bluuebunny/crossref_metadata_2025_split huggingface dataset:
Engineered Fluid Design Helps Drilling the Longest Horizontal Section in Record Time – A Case Study from Turkey
Authors: Sheer Shahad , Karakaya Guray , Gadhiya Ketan , Addagalla Ajay , Kamel Mina 
Published: November 2020

Abstract
Drilling extended lateral sections to maximize reservoir exposure is key to optimizing field production and data recovery. However, it presents peculiar challenges not limited to hole-cleaning, wellbore stability, narrow drilling windows, and excessive torque and drag. Thus, customizing the fluid system to drill lateral sections requires information to understand the formation characteristics, including geomechanical data to determine the correct mud weight window, a precise selection of optimal fluid rheological properties, good inhibition, and lubricity, which are of foremost importance for extended-reach drilling (ERD) wells.
The reservoir section of the well presented in this paper was previously drilled unsuccessfully twice, as the targeted zone was not reached. During the drilling phase, a large amount of non-productive time (NPT) was observed due to stuck pipe incidents, hole collapse, and then, hole cleaning issues were encountered while drilling. Another critical concern is the narrow mud weight window range, which causes the formation to break when Equivalent Circulating Density (ECD) increases beyond the pore pressure or fracture pressure of the formation.
A new generation of High-Performance Non-Aqueous Based Mud (HPNBM) was engineered to drill these types of complicated, long horizontal intervals matching the drilling performance required to drill such sections and deliver a perfect gauge hole. This HPNBM provides high shear-thinning properties, an excellent low-end rheological profile, and rapid-set/easy break gels. This paper presents a successful well delivery of drilling the longest horizontal section in the country within a record amount of time. The previous attempts were carefully studied to identify the challenges associated during drilling and considered while designing this HPNBM. The high-performance non-aqueous based mud system proposed with stress caging technique was successful, economic, and drilled successfully with zero non-productive time (NPT) related to drilling fluids. Engineering software was utilized as hole cleaning is critical for drilling the horizontal sections to reach the targeted depth and run casing to the bottom.
This paper presents the longest horizontal section (4,200 ft) to be drilled to the targeted depth as planned in Turkey. A comprehensive analysis that includes the planning phase, application, techniques, and performance of the mud system will be presented.
Optimised Pumping Design for 100% Pack Efficiency in Open-Hole Gravel Packs: A Field Study from Offshore Republic of Congo
Authors: Hubert Thomas , Chembou Mike Tony , Dupouy Nicolas , Ilyasov Robert , Nkala Christian Moumboko , Reilly Brett 
Published: November 2020

Abstract
Achieving complete and efficient gravel packing is the primary objective when tasked to install an effective sand control completion. This paper describes the challenges faced during the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the "L" field, offshore Republic of Congo. The open hole gravel packs (OHGPs) targeted the most prolific sand to ensure production objectives were achieved with the benefit of a gravel-pack completion.
The operator completed two OHGPs with alpha/beta technique for the sand face completion utilizing concentric annular pack screen (CAPS), wire-wrap screens, and a service tool permitting post-gravel pack filter cake clean-up treatments. The accurate selection, modeling, and evaluation of sand control techniques were crucial for completion and production optimization, as well as risk minimization. The service approach had traditionally leveraged upon industry rules of thumb and previous experience, but as the reservoir section length increased and completion configuration became more complex, the error margins tightened and the cost of failure increased such that a more robust design approach was needed.
This paper addresses several key factors that must be considered carefully when installing a successful gravel pack completion. The dynamic pressure management becomes critical to maintain the bottom hole pressures within a required range for the successful implementation of the gravel pack. Other factors include designing an optimal screen-wash pipe annulus ratio during alpha-beta wave packing, an optimal alpha wave height, and the use of multiple beta wave packing rates.
Results from the preliminary modelling of the gravel pack pumping provided an accurate estimation of the maximum and minimum anticipated pumping rates and pressures. These parameter estimates were generated for the workstring design scenarios and provided guidance for the planned pumping rate adjustment during the gravel packing execution phases. The gravel packed wells achieved pack efficiency greater than 100% based on an estimated 8.5-in. diameter OH. Post completion multi-rate tests concluded potential productivity exceeding the operator's expectations.
This paper describes the lessons learned and best practices developed for offshore Congo open-hole gravels packs, which have a very challenging well completion and reservoir scenario. Several proven completion practices are reviewed, with a critical examination of the application of these scenarios for future completion operations in this difficult operating environment. This applied methodology has made significant impact on future field development and increased the production expectations for the asset.
Novel Thru-Tubing Sand Control Solution: Defining the Operating Envelope
Authors: Barclay Amy , McKay Eilidh , Stewart Suzanne 
Published: November 2020

