bluuebunny/crossref_metadata_2025 huggingface dataset:
Slimming the Well While Keeping the Well Objective Intact for Cost and Well Delivery Optimization – A Unique Way of Drilling
Authors: Alotaibi Ali , Almulla Jassim
Published: January 2020

Deep gas wells exhibit characteristics such as high temperature and pressure that present challenges in terms of drilling and completions. To overcome these hindrances and deliver the wells in a timely manner, casing design has been optimized by utilizing the latest cutting-edge technology in the oil and gas industry.

The subject area has numerous multiple reservoir pressures, which can be troublesome when drilling in one hole section. In the past, these reservoirs had to be isolated from each other by introducing casing strings, or take the risk of drilling through transient zones. The formation characteristics are troublesome as well. Starting from shale swelling to fractures. These shales are very reactive and force controlled drilling parameters while closely watching the fluid properties just to mitigate the trouble zone. Too many casing strings means an expensive well and high target well days.

This is a complete review, which will discuss implementation of different technologies in a deep gas well. Advanced bridging agents drilling fluid enabled the well to avoid the operation risks of stuck pipe and optimize the rate of penetration through multiple reservoirs pressures. A 4 ½-in by 7-in completion system capable of 15K hydraulic fracturing was used. Innovative way of locating abnormal pressure formation, even though they are unpredictable.

The paper describes a robust solution to well slimming, utilizing the latest technologies, drilling methods and fluid types, while following the original well plan.
Elements Influencing the Estimated Permeability from Pressure Transient Analysis in Comparison to Measured Permeability from Cores
Authors: Qanadeely Hasan , Al-Mulhim Khalifa , Amin Rana
Published: January 2020

The purpose of this paper is to demonstrate and explain the factors that can produce notable differences between permeability measured in a laboratory from core analysis and permeability estimated from pressure transient analysis (PTA) of build-up and fall-off tests.

The paper presents several synthetic cases to show the variations in obtained permeability using each method, and the contributing factors affecting the outcomes. For calculating effective permeability from PTA, errors in input data such as static, dynamic or pressure/volume/temperature (PVT) fluid data can significantly increase discrepancies. Heterogeneity in reservoir permeability distribution such as vertical reservoir layering (variation in permeability vertically), large scale lateral variation or fractures will also add to the discrepancy between methods. Comparison between the permeability from both sources for the same subject wells will be used to illustrate these factors by interpretation of the data and characterization of reservoir.

The primary factor contributing to the differences in permeability is that the one measured from core analysis represents absolute permeability to air or nitrogen in the lab and corresponds to only a small sample (few inches) of the reservoir. However, the calculated permeability from a PTA represents the average effective permeability of the reservoir fluid type within the radius of investigation for that particular test. Hence, each method provides a permeability based on different fluids and volumes of investigation. A methodology that can be utilized to estimate the effective permeability for uncored wells, which usually make out most of the wells in any field, using average effective permeability from PTA will be discussed. Such a method is beneficial for simulation studies that require sufficient knowledge of permeability in each area under study. This method should help in extrapolating the permeability all over the field to get more reliable predictions.

Permeability plays a very important role in reservoir characterization as well as simulation. Knowing the permeability leads to the success in the placement of wells and therefore wells performance and ultimate hydrocarbon recovery. Thus, the most accurate determination of the permeability is of extreme importance because it affects the economy of the field development. The paper discusses the factors that can produce differences between measured permeability in a laboratory from core analysis and permeability estimated from PTA and the best practices for correcting and correlating between the permeability to achieve more reliable predictions for reservoir characterization and simulation studies which results in better field development.
Solids-Free Epoxy Sealant Materials' Injectivity through Channels for Remedial Job Operations
Authors: Alkhamis Mohammed , Abdulfarraj Murad , Imqam Abdulmohsin
Published: January 2020

