bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Deployment of Next Generation High Pressure High Temperature Multistage Cementing Tool
Authors: Albassam M. , Al-Yami A. S. , Almalki B. 
Published: January 2018

Abstract
Differential Valves are used in multistage cementing tools to ensure having adequate cement placement and enhanced wellbore isolation. Multistage tools are recommended to use if the formation is unable to support the hydrostatic pressure of the cement column. In cases of lose circulation, multistage tools are used at designated depth to help placing cement all the way to surface.
There are two types of multistage tools: conventional ones that can withstand low-pressure rating and more recently developed high-pressure rating tools. The low-pressure rating tool is used to support cement placement and is not considered as mechanical barrier against high-pressure formations. The high-pressure tools were developed based on additional requirements to improve wellbore isolation in high-pressure gas wells.
The objective of this paper is to: Highlight the importance of multistage cementing tools and to de-risk their useProvide best practices to overcome common multistage tool issues
Potential malfunctions can be due to either mechanical components malfunction or improper operational practices. These can be further divided into 4 categories, which are: packer issues, opening/closing DV ports, and drilling practices such as encountering losses while cementing and finally improper running operational procedures. This paper includes intensive review of actual runs including frequency of multistage tool issues based on casing size.
Different mitigation plans are recommended for each potential issue and optimum drilling practices to overcome them. In addition, high-pressure multiage tools performance will be highlighted in improving wellbore isolation since their initial deployment 3 years ago.
Case Study for Curing Circulation Losses during Primary Cementing Operations Using Fiber Cement in Zubair Field/Iraq
Authors: Hussein Maher Falih , Eren Tuna , Rahman Ahmed , Ghidoni Carlo , Talib Basheer 
Published: January 2018

Abstract
The giant Iraqi Zubair oilfield is a hotspot for drilling activities. Many vertical and directional wells have been recently drilled in this oil field. Losing cement slurry into karstic facies of the Hartha formation is the main challenge on most wells. Achieving required top of cement behind the intermediate casing is a critical challenge because this casing is the main barrier against the corrosive sulfurous water of the underlying Um Er-Radhuma and Tayarat formations. In this field, in spite of the tremendous time and effort that have been spent to mitigate losses while drilling and before cementing, at least 55% of wells experience losses while cementing. Various conventional treatments have been implemented to bring cement to the surface in primary cementing operations, including one stage with lead and tail slurries and two stages with two cement slurries (lead and tail) for the second stage. Even when ample amount of extra excess of cement has been used for the second stage to compensate for the cement lost during first stage, there was still a need for top jobs subsequently after the cement job. Recently, the field applications of fiber cement have shown substantial success compared to the case of using only cement slurries as lost circulation material. This was confirmed by getting returns when displacing cement across the lost circulation zone (Hartha formation) in five out of six wells. The cement jobs of the six wells have been revised, and use of fiber cement has now become a standard practice for cementing the intermediate casing strings in this field. In addition to presenting six case studies in the use of fiber cement, this paper describes the previous efforts at solving the problem and the success criteria. This paper also discusses the mechanism and the properties of using fiber within cement slurries for curing lost circulation while cementing in fractured formations. Laboratory tests were conducted to evaluate the plugging efficiency and the magnitude of the developed compressive strength.
In-Situ Thermal Rheological Properties of Drilling Muds
Authors: Ettehadi Ali , Altun Gursat 
Published: January 2018

Abstract
Thermal rheological properties of three drilling fluids suggested for hot environments were experimentally investigated using both HTHP dynamic rheometer and classical viscometer. Two of them were polymer based muds commercially used in geothermal drilling, and the third one was sepiolite base mud prepared with specially mixing order in this study. Rheological measurements at six different shear rates were performed in a programmed temperature range of 100 to 500°F with 10°F increments at a 700 psi of pressure differential. Flow characteristics of sample muds in a given well geometry were also considered using a numerical application.
Two polymeric muds sampled from a geothermal field in Turkey exhibited very low viscosity with a low thermal viscosity variation interval at temperatures above 300°F. In contrary, the sepiolite mud demonstrated higher viscosity and kept its stability with increasing temperatures up to 500°F. Findings also indicated remarkable viscosity differences between the conventional viscometer and the dynamic HTHP rheometer. Hydraulic optimization in terms of circulation pressure losses, cutting transport, and surge and swab pressures were numerically modelled. Optimization results based on conventional viscometer measurements generated noticeable errors causing difficulties through drilling program. Numerical application revealed that the usage of improper viscosity values resulted in calculation of well design parameters beyond the safe drilling limits.
Through this study, it was revealed that sepiolite based muds could be good candidate for drilling hot and/or hostile wells such as deep oil and gas wells, geothermal wells, and drilling through high saline formations. As excessive temperature through wellbore can lead to serious well problems, selecting thermally stable mud with proper rheological properties to improve penetration rates, hole cleaning properties, and borehole integrity can clearly express the importance of this study.
Ultra-High-Strength Proppant: An Update on Deepwater Applications in the Gulf of Mexico
Authors: Saldungaray Pedro , Palisch Terry 
Published: January 2018

