bluuebunny/crossref_metadata_2025_split huggingface dataset:
Practical Approach for Solid Production Prediction and Completion Strategy Decisions in Horizontal Wells – A Case study from Cretaceous Carbonate Reservoir – North Oman
Authors: AL-Aamri Mohammed , Mahajan Sandeep , Sujith Nair , Waleed Battashi , Marta Becerra Ruiz 
Published: January 2020

One of carbonate reservoir fields being produced by a large number of horizontal wells. The oil production wells are from long open hole section along the reservoir formation. The wells are completed by barefoot (open hole) completion with Electrical Submersible Pumps (ESP) located in wells build up section. The field has been experienced to significant ESP Failures, which has increased the operational expenditure (OPEX). Apart from scale build up, solid production from the open hole section is understood to be a crucial contributor to reduced pumps life.
Several new wells are planned in the upcoming years, so the study aimed to provide input for the well completion strategy design and operational parameters (drawdown, flow rate), which could minimize the solid production and lower the intervention expenditure (OPEX). A Geomechanical assessment was carried out to assess the solid production from the open hole section. Geomechanical analysis based on analytical (elastic) solutions and modeling using Sand production tools was carried out. The results were calibrated with available field data and records of ESP failure in order to establish a link with geomechanical control on solid production.
The analysis of rock mechanical properties show large variation of rock strength along the horizontal open hole section, which penetrated different rock types within the same formation. Drilling Rate of Penetration (ROP) data was reviewed which indicates variable rock strength along the horizontal well section based on variable ROP. Additionally, it was found that formation pore pressure was not constant along the wellbore and some portion of the reservoir was more depleted than the other.
The model results show the most wells for a sustained period of time were subjected to drawdown of about 20-40% higher than the critical drawdown limit (for solid production). Field data showed that wells with significant depletion at the heel of the well-reported higher frequency of failures, but the wells with uniform formation pressure along the well, demonstrate relatively better performance in terms of ESP failures. Based on the study results, recommendations were provided on drawdown management strategy, which will potentially benefit from increasing ESP run life and reducing the field OPEX.
A Robust Model to Predict the Inflow Performance Relationship IPR of Hydraulically-Fractured Horizontal Wells in Gas Reservoirs
Authors: Mohamed Abdelmjeed , Abdalla Mohamed 
Published: January 2020

The knowledge of well productivity is crucial in well performance evaluation, well design, and addressing and resolving production problems. The inflow performance relationship (IPR) curve is the plot of flowing bottom-hole pressures versus the oil/gas production rates at that pressure values. It is used as a tool to evaluate the productivity of the well, and it can be predicted using production tests or empirical correlations. Many models were previously developed for horizontal wells in gas reservoirs; however, very few models considered the presence of fractures. This study introduces a new robust model to predict the IPR curve for hydraulically fractured horizontal wells in gas reservoirs using a single-point flow test.A single-well reservoir model was built using CMG Builder to generate the production data, and many reservoir and fracture parameters were changed in the model to cover a wide range of data. Then, the effective parameters were determined by plotting the data in the dimensionless IPR form. Afterward, the data was divided into two portions; 70% for developing the model and 30% for validation. The model was developed using non-linear regression, then validated and compared with previous models using different statistical parameters such as average absolute percentage error, R-square, variance, and standard deviation.The findings of this study showed that the dimensionless IPR curve is only affected by the reservoir permeability anisotropy and has a weak function of other fracture parameters such as the number of fractures, fracture conductivity, fracture half-length, and fracture height. The developed model showed high accuracy in estimating gas production rates at different bottom-hole pressure values with an R-squared of 0.998 and an average absolute error of only 1.54%. With the new model, only one point of flow test is required to plot the IPR curve.
First GCC Utilization of Superior Primary Solids Control Equipment Reduces Surface Mud Losses and Minimizes Environmental Impact
Authors: Olivares Tulio , Pino Rafael 
Published: January 2020