Remedial cementing job is an important operation conducted in the petroleum industry to restore the primary cementing integrity of oil and gas wells. The remedial job is needed when the integrity of the primary cement is compromised and the wellbore is prone to fluids migration. This work studies the behavior of several sealants that can be used in a remedial job including solids-free material, semi-solids material, and Portland cement. The focus of this study is on testing the rheological behavior, the injectivity, the effect of the size of cement's voids on the injectivity of different sealants, and the strength of the sealants. Laboratory experiments were conducted to evaluate the performance of several sealants in different cement's voids sizes. The results of this work demonstrate that solids-free materials such as epoxy resin has the highest injectivity among the tested sealants even in very small gaps. The epoxy resin develops higher compressive strength than that of the conventional Portland cement. This work points out the importance of selecting the appropriate type of sealant on the effectiveness of the remedial job.
Journey Towards the Unconventional Digital Well Factory
Authors: Alqahtani Rawan , Reddy Karri , Albawardi Manal , Havard Maxime
Published: January 2020

Integrated Well Delivery (IWD) Program also known as Digital Well Factory Program is a large cross-functional transformation effort designed to help unconventional oil & gas operators successfully transition and ramp up from exploration phase to development phase. The purpose of the program is to establish a state-of-the-art integrated well delivery capability (referred to as "agile well factory") leveraging the best practices of the unconventional resources industry as well as the latest digital technologies & tools.

IWD program relies on five fundamental concepts that underpin the "digital well factory" vision: Transparency, Connectivity, Adaptability, Collaboration & Cross-Functional Integration. The program was designed to look at well factory performance from a 360-degree perspective and thus is structured around a comprehensive framework of 6 interdependent building blocks:

Well Delivery Performance Advanced Analytics

Well Delivery Zero-based Process Transformation

Well Delivery Integrated Planning & Scheduling Optimization

Well Delivery Process Agility & Automation

Well Delivery Mobility & Integrated Planning Center

Well Delivery Collaborative Operating Model

The end goal of the program is to evolve the operator’s organization into an agile, intelligent, automated & highly efficient well factory. On the one hand, the program aims at making the company capable of smoothly delivering hundreds of wells per year on schedule and in record time & cost. And on the other hand, it aims at making the operator capable of continuously adapting itself based on lessons learned, data driven-insights, operational challenges, strategic changes, etc.

This paper describes the end state vision of the program, its value, approach, framework, key initiatives, management, as well as recommendations for any operator willing to embark on a similar journey.
A Semi-autonomous Snake Robot to Increase Plant Availability, Lower Maintenance Costs and Improve Safety
Authors: Fairclough David
Published: January 2020

This paper reports on a project to develop a semi-autonomous snake robot, designed for entry into high pressure combustible gas systems. The project is funded by Innovate UK and is a collaboration between Process Vision and the University of Reading.

Recent advances in robotics are making many inspection and maintenance tasks possible. The objective of the project is to provide a proof of concept prototype that can increase plant availability, by reducing the need for inspection shutdowns. As well as improving safety by reducing confined space working and reduce shutdown durations, as online diagnostics will help shutdown planning and logistics.

If internal inspections could be performed without the need to shut down this would:

Reduce downtime and increase efficiency in production

Reduce OPEX

Provide a safety benefit by reducing confined space working

Provide an environmental benefit by reducing the gas sent to flare to de-pressurise

Reduce fixed costs

Allow fewer man hours in inspection tasks

Remove the need for purge gas – nitrogen or air

Reduce the number of procedures required

Reduce the amount of paperwork
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.
Research and Application of Fracture Failure Control Technology for 13Cr Tubing in High Temperature and High Pressure Gas Wells
Authors: Ma Lei , Liu Hongtao , Geng Hailong , Xie Junfeng , Zhao Mifeng , Xiong Maoxian
Published: January 2020

There have been many failures happening to S13Cr-110 oil tubing serving in high-temperature and high-pressure gas wells in Tarim Oilfield. A series of investigations were conducted for root-cause analysis, including the macroscopic and microscopic morphology observation of the fracture surface, the service condition evaluation, the quality check of the fractured tubing, and the state analysis of the tubing outer surface. It is concluded that the fracture of the tubing is mechanistically of stress corrosion cracking (SCC), and is closely related to the application of phosphate-based completion fluid. Further tests indicated that S13Cr tubing specimens failed in the form of SCC in the environment of phosphate completion fluid contaminated with mud and oxygen. And formate completion fluid is compatible with super 13Cr tubing. At present, 55 high temperature and high pressure gas wells in Tarim Oilfield have used formate completion fluid, so far there has been no tubing string fracture.
Solid Management Optimization for Offshore Big Bore HP/HT Sour Gas Well Cleanup
Authors: Nengkoda Ardian , Qahtani Abdallah , Logan Sami , Youssef Mostafa , Sinker Alastair
Published: January 2020