Abstract
With the advent of the development of lower Tertiary formations in the deepwater Gulf of Mexico, a gap in proppant technology was identified at the beginning of the decade. No existing conventional proppant could provide the required conductivity at the anticipated 15,000 psi (and higher) prevailing closure stress. To meet these challenges a new proppant was developed, with the goal of achieving twice the baseline conductivity of any conventional proppant at 20,000 psi.
Improvements in the manufacturing process lead to the required superior performance needed in extreme depth and stress environments. The shape of the new Ultra-High Stress Proppant (UHSP) is highly round and spherical with a mono-sized sieve distribution. At higher stresses, this means the UHSP will provide higher proppant pack porosity and ultimately more space to flow. In addition, the surface of the proppant is very smooth, leading to lower Beta, as well as reduced erosion potential. An extremely low internal pellet porosity evenly distributed in fine pores results in much stronger grains, with crush value of less than 2% at 20,000 psi for 20/40 mesh equivalent product. Additionally, the new proppant technology provides further advantages with increased durability and longevity, as well as significantly reduced erosion on downhole tools and equipment.
Further to the ultra-high stress applications the new manufacturing technique was applied to ores typically used to manufacture low density ceramics. The result is a proppant with equal or better conductivity than standard intermediate and high density ceramics leading to larger frac volume and better carrying capacity. This new low density ceramic can effectively replace the use of conventional ceramics from low to medium and high stress applications and in many cases reduce the costs associated with pumping these higher density proppants.
This paper will briefly review the manufacturing process and resulting step change advancements achieved by this new proppant, stressing on the technology adoption in the Gulf of Mexico illustrated with multiple case histories. This paper should be beneficial to all engineers and technologists currently working in fracturing applications from low to ultra-high stress, or other harsh conditions such as steam-flooding and geothermal applications.
Study on World Drilling Limit Envelope and Break its Limitations
Authors: Li Xin , Gao Deli , Wen Chang , Zhang Hui , Gu Yue 
Published: January 2018

Abstract
Why the world drilling limit envelope shows an irregular triangle as a whole and how to break its limitations? Many scholars have carried on the related researches, the authors also give theoretical reason, including the influence of borehole space, bearing capacity of drilled formation, mechanical factors and hydraulic factors. In this paper, the authors provide the effects of drill pipe tripping in/out and casing running on the world drilling limit envelope. Meanwhile, the drilling extended-reach limit optimization model is also established, its parameters include objective and subjective factors. The objective factors mainly refer to the formation factor; and subjective factors mainly include three types of parameters: drilling constraint parameters, wellbore design parameters and specific operating conditions. The subjective factors in the drilling extended-reach limit optimization model is mainly divided into the following three situations: the variation of drilling constraint parameters, the variation of wellbore design parameters, the drilling constraint parameters and the wellbore design parameters change simultaneously. In addition, the horizontal extended-reach well (ERW) is the well type which most frequently breaking world drilling record in recent years, and also the well type most likely to break the drilling world record in the future. Moreover, the concept of effective extended-reach limit is proposed. The borehole trajectory design is optimized using genetic algorithm, reducing the well's extension in non-reservoir formation and improving the effective extended-reach limit, so as to break the world drilling limit envelope. This work provides a practical tool for explaining why the world drilling limit envelope shows an irregular triangle and how to break the envelope's limitations, which is of great significance for the development of drilling engineering and improvement of economic benefits.
A Novel Multiphase Hydrodynamic Model for Kick Control in Real Time While Managed Pressure Drilling
Authors: Zhou H. , Fan H. , Wang H. , Niu X. , Wang G. 
Published: January 2018

