermore, sacrificial fluid is injected through drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration.
Limestone formation was drilled with 6 in slim hole which is a contingency plan. In addition, the premature set of 7 in casing was to cover the gas zone which is located above the limestone formation. Total loss circulation occurred when drilling through upper limestone formation. Conventional combat loss techniques i.e. spot loss circulation material, gunk plug, and cement plug were used to cure the loss but none of them give significant result. It took approximately 2 months for combat loss with such common technique. In consequence, PMCD technique was decided to apply in this situation and it only required 4 days to drill until TD and ready to run 4-1/2 in casing. By successfully utilizing the PMCD technique, the company was able drastically to reduce the NPT and reach the TD successfully.
This paper presents a case study of the drilling operation in ARG-1 exploration well that had massive loss circulation while using common combat loss techniques were unable to reach TD. Furthermore, it explains how drilling in PMCD mode allowed operation in ARG-1 to reach the TD after total loss of circulation was experienced and how the completion assembly was run and cemented in PMCD mode.
Well Integrity - Next Developments
Authors: Brechan Bjorn , Sangesland Sigbjorn , Naaden Christoffer 
Published: January 2018

Abstract
Step changes in the area of Well Integrity is often based on HSE, production regularity and intervention cost. Well Integrity is a relatively new area of expertise, where small and larger quantitative and qualitative improvements can be expected. With change in technology comes procedural changes. With more significant improvements comes organizational changes. This paper shed some lights on some improvements in the pipeline for future Well Integrity Management.
Some step changes are more evident as new equipment are qualified. Other improvements may be more intangible, like procedural or organizational changes. An overview has been made per phases a well is subjected to, in an approach to understand where it is likely to see progress in the area of Well Integrity. The overview follows a typical life cycle of a well to map out the processes and work where a well's barriers, integrity and containment are either planned, established or active.
One important issue learned from making an overview of the Well Integrity activities through the life cycle of a well is how the work is divided between different groups in an organization with different responsibility and Key Performance Indicators (KPIs). Updating and reporting integrity status, providing performance and reliability data across lines is in itself a challenging task.
The Integrity of a well is often tied to the capacity to contain fluids. The processes which happen on the outside of the barrier envelopes are also important. It can be gas migration leading to sustained casing pressure, exposure to mobile corrosive fluids, subsidence or formation collapse. Traditionally, monitoring pressure in the production annulus has been the main indicator of integrity and source of information. Many operators acknowledge that monitoring the other annular pressures are important and have long desired automatic surveillance of the next annulus.
Effect of the Rotary Steerable System Steering Mechanism on Wellbore Tortuosity in Horizontal Wells
Authors: Alrushud Albaraa , Mohammad Muntasar , Oliveira Victor , Zahrani Bader 
Published: January 2018

Abstract
This paper describes a new approach to evaluating the effectiveness of the rotary steerable system (RSS) steering mechanism on wellbore tortuosity in horizontal wells. Wellbore tortuosity in drilling applications is defined as any unwanted deviation from the planned well trajectory. As reservoir objectives become more complex and exact, operators increasingly perceive the wellbore tortuosity as a serious concern in the process of drilling, completing, and producing wells.
More than 700 wells were reviewed and analyzed in this study. Strict criteria were set during the classification process; the studied wells have a common geology and trajectory, and they use a very similar bottomhole assembly (BHA) design. The inclination values from the wireline tool are used to illustrate the attainable benefits in terms of wellbore quality and measure wellbore tortuosity. In addition, the wireline inclination data are compared with the actual measurement-while-drilling (MWD) survey to highlight the existence of the micro-dogleg severity (DLS) that cannot be measured by standard surveys.
Due to the theoretical differences in the steering mechanism between the various types of RSS, it has been claimed that utilizing one steering mechanism over another can produce a less-tortuous wellbore. These steering mechanisms have previously been classified as either push-the-bit or point-the-bit mechanisms. The relative merits of a push-the-bit steering mechanism vs. a point-the-bit steering mechanism is an over-simplification; neither mechanism can deliver the premium wellbore quality the industry demands from RSS. The present study introduces the continuous proportional steering method (CPSM), and demonstrates how this mechanism can provide superior wellbore quality by reducing wellbore tortuosity. In addition, a superior inclination hold performance is observed in horizontal sections drilled with the CPSM. Curve intervals are more continuous and smoothly drilled through the planned directional changes.
The research becomes a useful reference to analyze the performance and efficiency of RSS steering mechanisms across drilling and workover operations. Directional drilling service companies are encouraged and challenged to improve the efficiency and accuracy of RSS mechanisms, improving the hole quality and reducing micro-doglegs.
Benefits of Utilizing a Fully Mechanical Casing Running Tool on a 630 Ton Casing String in Kuwait
Authors: Saleh Khaled , Al-Shammari Abdullah , Shadad Nawaf , Mujahed Emad , Al-Jarid Meshari Abdullah , Smith Douglas G. , Mattia Chris Della 
Published: January 2018

Abstract
Casing running has historically been recognized as one of the most inefficient and dangerous processes on drilling rigs. Conventional methods carry with them a substantial equipment and personnel burden. This burden results in lengthy rig up/down times, a crowded rig floor and is often responsible for a variety of injuries and occasional fatalities. Recently, Casing Running Tools are being utilized that reduce equipment and personnel required on the rig, advancing the industry toward a safer, more efficient casing running process.
Casing Running Tools greatly reduce the equipment needed to run casing by incorporating many functions into one tool. Less equipment utilizing more intuitive procedures reduces the amount of rig up and rig down time. Both hydraulic and mechanical tools are currently available to the industry. Hydraulically operated tools require a "Hydraulic Power Unit" (HPU) and an operator on the rig floor to control the CRT's operation. Mechanical tools are more compact, do not require HPU's and place complete control of the tool and the casing running in the hands of the onsite driller. For this reason, a mechanical tool was selected for this string.
This paper will cover the results of the run in terms of tool efficiency, tool efficacy, safety, and TRS footprint. Tool efficiency will be compared between a mechanical casing running tool and conventional methods, in terms of rig-in times and run times. This will include considerations between efficiency at the beginning of a run and expected efficiency gains near the end of the run. Efficacy will be discussed in the context of the tool's ability to satisfy its desired function. This is less directly measured but will include input from rig personnel and measurable components such as connection reports. Arguably the most important benefit will be recognized in equipment and personnel requirements, and this paper will discuss the differences in conventional services and the use of a mechanical CRT using conventional services as the baseline for comparison. The discussion concludes with an outline of the benefits realized by the operator, service-company, and other rig personnel.
This publication reviews the first application of a fully mechanical CRT in Kuwait to run a string of casing with premium threads. This is also the first 630-ton casing string run with a mechanical casing running tool in the Middle East Region.
A newly developed wireless Torque Turn Sub that matches the hoist and torque capacity of the CRT was also used to monitor and record the torque on the premium threads.