The design of solid management systems (SMS) facilities for offshore big bore HP/HT sour gas well cleanup is an industry challenge, mainly it is due to solid erosion (sand), potential high pressure H2S release, heat radiation from flare, SO2 exposure, vibration, noise, including risk of piping or facilities blockage, and corrosion (facility integrity) that might hinder safety, operability and environmental issues. The objective of this paper is to develop a solid handling management decision making process especially during early facilities development, identify the merit and limitation on each handling option. As methodology; firstly, technology screening and benchmarking will be performed. Then characterize solid composition, determine the expected solid/ mud flow back during well clean up, erosion and deposition study, hydraulic flow assurance and heat impact mapping. The next process is, develop a decision-making workflow based on solid handling option scenarios including offshore, onshore or a combination of them. Moreover, a hydrocyclone solid removal simulation is performed, and for the onshore application; flow loop experimental work is carried out on a small scale to prove the solid removal efficiency. Various flow rate, pressure and mud with different particle size and concentration from 7% to 15% with mixture of base fluid component are tested during the flow loop test. It is found that factors such as safety (operability), reservoir, well type, solid mud properties, the availability of infrastructure and footprint are playing important roles in the decision of well clean up strategy. Having offshore and onshore SMS will help solid management further robust. Based on the flow loop test study, solids management system with multi-stage separation process has a capability to remove more than 90% solids separation and in addition, differential pressure across stage need to be maintained.
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.
Case Study: Monobore Cemented Completion Without Shoe Track for Unconventional Gas Wells
Authors: Han Kyungnam , Alexeyenko Alexey , Fethiza Tedjani Hamza , Oparin Maksim
Published: January 2020

Every drilling and completion operation has a room for improvement while staying within project's and safety requirements constraints. This paper discusses successful optimization idea from risk assessment to implementation in number of gas unconventional wells: cementing monobore 4 ½" 15.1 ppf completion string in unconventional horizontal gas wells without shoe track. This idea can also be defined as "no shoe track" or "short shoe track". Standard cementing practice requires having a calculated length of pipe to work as a tolerance buffer to ensure "bumping" the wiper plug while avoiding "wet shoe" where end of pipe is not cemented due to possible cement over-displacement. Proven cementing practice works for conventional wells. In unconventional wells where completion is designed for hydraulic fracturing the standard cementing practice is up for review. Drilling, completion and production teams have completed joint risk assessment and found that negative implications of eliminating shoe track are minimal or non-existent while time and cost benefits are tangible. Horizontal unconventional gas wells with vertical depth around 14,000 ft. and measured depth around 18,000 ft. were selected for no-shoe-track monobore cemented completion. Case study of these operations is provided in the following paper.
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.
Evaluation of Alkaline Treated Fly Ash as a Demulsifier for Crude Oil Emulsions
Authors: Adewunmi Ahmad Akanbi , Kamal Muhammad Shahzad
Published: January 2020

The formation of crude oil emulsion is a serious challenge in the petroleum industry as it can corrode upstream equipment and also cause catalyst poisoning in the downstream. Thus, efficient and effective water removal from the emulsion becomes very necessary while substantial water removal can be achieved by using suitable demulsifiers. In this study, the alkaline treated fly ash (TFA) was tested as a potential demulsifier for crude oil emulsions encountered during hydrocarbons production. The water-in-oil emulsion was prepared and the demulsification activity of various TFA concentrations (1%, 3%, 5%, and 7%) was performed at a temperature of 75 °C. Likewise, the demulsification exercise of the blank sample (emulsion free of TFA) was conducted at the same temperature. Optical morphology and rheology tests were conducted before and after demulsification. Experimental results showed that the TFA can effectively break the naturally occurring emulsifiers in the emulsion and separate oil and water into phases. Each concentration of TFA applied was able to destabilize the emulsion and remove considerable amounts of water. However, the 7% TFA exhibited the highest water removal with a demulsification efficiency of 93%. Optical electron microscopic images exhibited the morphology of emulsion before and after the demulsification test. Results of the rheology demonstrated that the TFA reduced the viscosity of emulsion considerably indicating the collapse of emulsifying substance and coalescence of water droplets.
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.
Improvement of the Upstream Project Valuation in Consideration of Abandonment Expenditure ABEX Uncertainties
Authors: Bakar Azureen Alya Abu
Published: January 2020