Abstract
Managed pressure drilling (MPD) technique can stop and remove a kick without shut-in procedure while keeping the bottomhole pressure relatively constant while a kick was detected. But the key for a successful kick removal operation depend on accurate, real-time knowledge of wellbore hydraulics. Therefore, the transient multiphase flow calculation for MPD kick control should be developed for obtaining high-precision hydraulics.
Firstly, a real-time multiphase hydrodynamic model for kick control of MPD was proposed, in which the gas solubility in drilling fluids is take into account. Because of the well head pressure need to adjust in real-time during MPD, therefore the influence caused by real-time adjusting of WHP for gas migration and phase change was take into account too. And as a consequence there are more boundary conditions and dynamic parameters of this model than the traditional multiphase model. Secondly, the finite difference method was used to solve the proposed model, and then a comprehensive solution procedure is proposed, in which the different boundary conditional mode of MPD is considered, based on which the numerical solution of kick control for different MPD mode can be obtained easily. Moreover, a series of system calculation software were developed to predicted pit gain, flow patterns, circulating pressures, gas top, bottomhole hydraulics and the related control parameters for control the kick while MPD.
The proposed model has been verified with experimental data collected from scientific experimental well of SINOPEC, there is an excellent match between the calculated and measured data and the calculation accuracy is higher than 95%. Furthermore, this calculation software has been used for analyzing the MPD kick control during drilling shale gas horizontal wells of SINOPEC, and it runs smoothly with convenient operation. Therefore it can be seen this system can be applied to provide more convenient fast and precise dynamic parameters monitoring for control kick while MPD.
This paper established a novel real-time multiphase hydrodynamic model and a systematic calculate software, which has been verified with experimental data and applied in shale gas field. Through the field application, the results show that it can provide more accurate prediction of wellbore multiphase flow parameters. Therefore it can be seen that this novel method can be applied for MPD kick control to provide more precise dynamic parameters for kick control while MPD.
First Run In the GCC Of Hybrid Cable DTS And DHPG
Authors: Mutawa Ahmed Abdulla , ElBarbary Abdalla Youssef , Quintero Fernando , Awad Abdul Salam , Khaled Moutaz Faysal , Al-Mansi Mohammad Kamel 
Published: January 2018

Abstract
Permanent down Hole Gauges (PDHGs) are typically run in combination with Distributed Temperature Sensing (DTS) cable with Wellbore Segmentation using Swellable Packers. The interpretation of the signals of the DTS/PDHG is complex, but it provides the possibility to identify change in production / injection profile along the completion and changes to the composition of produced fluids. Permanent down Hole Gauges (PDHGs) is a system enables the user to measure the reservoir pressure and temperature at single fixed point on real time basis. Distributed Temperature Sensing (DTS) is a technology which provides the user with a technique to measure the temperature in a well (from the surface to the TD of the well) distributed along the fibre optic line at any time.
Several challenges were anticipated and measures were taken to minimize the risks of such implementation to ensure smooth deployment successfully.
Successful Installation of Multi Task Valves MTV with New Generation ICD in The Middle East Sandstone Reservoirs Simplifies Deployment's Operation and Optimizes Well Performance
Authors: Al-Arji Hamad Mohammed , Abu Faizal Syed , Suherdiana Hedy 
Published: January 2018

Abstract
Inflow Control Device (ICD) are deployed as a part of downhole completion across the horizontal section in consolidated or unconsolidated formations to overcome challenges posed by long horizontal drains like heel to toe effect and formation heterogeneities. The main objective of ICD completion is to delay water or gas breakthrough by enabling equalization of flux along the wellbore and promote oil by chocking back water in case of water breakthrough.
Recently, for the first time in sandstone fields, a new ICD generation combining three advanced features in one was successfully installed enabling simple and safe deployment of an optimum completion design for a long horizontal well. The new ICD is a combination of new hybrid ICD design, multi-tasking valve (MTV) and premium sand screen.
The new ICD generation incorporates a hybrid design in which the fluid flows in a labyrinth path to achieve optimum pressure drop. The new design makes the ICD highly density dependent and insensitive to viscosity while maintaining a larger flow area which makes is less prone to plugging and erosion compared to conventional ICDs. MTV, a delayed opening valves incorporated into the ICD allowing them to act as a pressure containing liner component. This enables a true flow through full circulation from the bottom of the completion assembly eliminating the need of inner string during deployment.
Having MTV feature in the ICD has made the deployment not only simple and safe but also saved considerable amount of rig operation time compared to conventional ICD screens by eliminating the need for inner string. Risk of low productivity of well due to screen plugging by mud solids in OBM was also reduced by achieving a higher annular velocity during deployment and pumping wellbore clean-up treatment fluid.
This paper will discuss the benefits of the new generation ICD on completion operation based on experience from the first deployment and highlight the operational cost saving by reducing the rig time. In addition, the impact of the new hybrid design on the well production performance will be discussed highlighting the post drilling benefits and how it would prolong the well life.
The Study on Hydraulic Fracture Initiation and Propagation of Coplanar Perforation Technology in the Horizontal Well
Authors: Zhang Ruxin , Hou Bing , Shan Qinglin , Lin Botao , Lu Yunhu , Wang Yajun , Zhang Xiang 
Published: January 2018

