bluuebunny/crossref_metadata_2025 huggingface dataset:
Large Scale Reservoir Simulation Models for Regional Understanding of Inter-Field Communications - A Case Study Offshore Abu Dhabi
Authors: Parra Humberto , Mogensen Kristian , Alobeidli Abdulla
Published: December 2021

Reservoir simulation models aim to reproduce at well, sector and field level the pressure and production behavior observed in the historical data. The size and resolution of the models are essentially capped by the computational resources as the numerical computations are quite complex and hardware demanding. For this reason, the use of simulation models to understand inter-field communications at regional level have been always a challenge, rarely pursued, referring those analyses to simple material balance to evaluate influxes, lacking lateral vectors to identify where volumes are coming from, especially on cases of multiple field interactions. The work presented in this paper illustrates the value of merging existing field level simulations models into a large scale regional simulation grids, in order to understand pressure disturbances observed in multiple fields Offshore Abu Dhabi.

The process of merging simulation models represents a big challenge considering the high variety of approaches used in the original models, different geology complexity, fluid characteristics, different depletion regimes and field development strategies. In this study, thousands of wells, 6 structures with different fluid and equilibrium regions were used to build the biggest reservoir simulation model in Abu Dhabi. The integration of the data pursues the replication of the existing static and dynamic models, addressing in parallel lateral and vertical upscaling issues when moving from very fine into coarser grids. Implications on the change of scale on the repeatability of the HCIIP volumes and the impact of pseudo relative permeability curves on the history match were carefully analyzed during the process. Evaluation of the impact of the simplifications over the overall quality of the model was of paramount importance, interrogating whether the simplifications affects the capability of the model for assessing the pressure communication and influxes among the fields.

The regional simulation model allowed to understand the effects of the peripheral water injection of a giant field on the nearby satellite fields, also the effects of these interactions on the pressure and oil saturation changes through time. Fields and Structures separated way far (20 and 40 Km away) can eventually see pressure disturbances after very long periods of time (up to 300 psi in couple of decades in some cases). Although evidences for changes in pressure are very clear and supported by RFT/MDT time lapsed data, the work also proved that changes on saturations are not very evident or can be considered very marginal on fields separated by large distances.

This work represents an alternative and more accurate approach for evaluating nearby field communications and to quantify the boundary conditions to restore models at original stage before nearby interferences, allowing proper initialization of the fine scaled simulation models on pre-production status.
Overcoming Production Logging Challenges in Evaluating Extended Reach Horizontal Wells with Advanced Completions
Authors: Younis Akram , Alshehhi Mohammed , Al Braik Haitham , Uematsu Hiroshi , El-Sayed Mohamed , Manzar Muhammad Abrar , Ismail Mostafa , More Manjiri
Published: December 2021

Objective/ Scope

Production logging analysis is essential to understand and evaluate reservoir performance throughout the lifetime of an oil well. Data acquisition and analysis is known to be challenging in modern extended reach horizontal wells due to multiple factors such as conveyance difficulties, fluid segregation, debris, or open hole washouts. Advanced compact multiple array production logging tool (APLT) is proposed to minimize the uncertainties related to these challenges.

Method, Procedure, and Process

The proposed sensor deployment method provides a comprehensive borehole coverage, thus maximizing the amount of subsurface information collected to evaluate the production performance of a horizontal well. Essential measurements are combined on six individual arms. Each arm is independently deployed which guarantees the best borehole coverage in a variety of borehole condition. Robust mechanical arm design minimizes damage, allows tolerance to decentralization, and provides greater confidence in determining the sensor locations. Each arm utilizes two fluid holdup sensors (Resistance, Optical) and one velocity sensor (Micro-Spinner). Co-location of the sensors minimizes the uncertainty related to sensor spacing when compared with previous generation of APLT.

Results, Observations, Conclusions

The new sensor deployment method and analysis results are discussed showing the added value in barefoot completion as well as advanced ICD completion. The holdup sensors response from previous generation APLT is compared to the advanced tool and how it relates to better borehole coverage. The results also illustrate use of high frequency optical probes for phase holdup determination. In addition, the optical probes are used to confirm bubble point pressure at in situ conditions by confidently detecting the first gas indication in the tubular. The results clearly show how a compact APLT maximizes the borehole coverage in highly deviated and horizontal wells. This is critical in collecting representative data of all segregated fluids which enables more accurate interpretation of the flow profile in the well and better understanding of reservoir performance.