This study intends to propose parameter adjustment for economic evaluation in considering abandonment expenditures (ABEX) during front end loading (FEL) of discovered petroleum resources. In maturing a petroleum field development, abandonment and decommissioning of wells and facilities requires consideration during FEL. FEL, long adopted by prominent E&P players worldwide is used to support capital investment decision-making where value i.e. expected monetary wealth is measured and evaluated by Discounted Cash Flow (DCF) analysis. However, the DCF approach is outdated and flawed where it does not capture fluctuation well. This study reviews ABEX of sub-commercial contingent resources or shelved projects and economic evaluation method used in the author's organization and their parameters, identifying relevant and applicable adjustments that could be made associated to ABEX. Combining the revised ABEX with a modified economic model, a proposed set of categorical adjustments to is produced. The results show that the ABEX of the previously sub-commercial projects yield a more competitive number with revised semi-detailed estimates and different escalation and inflation approaches. Additionally, a standardized assumption for abandonment year before cessation of production is recommended to provide a more realistic evaluation of when ABEX is actually required to incur. These, in turn, improves the Net Present Value (NPV) of the projects tested as well as their viability and rank towards being sanctioned for development.
Waterless Stimulation: CO2 Fracturing Technology In Unconventional Resources
Authors: Wang Chunpeng , Cui Weixiang , Zou Honglan , Wang Chao , Zhang Xiwen
Published: January 2020

Compared with hydraulic fracturing, CO2 waterless fracturing can an alternative technology for the unconventional resources, such as the tight oil resources and the tight gas resources. It is an environment-friendly fracturing technology. Liquid CO2 fluid can be more easily obtained, and it is safe and non-explosive. Under formation temperature, it has ultra-low interfacial tension in supercritical state, so it has strong penetration ability, which can penetrate into matrix of reservoir and communicate with reservoir deeply. At the same time, it can reduce the viscosity of crude oil. Therefore, it is a kind of ideal fracturing fluid. This technology is significant for clean and efficient development of low-permeability tight oil reservoirs, and worthy of broad application.

The technique is divided into three stages. The large-scale high-pressure injection of liquid CO2 after fracturing, fracturing, continue to inject CO2 throughput, through multiple rounds, cyclic injection, CO2 from the wellbore along the cracks gradually extended to the distal end, increase formation energy, the single well control range and improve the producing rate of the reserves, at the same time to dissolve crude oil extraction, oil viscosity decrease. The CO2 steam soak, enhanced oil recovery rate decreased gradually, while the enhanced oil recovery rate is lower than the economic limit, the implementation of CO2 refractured, further increase the transformation volume, continue to inject CO2 multi cycle throughput, the CO2 can be extended to the depths of the reservoir, and further improve the reserves rate and yield of single well. When the pressure of production wells spread to neighboring distal production wells, injection wells will be part of the production of CO2, forming a rectangle of five wells net, CO2 flooding, establish effective displacement pressure system, supplement the formation energy, to ensure long-term stable production of tight oil wells.

The integrated technology of CO2 waterless fracturing has been used in ten tight oil wells of the north Oilfield in China. During the fracturing. In this treatment 19.8 m3 of proppant and 653.5m3 of liquid CO2 is used. As a result, the production has increased by over 100%. With low viscosity and high diffusion coefficient, supercritical CO2 is good for improving fracturing volume.