Traditional primary solids control methods use high energy, high G-force shakers to "shake" the fluid off the drilled solids on multiple static screens, and drilling fluid losses are typical 1 barrel of fluid for every 1 barrel of rock drilled. The new approach described in this paper replaces shakers with a vacuum-based system, to optimize the separation of drilling fluid and cuttings as they return from the wellbore. During this trial, a high-flow vacuum and rotating filterbelt (screen) system was configured to safely recover more drilling fluid from the cuttings, with the intention of reduce drilling waste. The goal is to validate the performance and HSE benefits of using vacuum-based primary solids control technology versus traditional shale shakers. Success criteria for the trial on two land wells were compared to common shale shaker performance and included: reduce fluid on cuttings by 30% (no more than 0.7 barrels of mud per 1 barrel of rock drilled); reduce screen consumption; and reduce noise level below that of the existing shale shakers.
A third-party cuttings flowmeter was used to measure the rock recovered by the vacuum-based system. The following results were recorded during the trial on two wells: fluid-on-cuttings was only 29%, versus the 70% target for the trial; average filterbelt life exceeded the trial target by 54%; and sound pressure level was measured at 74 dBA, at least 3 dBA less than common shakers. Based on retort analyses, Oil On Cuttings averaged 8.39% wet weight. Total rock recovery for the vacuum-based system was 91% of the theoretical hole drilled. During the fluid/cutting separation process, the unit is operated as an enclosed system, eliminating operator exposure to harmful vapor and gases. Finally, it was noted that changing the filterbelt (screen) could be performed by one person in approximately 3 minutes. In conclusion, the trial demonstrated that 71% less drilling fluid was lost versus a typical shale shaker, at the same time reducing overall drilling waste volumes and providing a safer working environment for personnel.
Vacuum-based primary solids control systems represent a step change in performance over the decades-old shale shaker concept. The production of significantly dryer cuttings can eliminate the need for traditional de-sanders, de-silters, centrifuges and cuttings dryers. In addition, benefits related to transportation, storage, and processing of drilling waste, can be dramatically obtained.
Design Your Wells Faster, Safer: A Validated Approach on Automating and Customizing Workflows in the Drilling Design Phase
Authors: Alvarez Alfredo , Bouska Reisha , Mustafa Dauren , Webb Jerry , Chelmella Sunny 
Published: January 2020

Pre-job engineering tasks conducted during the drilling design phase have often been an overlooked aspect regarding time and cost savings. This is a critical phase that directly impacts efficiencies and effectiveness while drilling. This paper highlights the multiple benefits of an engineering solution that automates and triggers advanced engineering computations simultaneously. The objective is to realize time savings and accuracy gains necessary for quick evaluation and resolution of the decision-making processes, while eliminating unintentional oversight on engineering requirements.
The approach focuses on a fully customizable application that automates sequences of models/ actions; interpretation and validation of results, based on pre-determined criteria; and reporting functionality. This automated solution uses established workflows and conditions, and user defined calculations to conduct typical pre-drill engineering tasks.
To demonstrate the tool's capabilities, two wells were reviewed by multiple engineers of varying experience levels. Each performed the pre-drill engineering tasks assigned based on proposed requirements. The outcome reviews the time taken to deliver validated engineering solutions; accuracy of result validation and ability to track compliance to standards. Results from the evaluation of these three Key Performance Indicators (KPI's) are presented and thoroughly described.
The validation conducted revealed significant time efficiency gains when executing pre-engineering tasks and automatically validating each simulation (71% overall time-reduction). The accuracy of results was always guaranteed when using the automated method, with a 100% accuracy for both wells analyzed, compared to an average of 92% from the focus group. This improvement is key to ensure the delivery of flawless well designs, consistently and reliably. Additionally, the described potential for ensured compliance based on standardized rules specific to each organization, allows for repeatability and accountability, enhanced through the use of auditable trails.
Automation of processes, workflows and equipment is driving the innovative and creative direction for the industry, but it should also steer toward an increase in reliability, performance and minimization of risk in every step of the well delivery process. This fully customizable engineering tool proved to be a highly efficient approach that allows users to eliminate manual, time consuming tasks while removing the potential for accidental oversight in identifying future issues before drilling begins.
Novel Liquid Mitigation Solutions in Brown Field Gas Compression Projects
Authors: Davis Ian , Saif Omar 
Published: January 2020