Novel / Additive Information

The novelty of the new instrument is the ability to maximize the amount of subsurface production logging information collected with low uncertainty and minimum operational risk.
Examining the Significance of Internal Mobility Hiring in Determining the Individual Vs Organizational Outcomes: An Empirical Investigation from ADNOC FURSA Platform During Recent Pandemic of COVID-19
Authors: Abudaqa Anas , Al Nuaimi Seena , Buhazzaa Hayfa , Al Hosani Sumaya
Published: December 2021

Objective Scope: ADNOC group of companies introduced the Fursa platform which is an internal online website where HR acquisition partners among the 13 companies can post vacancies and employees from any of the 13 companies can apply to those vacancies. The aim of this initiative is to move ADNOC's employees internally to reskill, fill department gaps, and cross-collaborate to get a project done or hit an organizational goal with minimizing hiring cost and accelerate recruitment process. This study considers the above stated program as an explanatory factor to determine the individual's as well as organizational outcomes in ADNOC group of companies.

Methods, Procedure, Process: To address the study objectives, qualitative and quantitative methods are adopted. More specifically, for quantitative approach, structural questionnaire was developed through adopting different items from the literature. Whereas qualitative analysis are conducted while using the information from structured interviews.

Results, Observations, Conclusions: The study findings indicates that both individual and organizational outcomes are positively and significantly determined by internal mobility program. Similarly, analyses through qualitative approach confirms that internal mobility program helps to provide learning and development of the employees, productivity and performance in terms of individual outcomes, and sales and growth to reflect the concept of organizational outcomes. It is stated current program Enabled employees to find their next position, project, or mentor internally, and maximized ADNOC workforce potential and unlock the capacity to meet the corporate objectives. Other interesting outcomes are It takes less time and money to source (and saves money on relocation costs and as known during pandemic situation there is a restriction on international movement between countries); it enables faster onboarding and ramping up. Additionally, during internal mobility the company is confident that the candidate shares your mission and vision, and It also implies that you are aware of a candidate's most recent performance.

Novel/Additive information: the study is unique in the sense that it is done in one of the giant oil and gas companies which employees working in different aspects of the business; upstream, downstream, and mid-stream. The study introduces modern ways of work in a speedy, natural manner, and the use of MS Teams to do virtual interviews. Fursa platform allows companies to act quickly. It only takes a few seconds to determine where talent should be directed, and a few more seconds to deploy it.
Standardization of Lightweight Structure Via Design One Build Many Solution
Authors: Saadon Syakira , Azmi Norhazrin , Murukesavan Prabagar , Nordin Norsham , Saad Salman
Published: December 2021

Petroliam Nasional Berhad (PETRONAS) is embarking on the implementation of the Design One Build Many (D1BM) concept, an integrated approach on design standardization, replication and volume consolidation for light weight fit for purpose wellhead platforms - also known as Lightweight Structure (LWS). The objective of the standardization is to enable monetization of marginal and small fields by improving project economics that are challenged with the high development costs and conventional execution schedules. Traditionally, projects are developed through a "bespoke" design which requires a specific engineering study during the Front End Loading (FEL) phase to cater for the field specific requirements. In addition, once the project has been sanctioned, it is a must to undergo tendering and bidding activities which can increase field monetization duration by four to five months. The current "bespoke" design has resulted in non-standardization, loss of opportunity for volume consolidation and ultimately longer time for field monetization. Although the Design One Build Many principles were known for a long time, but they were rather project oriented. Thus this emerging solution is a result of synthesizing multiple challenges with the goal to establish an end-to-end systematic approach in monetizing marginal and small fields by lowering development cost and monetization duration. There will be standardized sets of Base Design and a flexible Catalogue items to cater for standardized add on items. Lessons learned incorporation upon the repeated design and standardized execution strategy including Engineering, Procurement, Construction, Installation and Commissioning could also help in improving the delivery efficiency for the lightweight structure. The greater collaboration across fields and blocks will give significant added advantage through economies of scale efficiency and eventually increase in the overall project value.
Modified Regeneration Scheme for Energy Efficient Gas Dehydration
Authors: Ali Haseeb , Sajjad Saqib
Published: December 2021

Molecular Sieve Dehydration units are used for dehydration of natural gas prior to gas processing or transportation. A molecular sieve dehydration system consists of multiple adsorbers which remove water during adsorption cycle until they get saturated with water. Regeneration of a saturated adsorber is performed by passing a hot regeneration gas stream through the adsorber. The hot regeneration gas after passing though the adsorber is then cooled before sending to regeneration gas compression. If an aircooled exchanger is used to cool the hot regeneration gas, heat available in the hot spent regeneration gas ends up in the atmosphere. In this context, an in-house study was performed to examine techno-economic viability of waste heat recovery from the hot spent regeneration gas using a modified regeneration scheme at one of the gas processing sites.