Abstract
In mature basins, sand issues can account for up to 10% of all shut-in wells either due to failure of the existing downhole sand control or onset of sand production caused by pressure depletion and/or water production. Existing remedial methodology to address sand management include allowing sand production and managing it at surface, managing production rate to minimise solids production, running an insert sand screen, applying consolidation treatment or performing a remedial gravel pack. All of these methods vary in complexity, cost, risk, longevity and effectiveness and have associated weaknesses often resulting in reduced production or in extreme cases, loss of surface containment due to erosion.
A novel remedial solution was developed to enable compliant sand free production to be restored effectively and efficiently and to be compatible with thru-tubing operations, including live well deployment and single trip sand clean out. This solution includes a new filtration mechanism using an Open Cell Matrix Polymer (OCMP) filter run compressed within a sleeve to allow passage through tight restrictions which then decompresses to be conformant with a significantly larger inner diameter (ID) of the area requiring sand control when the sleeve is removed. The system has additional functionality that allows sand in the wellbore to be cleaned out in the same trip. The inclusion of both new deployment and filtration mechanisms meant that existing testing and filtration sizing criteria could not be applied.
This paper describes the unique qualification program and development of new testing practices that were undertaken to qualify the solution and enable the operating envelope of this technology to be defined.
Openness in Reservoir Simulation: Empowering Flexible Field Management
Authors: Zhou Wentao , Ali Samad , Biniwale Shripad 
Published: November 2020

Abstract
As the oil and gas industry enters the digital era, openness is a key enabler to realizing the vision of transforming the industry for the better. The practice of reservoir engineering and reservoir simulation is no exception. In this paper, an openness mechanism in a reservoir simulator using Python scripting language is introduced. It empowers engineers to utilize simulation in new ways. It extends simulator capabilities and enables people to implement flexible-control logic to solve field management challenges.
The new openness mechanism in the simulator allows engineers to program and include Python scripts in a simulation model. These scripts interrogate and interact with the simulator. The scripts are executed by the simulator while running the model. Flexibility is available to execute the scripts at every Newton iteration, before and after every simulation timestep, at specified times, or when a criterion is met. Simulation model properties can be queried through the scripts, such as well connections, well properties, group properties, grid region properties, network entities, current simulation time, etc. The scripts can set properties such as well constraints, well and connection productivity index (PI), group production target, pausing or stopping the run, etc. Customized control logic, if not directly available in the simulator, can be implemented in the scripts that interrogate and drive the simulator. Such customization can be packaged as Python libraries and shared with team members, enabling continuous value creation. Public Python libraries, such as NumPy, pandas and pywin32 or win32com, can also be loaded in the scripts to extend even further what the simulator can do.
The openness mechanism is demonstrated on case examples. They include customized action to acidize wells when production drops, approximating the geomechanical effect of decreasing well pressure, modeling the effect of fines in injected water on well injectivity, and connecting to a network simulator. Examples are also given on customized reporting for model diagnostics and result interpretation, setting production constraints based on economics calculated in an Excel sheet with complex fiscal regime, advanced gas accounting, management of sulphur content, dual-optimization to meet gas demand while honoring oil treatment capacity, and integrated asset modeling from reservoir to surface networks to processing facilities.
the ability to extend built-in functionalities of a reservoir simulator and customize field management controls using user scripting language. It embraces innovation and enables continuous value creation in reservoir simulation.
Intelligent Completion Implementation in Immiscible WAG Wells in a Mature Offshore Field EOR Project
Authors: James Berok Sylvia Mavis , Sinanan Haydn Brendt , Tan Chee Seong , Kalidas Sanggeetha , Goh Gordon 
Published: November 2020

