bluuebunny/crossref_metadata_2025_split huggingface dataset:
Minimising Excess, Mitigating Losses and Improving Cementing Job Quality along Challenging Tophole Sections by a Simplified Novel Spacer-Cement Train: Evaluation of 3 Case Histories Offshore Malaysia
Authors: Brandl A. , Hafizzudin R. Mohd , Mahaiyudin A. Mohd , Hassan H. A. 
Published: October 2018

Abstract
The successful cementation of top-hole sections of three development wells offshore Malaysia has been very challenging since from offset wells nearby the fracture pressure in this section was very low. The section was supported only by an overburden of 328 ft (100 m) of water and 492 ft (150 m) of soil. With such low support, the tophole section had repeatedly hemorrhaged cement into the formation rather than getting good annular cement coverage to surface. As much as 130% more cement than should have been required was wasted in these efforts. In this study we review these case histories and describe how we overcame the given challenges by implementing an innovative spacer cement train.
During drilling of the wells, the inadequate isolation had also allowed as much as 30 bbls/hr of drilling fluids to escape. Analysis suggested that a lighter-weight cement would reduce the pressure on the formation to levels the formation could support, enabling the annulus to be filled with cement without losses. To minimize the losses into the thief zone and to bring up the lead slurry to the desired depth by reducing the equivalent circulating density (ECD) at the top-hole a stable lightweight cementing system was engineered which does not require extenders or lightweight spheres. With this approach we simplified logistics and operations but also brought the quality control of the cementing system to a higher level, since the potential separation between dry-blended lightweight material and cement was no longer of concern.
Laboratory testing was conducted to design this fit-for-purpose solution, which helped to eliminate the amount of synthetic products (such as beads) in the slurry, which greatly reduced its cost. At the same time, the solution provided better properties such as compressive strength development compared to the slurry that had been implemented on previous wells. A sealing spacer system was incorporated into the design to further prevent losses as an additional layer of assurance. As expected, the top-hole sections of the 3 wells were completed with no recorded losses. Cement coverage was confirmed throughout the annulus, and we did not have to pump 130% more cement than required, as we had to on previous wells.
Unlike previously cemented wells in the area with low frac gradient along the top-hole section, the three wells that used the innovative spacer cement train did not suffer subsequent drilling fluids losses because they were adequately isolated. The combined effect of the lightweight cementing system and the sealing spacer was a drastically reduced cement cost and a better ultimate isolation.
An Efficient Gas-Lift MPD Based On Dual-Channel Drillpipe
Authors: Kang Bo , Fan Honghai , Liu Jinge , Wen Zixiang , Deng Song , Wang Shujiang , Chen Yongming , Zhou Yanjun , Feng Guangtong , Li Zongqing , Yan Xiuliang 
Published: October 2018

Abstract
When drilling in the open hole with negative density window, which occurs leakage in the upper section and collapse in the lower section, it will lead to many problems using the conventional method to seal the formation with technical casing, such as high cost,complex casing structure and small completion size. It is difficult to meet the needs of low cost and high efficiency development in the deep wells.
This paper presents a new Gas-Lift MPD drilling method based on Dual-Channel compound Drillpipe (DCP), which can solve the above problems. The DCP is composed of the 139.7mm DCP, the gas lift joint and the conventional 139.7mm drill pipe. It has two circulating channels. Channel 1 is for drilling fluid circulation and channel 2 is directly connected with the upper borehole annulus. The advantage of this method is that it can change the upper wellbore annulus into gas-liquid two-phase flow by injecting gas the channel 2 when the drilling fluid is circulating in the channel 1. It can develop different annulus ECD gradient (small to large) profile and complete complex pressure formation drilling operation in the same open hole section.
According to the design of SBX-5H well, the article uses OLGA to carry out dynamic simulation and analysis of the construction plan of the Gas-lift MPD based on Dual-Channel Drillpipe. The simulation results show that it has great advantages in reducing the number of casing layers, shortening the drilling cycle and enlarging the completion size. Firstly, the control requirements of the ECD profileare is satisfied, which is that the ECD&lt;1.28g/cm3 in the upper section and ECD&gt;1.32g/cm3 in the bottom of the open hole (collapse ECD=1.31g/ cm3, leakage ECD=1.29cm3) by simulating and adjusting drilling pump flow, injected gas flow rate, Dual-Channel Dirllpipe length and drilling fluid density. Secondly, the complicated drilling problem is expected to be solved,such as repeated leakage in the long open hole section. The number of casing layers can be further reduced from 4 to 3 and the drilling cycle is expected to be reduced by more than 20%. Finally, the completion well bore size will be expanded from 149.2mm to 165.1mm (enlarged 11%), which can better meet the requirements of the next production and reservoir transformation.
Through the simulation analysis, it is proved that the Gas-lift MPD technology based on Dual-Channel Drillpipe can effectively solve the problem of negative density window in deep well drilling operation. It not only reduces the drilling difficulties and the drilling cycle, but also is economical and efficient. Therefore, it has a good market prospect.
Integrated Reservoir Modeling while Drilling Enhances Horizontal Well Placement and Productivity in a Complex Offshore Field, Bohai Bay
Authors: Mao Min , Bai Lin Kun , Shen Wen Jian , Li Xiao Qiang , Xia Zhen 
Published: October 2018