In the tight oil reservoir, The realization of artificial energy development, reducing carbon emissions, to further enhance oil recovery, improve the reservoir producing ability. At the same time, to realize large-scale CO2 sequestration and reduce carbon emissions, both realistic and economic, but also great social benefits.
Cross-Cultural Communication: Perspectives from Translation Studies and Applied Linguistics
Authors: El-dali Hosni Mostafa
Published: January 2020

This paper has emerged out of the conviction that linguistic theory has more to offer totranslation theory than is so far recognized and vice versa. One reason for the relative separationbetween the two fields is, perhaps, the domination of formal approaches to language study for aconsiderable period of time. But, with the spread of functional linguistics in the last three decades,there have been growing hopes for establishing links between linguistics and translation studies.Accordingly, the discussion, in the present study, proceeds primarily from the perspectives of“Translation Studies” and “Applied Linguistics”. One major goal is to show the interrelationshipsbetween linguistics and translation, and how they benefit from each other. The basic underlyingtheme, here, is that “inside or between languages, human communication equals translation. Astudy of translation is a study of language” (Bassnett-McGuire, 1980: 23). In addition, bothtranslators and linguists deal with two linguistic systems, each with, perhaps, a different culturalsystem. So, if we agree that ‘all communicators are translators’ (Bell, 1994), we must rememberthat the role of the translator is different from that of the ‘normal communicator’: the translator is abilingual mediating agent between monolingual communication participants in two differentlanguage communities.

On the other hand, there has been a great focus on using English only as a medium ofinstruction in all courses taught in the UAE University. Accordingly, the second goal of this studyis to try to answer the questions, “How much translation from L1 is permitted in FL teaching? and“What are the factors that determine the quantity to be used?”. The view adopted in the presentstudy is that disregarding L2 learners’ mother-tongue and considering it “a bogey to be shunned atall
A cry still unheard: A menace of female foeticide societal attitude towards female foeticide
Authors: Arora Mona
Published: January 2020

India has an age old fascination with the boy child and considers the birthof a girl as a bad investment in future. A girl is considered to be consumer ratherthan a producer, and this narrow viewpoint of the Indian patriarchal society haslead to horrid practices like female infanticide and female foeticide.

There is societal pressure for women to have male children and failurestend to feel guilty after giving birth to a girl. Such women are at risk of beingbeaten and rejected by their husbands. This can even lead to rejection by in -lawsand by the society as a whole. Keeping in view the above discourse the presentpaper aims to study the attitude of society towards female foeticide.
A Development of Healthy Promotion Model by E-SAN Folk Healer's Wisdom
Authors: Phon-ngam Patthira
Published: January 2020

The purposes of research were 1) to study the knowledge used by local folk healers, thecondition of healing and services, the acceptance of the methods used by the folk healers in LoeiProvince, and 2) to develop the model for the promotion of the community health with the herbalwisdom of I-san folk healer participated by the related stakeholders.Mixed methods of quantitative and qualitative research were applied, the quantitativeresearch was used in the survey, and the quantitative research was used in an in-depth interview,the participatory observation, and focus group discussion. The target groups in this study consistedof the registered folk healers from 14 districts of Loei who still perform the healing, the localpeople who get the services or used to get the services from the folk healers, the senior people inthe areas, and Thai traditional medicine scholars. The findings were as follows.1. All folk healers treat the illness according to the systems of human body. The healingcondition in which the folk healers used was related to the belief of local culture that the folkhealers believe, including (1)the belief in the causes of illness, (2) 4 elements and 5 aggregates oflife, (3) astrological belief on fate, (4) astrological belief on the causes of illness, (5) the belief onthe 4 elements of life, (6) the belief in the rite of Thai traditional medicine, (7) the belief and therite on the herbs, and (8) the belief on the village herbs and the elimination of illness.The acceptance on the healing methods of the folk healers in Loei indicated that thepatients and the relatives are satisfied with the results of healing, because the symptoms of illnesswere disappeared. Some people were back to normal, however, everyone can go back to live lifeand to work normally as before.2. The results from the development of the healthy promotion model in communitywith the knowledge on herbs of the folk healers using participatory action of related thestakeholders in the community were in 3 models; Model 1: The community health promotionalactivities consisted of (1) the activities related to public health to promote the local students’learning, (2) herbs garden project in schools, (3) the first aids cure with the herbs in schools insteadof using medicine, Model 2: the creation of learning materials of the local wisdom of the folkhealers by making books and CDs titled Herbs in Loei and I-san Herbs Recipe, and Model 3: TheDissemination of folk healing knowledge to peopleThe evaluation of the three models was done by the observation of the activityparticipation, interview on the satisfaction, and the usefulness of the participation in