Abstract
As part of the enhanced oil recovery (EOR) field development plan (FDP), four immiscible water alternating gas (iWAG) wells with intelligent well completions were successfully completed. Inflow control valves (ICV) with dual-permanent downhole gauges (PDG) in each zone were installed to allow remote injection control and monitoring. Each well has three zones. One of the iWAG wells was installed with the DTS cable behind casing. This enabled the injection profile monitoring across each sand in order to optimize the injection rate distribution and representatively amongst the four wells. The paper further discusses the injection strategy to meet the required zonal injectivity and reservoir zonal voidage replacement over field production life.
Downhole water injection conformance is critical for managing thin oil rim reservoirs. The injection plan considered several factors including uneven zonal split injection, short-circuiting injector to producer issues, and unfavourable zonal water-front propagation and changing injection scenarios over time. Hence, zonal control with optimal valve design is critical in achieving the EOR reservoir management plan. Injectivity and conformance modelling was performed on four iWAG wells across three reservoir zones to ensure optimal valve-sizing configuration for comingled injection multizone. A base case simulation assuming no downhole zonal control (all zones fully open) was first performed to understand the zonal injection performance and distribution contrast for both water and gas injection. This subsequently served as a guide for the zonal injectivity control strategy. This was followed by modelling valve sizes across a variety of injection scenarios. This was done to ensure the design working range for balancing future zonal injection selectivity under expected uncertainty range.
Post deployment ICV modelling was performed with cross-reference to actual petrophysical data, reservoir properties, and well trajectories. Petrophysical evaluation showed some zones are having lower permeability with low fracture pressure. Step rate injection test data was used to calibrate the model and to further validate whether the valve sizes were within the design ranges prior to the injection phase. Based on the simulation using surface injection rates and PDG pressure data, most of the zones were able to meet the target injection rate within the set fracture pressure. The model will then be further updated with the zonal injection data in the future as the iWAG injection program is implemented.
Improving Well Delivery by Integrated Geomechanical Understanding with Robust Well Planning and Execution: A Successful Case Study from a Development Drilling Campaign in Offshore Peninsular Malaysia
Authors: Tello Roberto Horacio , Wong George , Ghosh Amitava , Chatterjee Avirup , Santhamoorthy Priveen Raj 
Published: November 2020

Abstract
This paper presents a case study on usefulness of having geomechanical understanding to avoid drilling risks and minimize costs in a Drilling campaign, Offshore Peninsular Malaysia.
Significant drilling issues related to wellbore stability were encountered in the four exploration wells drilled during previous campaigns. The development wells were planned to drill with high inclinations (up to 700), through weak coal layers and cross major fault. The drilling problems of the offset wells were critically analyzed to understand the mechanisms of failures. A geomechanical model was built using the offset well information. The well-calibrated stress model was then used for the wellbore stability modeling for the planned trajectories. The outcome of this study was used as key input for casing and mud design.
With the help of the reccomendations based on this study, six highly inclined development wells were drilled through low pressure and narrow mud window intervals without operational problems. Reducing non-productive time (NPT) for the entire drilling campaign was one of the key focus for delivering the wells safely within schedule and budget. This paper documents the entire workflow and methodologies used for this entire study.
First Offshore Hydraulic-Jet-Fracturing Multizone Completion Application Case Study: Challenges and Lessons Learned in the Bozhong Oil Field, Bohai Bay, China
Authors: Fu Jianmin , Ma Yingwen , Zhang Ming , Ma Changliang , Liu Zhengwei , Zhou Shubo , He Lei , Feng Liang 
Published: November 2020

Abstract
The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field.
Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual.
A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions.
This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.
Multi-modal Particle Size Distribution of Lost Circulation Material Blend for Controlling Fluid Losses from Multiple Fractures Around Inclined Wellbores
Authors: Nguyen Kien , Mehrabian Amin , Santra Ashok 
Published: November 2020