Abstract
Horizontal wells are being a common practice in offshore field development in Bohai Bay recently. Maintaining well trajectory in sweep spot while drilling is one of the key factors to optimize horizontal well’s productivity. However, great challenges are often faced in Bohai Bay area including survey uncertainties while drilling and reservoir geology variation. On the one hand, successful placement of a horizontal well requires accurate landing of the well in the right position and orientation in the reservoir. On the other hand, the trajectory is optimized based on structural geobody variation resulted from the uncertainty of parameters governing the static behavior of the field. Therefore, the ability to update geosteering model in timely manner and to proactively adjust well trajectory in real time are required.
This paper presents an innovative method in Bohai Bay by applying the technology of integrated seismic volume and reservoir geosteering model while drilling to achieve very promising productivity. That is to say, the new geosteering method includes seismic inversion of checkshot calibrating, single/multi-wells reservoir model updating, conventional logging while drilling, and mud logging etc. How to develop new horizontal well steering methodology and software integrated seismic volume of time (or depth) domain, logging while drilling, reservoir modeling result to optimize well planning and placement for high productivity?
Results from lower Neogene Minghuazhen formation tests executed in SuiZhong 36-1, Bozhong oilfield of Bohai Bay clearly demonstrate the following capabilities of the technology.Reduction of the steering need for the tools of distance to boundary included Directional and deep well placement tool.A bridge from three-dimensional geology model to two-dimensional geosteering model before drilling; vice versa, 2D geosteering model update 3D geological model after drilling.
More People grasp the systematical methodology of integrated reservoir geosteering model and trajectory optimizing while drilling which provide a higher degree of confidence in the drilling process.
Successfully Drilling an Extremely Complex ERD, HPHT Exploration Well
Authors: Alemi Hassan , Uzu Ugo , Pourtangestani Mehdi , My Lien Ta , Maliekkal Harish 
Published: October 2018

Abstract
To meet the ever-growing demand for oil and gas, operators today are forced to search for reservoirs in more challenging environments characterized as high-pressure high-temperature HPHT using extended-reach drilling (ERD) techniques. A major operator in the Central North Sea successfully drilled a complex extended-reach drilling (ERD), HPHT exploration-production well in the central North Sea presented numerous challenges, This well contains one of the largest outstep HPHT wellbore ever drilled, and contains one of world's heaviest production casing strings. The HPHT environment causes various drilling problems, such as accelerated thickening of drilling fluids, reduction in rate of penetration (ROP), lost circulation, swabbing during pulling out the string, stuck pipe, and hardware failure. The complex nature of this ERD well created specific problems, including torque and drag, hole cleaning, casing running, equivalent circulating density management, and wellbore stability. The operator planned to drill this HPHT exploration and production well by sidetracking from an existing well. In addition to the HPHT and ERD challenges, other drilling challenges consisted of hard rock, high-pressure reservoir, differential sticking risk, a one-way casing/liner run, potentially depleted sands, and possible severe casing wear. These numerous and varied challenges required quick operation decisions to avoid costly overruns.
This paper presents the method used by the operator to successfully drill and complete this complex ERD, HPHT well access a reservoir containing several challenging drilling conditions and potential obstacles to achieving the well objectives. The successful operation demonstrates the importance detailed engineering, communications, and an integrated effort played in successfully delivering this challenging well.
Filter Cake Buildup in Horizontal Wells: Characterization and Impact on Removal Operation
Authors: Hamzaoui Bilel , Al Moajil Abdullah M. , Caliskan Sinan , Aldarweesh Sajjad S 
Published: October 2018