This paper describes the development of onshore brown field gas compression projects, with production from many hundreds of wells in remote locations. Gas is produced from both sweet and sour reservoirs, with differing decline characteristics and fluid compositions. The paper describes the impact of flow assurance design on the field development plan. The potential for liquid management difficulties are discussed, and a novel liquid management mitigation solution is proposed.
The initial investigation used maps to identify the hydraulic optimum locations for gas compression plants (GCPs) in congested areas, followed by site visits. A number of GCPs were based on gas production rate, field location, gas plant capacity and compression power. Design was performed with remit to reuse as much of existing facilities as possible.
Uncertainties in multiphase pressure and hold-up predictions on aging pipes required a conservative approach to hydraulics. Sensitivity analyses were performed on critical parameters.
The pipeline network design was refined through a cycle of site visits to obtain pipeline corridors and GCPs land use permits. Diameters were optimized to lower liquid accumulation and mitigation implemented against uneven split of liquid flow through existing twin pipelines.
Some pipelines upstream of GCPs were discovered to experience high levels of liquid accumulation. This is in agreement with operating experience. "U-bend" topography allows severe liquid accumulation and potential blockage, requiring frequent scraping for liquid management. The proposed solution is comprised by Liquid Separation Stations (LSSs). The LSSs are designed to remove bulk liquids at low points, which are transported via separate liquid pipelines to the GCPs slug catchers (SCs), then onwards to the gas plant.
With remote location of LSSs, the design philosophy adopted for design was application of piping components according to ASME B31.8 code, instead of ASME vessel code (and the resultant required appurtenances). This allows very basic gas/liquid separation; and the ability to immediately drain liquids from the separator to maintain normal liquid levels. Consequently, with the ability to drain at rates within an adequate uncertainty factor, significant residence time in the LSS is not necessary, allowing the sizes to be kept within the confines of B31.8 code.
Uncertainties in system design inputs and multiphase flow prediction in brownfield developments are highlighted. The proposed novel use of piping code to develop remote field separation for liquid management is discussed. This mitigation offers benefits of reducing operational issues associated with frequent scraping and liquid blocked pipelines.
Chemical and Mechanical Water Shut-Off in Horizontal Passive ICD Wells; Experience and Lessons Learnt in Giant Darcy Reservoir
Authors: Abdel-Basset Mohamed , Zakaria Shams El-Dine , Al-Husaini Mohammed , Barki Jassim , Chong Mizan 
Published: January 2020

Water conformance is a common challenge in oilfield industry especially in water flood and active water drive reservoirs where water production has a significant impact on production economics, oil recovery and facilities constraints. Water shut-off (WSO) is an essential solution to delay or minimize water production however effectiveness depends on treatment efficiency. This abstract will demonstrate extensive mechanical and chemical WSO experience in horizontal drilled wells completed with passive Inflow Control Devices (ICD) completions, with case histories from North Kuwait giant water aquifer reservoir.
The main challenge during water conformance treatment is the proper diagnosis and the full understanding of the water flow profile; accurately identify the water source as well as reservoir understanding will help selecting the efficient WSO mechanism, which is crucial for a sound decision making considering the associated cost and the operational complications. Understanding reservoir geology, Integration of inflow profiling via Horizontal PLT and new technologies of water saturation logsare key to accurately identify the water source (heal, middle or toe side) and by turn WSO mechanism. This is done in integration of multidisciplinary domains of G&G, production and reservoir engineers and operation teams.
Mechanical WSO using inflatable packers' technologies were applied for isolating the toe side, while chemical WSO technologies used for heal side isolation in the open-hole passive ICD completions. Rig-less shifting of ICD sleeves used where active SSD-ICD's completion installed. The statistics of executed WSO results of many case histories have shown relatively good success ratio represented in reducing water cut from 80 – 90% down to 20 – 70%, increase oil production rate from 200 bopd up to 3000 bopd in some wells depending on water source. Furthermore, WSO enabled bringing some inactive high-water wells back to production. This helps extending well-life and by turn maximizes ultimate hydrocarbon recovery. Also, reducing the total water production to facility allowed increasing production of some other wells producing to same facilities. As key learnt lesson; managing the produced liquid rate and drawdown post WSO is essential to maximize the benefit of WSO and delay sharp increase of water cut.
WSO solutions are in constant improvement. Integrating reservoir characterization, fluid inflow profiling and proper selection of WSO technique is crucial for any successful WSO decision. WSO became a common practice to maximize the oil recovery factor from Lower Burgan reservoir of North Kuwait fields.
A Systematic Approach to Increase Banyu Urip Crude Oil
Authors: Utama Dheli Panji , Kaswan Sutrisno , Bahri Syamsul 
Published: January 2020