Abstract
Lost circulation material (LCM) is commonly used to stabilize formations and inhibit fluid losses from the wellbore during drilling. Mud loss records and wellbore downhole image logs often reveal existence of multiple natural and drilling-induced fractures in the wellbore vicinity. Appropriate particle size distribution (PSD) for the LCM blend should be designed so that lost circulation from all near-wellbore fractures is contained.
This paper presents a novel design scheme for multi-modal PSD of LCM blends applicable to the likely cases of lost circulation from multiple near-wellbore fractures. The design scheme takes advantage of an analytical solution which estimates the fracture widths of an arbitrary number of fractures around inclined wellbores when subjected to the three principal stresses of the subsurface. The LCM blend design involves dividing the blend into subcategories of various sub-blends sizes. Each sub-blend has distinct particle size distribution, when combined, satisfying the size distribution criteria on the quantile distribution basis. The fractures apertures widths, which are a crucial input for LCM blend selection, are determined from an analytical solution of the related wellbore geomechanics problem. The solution is derived from the dislocation-based formulation of fracture opening profile in an infinite poroelastic medium. The effects of overburden stress, anisotropic horizontal stresses, wellbore inclination and azimuth as well as the mechanical interaction between the cracks are incorporated in the analysis. Further, a systematic method to characterize mud cake parameter is employed. Mud cake efficiency is shown to cause considerable influence on fractures aperture width and consequent composition of the LCM blend.
A synthetic study case mimicking typical depleted sand drilling environments is used to determine the optimal LCM blend design. The poroelastic back-stress effect is considered in the test cases, suggesting substantial changes in fracture initiation pressure and fractures apertures compared to the corresponding elastic solution. Furthermore, the sensitivity of fractures widths to geomechanical parameters is analyzed. The results indicate an interesting interaction between fractures as they induce a compressive hoop stress on one another, limiting the width growth of other fractures. Consequently, the multi-fracture wellbore problem introduces a variation in fraction width, thus causes different LCM sub-blend recommendations tailored to individual fractures. A combination of these sub-blends, each of which only covering a narrow range of fracture width, suggest a novel treatment of fluid loss in multi-fractured wellbore by forming a super-blend which covers the whole range of width distributions.
Pressure Wave Downhole Communication Technique for Smart Zonal Water Injection
Authors: Wang Quanbin , Jia Deli , Hu Gaixing , Sun Fuchao , Zhang Jiqun 
Published: November 2020

Abstract
Zonal water injection technique has been proved an effective method for enhanced oil recovery of multi-layer heterogeneous oil reservoirs. Higher zonal injection qualified rate is an important index for improving the effect of waterflooding development, so frequent monitoring and adjusting flowrate of separated layer is necessary. However, when traditional zonal water injection techniques are used, periodic flowrate testing and adjusting are realized by an armored cable with steel wire, which lead to a large number of testing work. This paper proposes a smart zonal water injection system based on pressure wave downhole communication technique. In this system, an integrated water distributor and a wellhead control device with pressure sensor and flow regulated assembly is developed. Continuous pressure wave can be generated by controlling the opening of downhole water distributor and wellhead control valve, and the pressure changes in wellbore can be monitored by sensors. Based on the time shift keying coding and decoding techniques, control command and downhole monitoring data are loaded into the continuous pressure wave. The pressure wave communication between wellhead control valve and downhole water distributor can be realized with injection water as the medium. With the help of General Packet Radio Service (GPRS) and Internet technology, the smart system can also be used for remote monitoring of downhole parameters and remote regulating of zonal flowrate. The smart technique for zonal water injection wells has been implemented in 89 wells in China National Petroleum Corporation (CNPC) Changqing M1 Block. Testing and adjusting work by testing vehicle in traditional zonal water injection technology is eliminated. The results of 27 tracked wells show that the maximum effective distance of pressure wave communication is 2879 m, the minimum pressure change that can be identified is 0.5 MPa, and the time of uploading a flowrate data takes 70 min. The effect of waterflooding development is improved after applying the smart technique. Zonal injection qualified rate is improved from 63.6% to 90.3%. Reservoir water absorption thickness is increased from 18.5 m to 19.4 m. Reserves producing degree of waterflooding development is improved from 68.7% to 70.2%. Natural decline rate is reduced from 5.2% to 4.8%. This paper illustrates a technology of pressure wave downhole communication for smart zonal water injection and an integrated case study, which can obtain vast amounts of real-time pressure data, and help reservoir engineers adjust development plan of waterflooding reservoirs. In addition, it offers a methodology for downhole wireless control.