Abstract
The drilling fluid in a vertical well may only be in the pay zone for few hours while in a horizontal well the time can be measured in weeks. This can cause a significant formation damage problem that has the potential for reducing productivity in horizontal wells during drilling operations. A common practice following drilling operations involove filter cake removal operation followed by displacement of wellbore fluids by completion fluid in order to prepare the well for production operations. Presence of drilling fluids in horizontal wells for several weeks is not considered in the design for cleaning fluid recipies targeting drill-in fluid damage. The filter cake buildup time affect its physical characteristics and thus, on the removal process. This study focused on the characterization and the cleanout of the filter cake during the different buildup stages that may occur in the horizontal section. The focus of this study is to highlight the effects of not promptly removing the filter cake.
Filter press instrument was used to simulate filter cake formation on the wellbore wall at 500 psi and 300°F. The filter cake formation process was performed using oil-based drilling fluid at different buildup times (i.e., 3 hours, 3 days and 3 weeks), under 500 psi and 300°F.
The comparison of the different scenarios showed that a thicker filter cake was formed with buildup time (up to 2.5 inch after 21 days). The CT scan results showed that the heterogeneity increased up to 4 layers and the solubility of in the cleanout fluid decreased to 4% by weight.
Driving Efficiencies in Well Intervention Operations
Authors: Yong Yee Tzen , Azizan Yusri , Leong Azemi , Song Yan , Abd Rani Rudzaifi Adizamri 
Published: October 2018

Abstract
Brunei offshore platforms are home to hundreds of maturing wells in need of ongoing interventions. Offshore operations in Brunei face several obstacles, (i.e., weather conditions, ageing platform facilities, limited lifting capability, and limited workspace), as well as tight work schedules that make the work challenging.
As with other mature fields, the Brunei wells need high efficiency operations to reach production targets. These challenges can be addressed with a purpose built compact semi-submersible vessel (CSS) with dynamic positioning (DP 2) equipped with a full catenary coiled tubing unit, a pumping unit with flowback capability, and a dedicated slickline unit.
Dual hull design with a compensated gangway increases the weather working envelope of the vessel. The coiled tubing catenary system with a reel turntable helps enable coiled tubing unit flexibility during rigup and work under varying weather conditions. Integration of the vessel and the coiled tubing unit helps enable a 24/7, 365 day work unit.
Average downtime caused by weather decreased by up to 10%, averaging 8.5% in 2 years, compared to previous work vessels with an average between 15 and 18% downtime because of weather.
Further efficiency improvement is gained through use of fit for purpose equipment. A 35 ton jacking frame helps enable injector and pressure control equipment stack up to be made up, function, and pressure tested offline. A small footprint flowback package was introduced that reduced the total number of lifts from 12 to 6, saving two hours lifting time per rig up/down. Overall rigging up time was reduced by approximately 20% with the improvements to equipment setup.
The reduced equipment necessary on the platform enabled wireline and coiled tubing to operate concurrently. This enables 24 hour wireline interventions to be executed offline more efficiently. Time savings for intervention completion were approximately 62%. This setup enables more efficient use of existing resources to complete the work scope.
The setup, collaboration, and execution on the vessel demonstrate the opportunity for improvement, which is important under current industry conditions, and help enable a cost effective yet robust operation.
A Quantitative Approach to Forecast Well Productivity While Drilling
Authors: Li Maowen , Lei Guowen , Zhang Mingjie , Coskun Sefer B. , Sy Resksmey C. , Hardikar Nikhil P. 
Published: October 2018