Banyu Urip Facility which started up in 2015 was designed to process 185,000 BPD crude oil. Previous studies indicated surface facilities were constrained compare to reservoir deliverability. Debottlenecking activities including wash water injection into the production separator increased production 8% higher of the design capacity. Recent plant capacity test confirmed additional cooling would be required to increase production 19% higher than design capacity. Additional cooling capacity was installed downstream of the Crude Oil Stripper which successfully increased production to the new higher crude production.
This paper will share the comprehensive assessment of increasing capacity of the Banyu Urip production facilities including the additional cooling capacity and other facilities aspect affected by increasing crude production. The additional crude cooling capacity was achieved by the installation of an air cooler; however, the concept selection process also evaluated other brownfield constraintssuch as equipment spacing, constructibility, demand on supporting utlities and safety systems.
Early screen was performed to identify the equipment area taking into account the impact to operability, maintenability, and process performance. Due to the brownfield nature of the project the ideal location for symetrical arrangement of the new equipment was not avaible, therefore a screening level hydraulic analysis was require to validate the location was suitable for the process contidtions (i.e. pressure drop, velocity, etc.). The final location proved to perform as designed by by delivering the required cooling to support the increase capacity higher by 19% of design capacity.
Reservoir Development and Exploration Potential of the Upper Cretaceous Hartha Interval in Partitioned Zone, Saudi Arabia and Kuwait
Authors: AlMutairi Mohammed , Toomey Niall , Ghose Sujoy , Ponthier Joe 
Published: January 2020

Although the Partitioned Zone (PZ) between Saudi Arabia and Kuwait has been a prolific producer for over sixty years, significant resource potential remains in underexplored stratigraphic intervals. The Upper Cretaceous Hartha Formation is one of these opportunities. The Hartha interval has been penetrated by numerous wells targeting the deeper section in PZ, and although hydrocarbon presence has been observed in the Hartha, the play has not been fully characterized prior to this study.
Stratigraphic studies using core and well data concluded that the Hartha was deposited on a broad, low-angle carbonate ramp setting that includes the outer ramp, middle ramp, ramp margin, and inner ramp environments. Gross Depositional Environment maps were constructed based on these interpretations and show an approximately N-S strike-oriented ramp, similar to the orientation of the present-day shoreline of the PZ. Reactivation of basement highs during the Late Cretaceous influenced Hartha deposition, with high-energy grainstones deposited over and around these structural highs having the best potential for reservoir development.
Seismic interpretation was performed on recently acquired PZ 3D data to map key surfaces in the Hartha to Ahmadi section. The Hartha interval thins over structural highs and is significantly eroded by the pre-Hartha and pre-Aruma unconformities. This paleo-high structural trend in western PZ is also where the ramp margin grainstone fairway had developed and has been interpreted to contain the best reservoirs. Prospective areas are primarily structural closures over these highs inside the ramp margin fairway with stratigraphic facies changes to non-reservoir facies defining the lateral extent of the trap.
Virtual Reality: New Concepts for Virtual Drilling Environment and Well Digital Twin
Authors: Ferrara Paolo , Ricci Maccarini Giorgio , Poloni Roberto , Campaci Renato , Favaretto Mauro , Grasso Tiberio 
Published: January 2020

This paper describes a Virtual Drilling Reality (VDE) System, based on Virtual Reality (VR) technologies, designed and developed by Eni in collaboration with Saipem. The virtual environment is currently featuring last generation deepwater drilling rigs that are entirely virtualized and allows an immersive experience for Rig Crew and Drilling Engineers training, and in general for anybody who is interested in drilling rigs, equipment and operations. The system includes:
a complete virtual tour of rig and equipment;
the replay of drilling and rig operations chosen from drilled wells database;
a virtual HSE induction at rig site
virtual replays of real HSE incidents and rig Safety Drills;
an interaction with Drilling Operations based on well drilling simulations;
the execution of customized "missions", in single- or multi-player mode
The new VDE can also be used as an overall well digital twin throughout the entire well lifecycle including well planning, operations follow-up and post-analysis.
Configured for easy customization, the system allows extensions of virtualized rig fleet, modification and addition of the "active objects" in the repository, the preparation of tasks to be completed under the supervision of the trainers, play-back of operations, simulation of new drilling procedures and finally extra HSE incidents or emergency situations.
State of the art VR devices and techniques, such as headsets, VR gloves and stereo goggles, are used for a highly immersive and interactive experience, while 2D PCs or 3D Screens facilities are also available. An initial version of the VDE has been used since 2018 in innovative training courses held in Eni's Corporate University.
More recently, a well drilling simulator has been included in the system, realizing a full "well digital twin".
Engineering experience was then gained both in well planning, operations follow-up and post analysis, applied to complex wells management.
Main results obtained include:
a safe familiarization with complex operations
the optimization of operations, through realistic simulations
an increased safety awareness
an operation follow-up diagnostics support
In summary, Eni's concept of the virtual drilling environment allows a fully virtualized system, with access to all rig workplaces, for a full immersion and interaction in a dynamic, physical and collaborative environment. The possibility to reproduce simultaneous activities and the enhanced interaction with all drilling operations and real life on board, provides a new and innovative well digital twin experience for improved training and engineering support throughout the entire well life-cycle.