Abstract
Coplanar perforation is a new perforation technology with unique perforation position that can improve the efficiency of hydraulic fracturing of horizontal wells in low permeability reservoirs which have low porosity, low permeability and are difficult to explore. So it is important to know how fractures initiate and propagate as well as the optimal perforation parameters.
A large-scale true tri-axial hydraulic fracturing simulation experiment is conducted to study fracture initiation characteristic and propagation pattern of coplanar perforation in horizontal wells under different in-situ stresses, compared with conventional helix perforation in horizontal wells under the same in-situ stresses. In the meantime, the three-dimensional finite element method is used to study the influences of different perforation parameter combinations set according to field data on fracturing pressure in horizontal wells, including shot length, shot diameter and shot density.
The experiment results show that the coplanar perforation has simpler fracture propagation pattern under higher stress difference and has following advantages compared to conventional helix perforation: (1) reducing the fracturing pressure, (2) controlling the fracture propagation to reduce the complexity of near-wellbore fracture and (3) reducing the near-wellbore friction resistance. The numerical simulation results show that: (1) the fracturing pressure does not decrease linearly as the shot density increases, it falls rapidly when the shot density increases from 9 to 15 holes per meter, but when the shot density increases from 15 to 21 holes per meter, it falls slowly and finally remains almost constant, (2) the fracturing pressure decreases as the shot diameter increases, and (3) the fracturing pressure stays the same as the shot length increases. Through the conclusions of experimental and numerical simulation, we could provide some valuable suggestions to the hydraulic fracturing on filed. During hydraulic fracturing process in low permeability reservoirs, coplanar perforation technology with high shot density (21 holes/m) and large shot diameter (0.03m) should be used.
The experimental and numerical simulation conducted in this paper show a real process of hydraulic fracturing with coplanar perforation. The advantages and optimal perforation parameters of coplanar perforation are proposed to give guidances for hydraulic fracturing on field.
An Enhanced Experimental Method to Assess the Shale Inhibition Durability of Inhibitive Water-Based Drilling Fluids
Authors: Al-Arfaj Mohammed K. , Amanullah Md , Mohammed Al-Osail 
Published: January 2018

Abstract
When drilling shale formations with water-based drilling fluids, wellbore instability problems arise from the interaction of water with clay minerals. As a result, there will be higher solids loading into the wellbore and the borehole diameter will not be constant along the depth of the well. Hence, the chance to get pipe stuck increases and the hole cleaning efficiency of drilling mud decreases significantly. To combat shale drilling problems, different types of inhibitive water-based muds were developed. The performance and effectiveness to inhibit shale formations vary between one type of shale inhibitors to the other. Oil and gas industry has standard procedures to test the inhibition performance of drilling fluids such as dispersion test and swelling test. This paper builds on that and introduces a method to test the long-term shale inhibition capability of shale inhibitors. Due to the presence of some unique geological conditions, sometimes there is a need to replace a high cost inhibitive mud by a low cost non-inhibitive mud to drill the next formation. If the original inhibition provided by the inhibitive drilling fluid does not last long enough to drill the second zone, the previously drilled inhibitive shale formation starts reacting again with the non-inhibitive drilling fluid leading to various drilling problems. Hence, there is a need for isolation of the reactive shale zone by a casing string before drilling ahead. Inhibitive muds with long-term inhibition potential such as 24 hours or more may eliminate the need of a protective casing for the previously drilled shale formation.
7- × 4 1/2-in. Monobore Completion System Capable of 15-ksi Treating Pressures in Hydraulic Fracturing Applications for Deep Gas Wells
Authors: AlGhuryafi Ahmed M. , Garrido Cruz Raul A. , Ashby Scott F. , Abuelnaga Ahmed 
Published: January 2018

Abstract
The increasing need for completions to be capable of withstanding higher treating pressures, combined with complex well geometries and cementing requirements, led to the development of a new 4 1/2-in. completion system that includes liner systems to facilitate isolation objectives, and upper completion systems to create a monobore conduit. This new monobore completion system is rated for 15,–KSI target surface treating pressures.
Traditionally, cementing and isolation objectives have been achieved using liners and liner hangers capable of deploying those liners and also isolating the target zone. To achieve a monobore completion design, an integral tieback receptacle (TBR) is used to tie the liner back to surface. The integral TBRs currently used are either too short to enable the necessary tubing movement stroke, or rated too low to enable the required treating pressure.
A solution was developed integrating a lower polished bore receptacle (PBR) below the liner hanger that is capable of withstanding the pressure requirements, and using a compression-set anchoring system to anchor a seal assembly inside the PBR. To account for tubing movement and help reduce mechanical loading on the tubing and upper completions components, a PBR is placed above the compression-set anchor.
This arrangement enables the liner hanger systems to be isolated from treating pressures, which helps remediate limitations associated with traditional completion systems. Considering that the liner hanger is isolated from tubing treating pressures and that the compression-set anchor does not isolate annular pressure, the TBR on the liner hanger is pressure-balanced, no longer exceeding the pressure limit. Furthermore, tubing-casing annulus (TCA) pressure that is normally applied during stimulation can now support the liner hanger and lower tieback seals.