Abstract
The WEIZHOU-XYZ project is a newly developed offshore oilfield located in South China Sea. A quick and accurate productivity estimate would add valuable information to the decision-making on further field development, which is divided into three phases as per priority. A luxury dataset comprising seismic, drilling, well logs, well testing and production was acquired from most wells drilled in Phase-1. The objective of this paper is to establish a fast productivity forecasting method that can be used for the newly drilled wells of Phase-2 and Phase-3 after acquiring logging-while-drilling (LWD) data only.
The well-productivity forecasting model was based on uncertainty analyses using the Monte-Carlo method. Starting with equations of the production rate and the productivity index, each parameter of the equations has been investigated based on LWD data, and with a reference to the Phase-1 wells. Two key reservoir data used for the forecasting model are LWD formation testing (formation pressure while drilling - FPWD) and LWD nuclear magnetic resonance (NMR). These two dataset are the main information collected while drilling along with LWD resistivity and gamma ray in Phase 2. The FPWD data provides mobility, thus indicating the ability of fluid flow through the permeable reservoirs. The LWD NMR data provide continuous porosity measurement. Additionally, the T2 relaxation sensitives to both the pore size distribution and fluid properties providing estimation of formation permeability and fluid viscosity. Differing from the conventional way of a constant value input to the production rate equation, the proposed method sets all productivity related parameters (permeability, thickness, formation volume factor, viscosity, drainage radius etc.) under an uncertainty distribution range. The productivity prediction model is processed and evaluated using Monte-Carlo simulations. A scenario of 10,000 runs were conducted to account for the possible production distribution. As a result, an expected value of production rate or productivity index is used for the delivery of the possible forecasting outcome.
In this study, a successful application of this forecasting model has been proven by a good match with actual results from a well test. The observed difference is less than 5% between the real production rate and the expected value from the forecasting model.
This paper shows that formation testing while drilling and NMR while drilling together provide valuable inputs for productivity forecasting. The integrated method would be very helpful and meaningful for the production evaluation and decision-making for the Phase-2 and Phase-3 development wells, which will have limited data acquisition. A Monte-Carlo simulation workflow has been proposed for quantitative prediction.
Step Change in BHA Reliability and Performance Due to Utilization of Downhole Drilling Dynamics Services
Authors: Reckmann Hanno , Hohl Andreas , Oueslati Hatem , Akimov Oleg 
Published: October 2018

Abstract
To reduce cost, drilling operations are getting longer, both in time and distance. Simultaneously, drilling parameters are optimized to reach higher performance for a maximum rate of penetration (ROP). The drawbacks of these practices are increased static and dynamic loads such as bending stresses, torque, and vibration on the drilling system. These parameters can greatly fatigue even the most robust drilling tools. Downhole drilling dynamics services must be used to ensure reliable operation with optimum performance.
This paper discusses the general challenge to balance reliability and performance. For this process, tools are needed to measure the respective downhole data. A database is required to help connect downhole dynamics data and surface data like drilling parameters such as weight on bit and rotary speed, with context data such as geological formation and system reliability. To analyze dependencies and optimization approaches, it is necessary to review the data in various ways and from different perspectives through the data sets. This review can be achieved by using crossplots in various dimensions.
The recording of downhole data with sampling rates exceeding 1000Hz and subsequent analysis of high-frequency drilling data provide insight into the excitation mechanism for vibrations. Additional statistical analysis of the data reveals the true load profile on the drilling system and its origin, enabling optimization in two ways. The tool or system design is optimized for reliability considering the identified loads, and the loads are minimized by optimizing the drilling parameters. Novel modeling techniques enable estimation of the dynamics load distribution over the bottomhole assembly (BHA), even from a single measurement position. Analysis shows that the main dynamic loads stressing the system are lateral vibrations and high-frequency torsional oscillations. Temperature effects also play a significant role for electronics. Statistical models support the decisions to retire tools or components and any re-run decision.
The use of drilling dynamics services and the real-time downhole data ensure informed decisions during the drilling process, optimized performance by minimizing loads on the system, and maximized ROP with optimal drilling parameters. The collected downhole data, in combination with context data and reliability data applied in the design process, lead to fit-for-purpose designs of the latest drilling tools.
Effect of Synthesized AMPS-g-Clay/CuO NanoComposite on WBDFS for Challenging Formations
Authors: Kumar Nitesh , Kumar Akaash , Kumar Saket 
Published: October 2018