The modified scheme involves installation of a new waste heat recovery (WHR) exchanger to exchange the heat available in the hot regeneration gas with regeneration heater's inlet regeneration gas thereby reducing the fuel gas consumption in the regeneration heater as well as power consumption in regeneration gas cooler fans. The study comprised design and operation data collection and analysis followed by assessment of key challenges. The key challenges include performance of the heater in WHR case (i.e. lower fuel gas consumption), space availability for the new WHR exchanger and modifications in the existing system. A thermodynamic model was developed for running various operating scenarios and estimating the WHR potential, including heater's specific fuel gas consumption analysis at varying temperatures, to establish realistic fuel gas savings.

Overall, the study has indicated significant energy savings with good financial indicators for the proposed regeneration scheme. It has also showed reduction of peak heat duty of heater & cooler, thus providing an additional advantage of reduced CAPEX for future projects.
Flow Assurance and Thermodynamic Challenges of operating CO2 Pipelines for variations in terrains and environments
Authors: George Wood Terence , Campbell Scott , Smith Nathan
Published: December 2021

The requirement for capturing and storing Carbon Dioxide will continue to grow in the next decade and a fundamental part of this is being able to transport the fluid over large geographical distances in numerous terrains and environments. The evolving nature of the fluid supply and the storage characteristics ensure the operation of the pipeline remains a challenge throughout its operational life.

This paper will examine the impact of changes in the fluid composition, storage locations, ambient conditions and the various operating modes the pipeline will see throughout the lifecycle, highlight the technical design and operational challenges and finally give guidance on future developments.

The thermodynamic behaviour of CO2 with and without impurities will be demonstrated utilising the fluid characterisation software, MultiflashTM. The fluid behaviour and hydraulic performance will be calculated over the expected operational envelope of the pipeline throughout field life, highlighting the benefits and constraints of using the single component module in OLGATM whilst comparing against a compositional approach when dealing with impurities.

The paper will demonstrate through two case studies of varying nature including geographical environment, storage location (aquifer vs. abandoned hydrocarbon reservoir) and ambient conditions, the following issues:

The impact of the storage type on the pipeline operations and how this will evolve with time; The environmental conditions and the impact these have on selection of process equipment and operational procedures (i.e. shutdown); and The impact the CO2 composition has on the design of the CO2 pipeline, and

The paper will conclude with a set of guidelines for undertaking design analysis of CO2 pipelines for variations in fluid composition, storage locations and ambient conditions as well as some key operational strategies.

This paper utilises the current state of the art tools and how these evolving tools are making this technically challenging area more mainstream.
Recent Advances in Capillary Desaturation Curves for Sandstone and Carbonate Reservoirs
Authors: Siyal Amaar , Rahimov Khurshed , AlAmeri Waleed , Al-Shalabi Emad W.
Published: December 2021

Different enhanced oil recovery (EOR) methods are usually applied to target remaining oil saturation in a reservoir after both conventional primary and secondary recovery stages. The remaining oil in the reservoir is classified into capillary trapped residual oil and unswept /bypassed oil. Mobilizing the residual oil in the reservoir is usually achieved through either decreasing the capillary forces and/or increasing the viscous or gravitational forces. The recovery of the microscopically trapped residual oil is mainly studied using capillary desaturation curve (CDC). Hence, a fundamental understanding of the CDC is needed for optimizing the design and application of different EOR methods in both sandstone and carbonate reservoirs. For sandstone reservoirs, especially water-water rocks, determining the residual oil saturation and generating CDC has been widely studied and documented in literature. On the other hand, very few studies have been conducted on carbonate rocks and less data is available. Therefore, this paper provides a comprehensive review of several important research studies published on CDC over the past few decades for both sandstone and carbonate reservoirs. We critically analyzed and discussed theses CDC studies based on capillary number, Bond number, and trapping number ranges. The effect of different factors on CDC were further investigated including interfacial tension, heterogeneity, permeability, and wettability.