Abstract
An attempt has been made in this work to formulate a novel water based mud system with acrylamido-methyl-propane sulfonate polymer (AMPS) grafted clay/CuO nanocomposite for drilling the high temperature troublesome shale formations. Literature survey found several water mud applications of AMPS polymers in the high temperature and high salinity environment as they are highly water-soluble anionic additives. On the other hand, investigators have reported very encouraging results on rheology and fluid loss control, shale impact, well bore stability and strengthening, cuttings lifting capacity and suspension and impact on thermal properties with CuO nano particle. The improvement in rheological and fluid loss control can be attributed to the fact that pore size studies on shales have suggested nano pore size of 2-50 nm. Conventional shale stabilizers and polymers contained in a water based mud cannot plug nanopores of shale. Therefore, water invades into the wellbore, and results in high mud filtrate volume and clay swelling. Given above, AMPS grafted clay/CuO nanocomposite is expected to improve on the CuO nano particle (NP) performance and provide an excellent solution to plug nano pore size of the shale. Hence, in this paper we tried to develop a synthesized additive which assists the drilling mud to provide better bore hole stability and well integrity while drilling the formations.
Optimizing Heavy Oilfield Development through Innovative Logging While Drilling and Horizontal Well Steam Stimulation with Multiple Fluids Technologies in Bohai Bay
Authors: Zhang Binqi , Liu Feng , Zhang Bo , Zuo Cunhai , Zhang Xiaowei , Yu Xiaoning , Wang Fei , Xu Tianyun , Wu Kai , Hu Zhong , Yuan Xiangwei 
Published: October 2018

Abstract
More than 70% reserve explored in Bohai Bay, northern offshore field in China, could be categorized as heavy oil. Only relying on the conventional production process leads to both low production rate and low recovery rate. Take NB-N oil field as an example, which started production in Oct-2005. As of April 2011, there are a total of 27 development wells, with a daily oil production of 174 m3, water cut up to 77%, and recovery rate 0.2%. The oil recovery rate is 1.52% OOIP (Original Oil in Place) only, which does not meet the expectations.
To optimize the heavy oil reservoirs production, a series of comprehensive studies and field test were carried out in the Bohai field. Innovative Logging While Drilling technology was deployed to provide distance to boundary (DTB) detection ability and combined with Rotary Steerable System (RSS) technology, which enables the wellbore to be close to target roof and maximizes reservoir exposure as the result. According to the reservoir characteristics, oil recovery technology of steam stimulation with multiple fluids (SMF) by injecting steam and non-condensate gas into oil reservoirs increases production rate. The injected gas not only enlarges the influencing scope for thermal production but also reduces viscosity together with the injected heat, thus lowering the requirements for thermal production, reducing heat loss and improving the economic feasibility of thermal production.
The paper will feature the best practices of utilizing the above innovative approaches to optimize horizontal well drilling and enhance the heavy oil reservoir performance. Several key outcomes have been observed in this project: Five horizontal wells were drilled with 100% NTG and lateral sections were place close to target top to minimize attic oilWith the SMF technology, the average single-well daily production was increased from 10-20 m3 to 50-60 m3 when cold production process was used. The effective production period lasted 300-400 days.
The successful application of innovative technologies in NB projects, has improved both oil production and recovery rate of this heavy oil reservoir. Ultimately, this has enabled the economic use of heavy oil reservoir, especially in the Bohai Bay. The author also believes this approach could be extended to the similar type reservoir as a fit-for-purpose solution.