This comparative review shows that capillary desaturation curves in carbonates are shallower as opposed to these in sandstones. This is due to different factors such as the presence of high fracture density, presence of micropores, large pore size distribution, mixed-to-oil wetting nature, high permeability, and heterogeneity. In general, the critical capillary number reported in literature for sandstone rocks is in the range of 10−5 to 10−2. However, for carbonate rocks, that number ranges between 10−8 and 10−5. In addition, the wettability has been shown to have a major effect on the shape of CDC in both sandstone and carbonate rocks; different CDCs have been reported for water-wet, mixed-wet, and oil-wet rocks. The CDC shape is broader and the capillary number values are higher in oil-wet rocks compared to mixed-wet and water-wet rocks. This study provides a comprehensive and comparative analysis of CDC in both sandstone and carbonate rocks, which serves as a guide in understanding different CDCs and hence, better screening of different EOR methods for different types of reservoirs.
An Optimal Design Algorithm for Proppant Placement in Slickwater Fracturing
Authors: Wang HaiYang , Zhou Desheng , Xu Jinze , Liu Shun , Liu Erhu , Gao Qian , Liu Xiong , Guo Minhao , Wang Panfeng
Published: December 2021

Slickwater fracturing technology is one of the significant stimulation measures for the development of unconventional reservoirs. An effective proppant placement in hydraulic fractures is the key to increase the oil production of unconventional reservoirs. However, previous studies on optimizing proppant placement are mainly focused on CFD numerical simulation and related laboratory experiments, and an optimization design method that comprehensively consider multiple influencing factors has not been established. The objective of this study is to establish an optimal design algorithm for proppant placement based on the construction characteristics of slickwater fracturing combined with Back Propagation (BP) neural network.

In this paper, a proppant placement simulation experimental device was built to analyze proppant placement form data. We established a BP neural network model that considers multiple influencing factors and used the proppant placement form data to train and calibrate the model, which the proppant placement form prediction model is finally obtained. Using the proppant placement form prediction model, we designed an algorithm that can quickly select the three groups of construction schemes with the best proppant-filling ratio based on the massive construction schemes. The results indicate that the prediction results of the algorithm for proppant placement form are consistent with the CFD simulation results and experimental results, and the numerical error of the balanced height and the distance between the front edge of the proppant sandbank and the fracture entrance is within 5%. After using this algorithm to optimize the design of the fracturing construction scheme for the C8 oil well in Changqing Oilfield, the stimulation performance of the C8 oil well after fracturing is 2.7 times that of the adjacent well.

The optimal design algorithm for proppant placement established in this paper is an effective, accurate, and intelligent optimization algorithm. This algorithm will provide a novel method for hydraulic fracturing construction design in oilfields.
A Change Point Detection Approach for Intelligent Real-Time Identification of Lost Circulation Events During Drilling Operations
Authors: Cannarile Francesco , Montoli Stefano , Giliberto Giuseppe , Suardi Mauro , Di Bari Benedetta , Formato Gaetano , Farina Daniele , Magni Gianluca , Mutidieri Luigi , Prospero Alberto , Fidanzi Alessandra , Dal Forno Luca , Ricci Maccarini Giorgio
Published: December 2021

Lost circulation is a challenging aspect during drilling operations as uncontrolled flow of wellbore fluids into formation can expose rig personnel and environment to risks. Further, the time required to regain the circulation of drilling fluid typically results in unplanned Non-Productive Time (NPT) causing undesired amplified drilling cost. Thus, it is of primary importance to support drilling supervisors with accurate and effective detection tools for safe and economic drilling operations.

In this framework, a novel lost circulation intelligent detection system is proposed which relies on the simultaneous identification of decreasing trends in the paddle mud flow-out and standpipe pressure signals, at constant mud flow-in rate. First, mud flow-out and standpipe pressure signals underlie cubic-spline-based smoothing step to remove background noise caused by the measurement instrument and the intrinsic variability of the drilling environment. To identify structural changes in the considered signals, a nonparametric kernel-based change point detection algorithm is employed. Finally, an alarm is raised if flow-out and standpipe pressure decreasing trends have been detected and their negative variations are below prefixed threshold values.

The proposed intelligent lost circulation detection system has been verified with respect to historical field data recorded from several Eni wells located in different countries. Results show that the proposed system satisfactorily and reliably detects both partial and total lost circulation events. Further, its integration with already existing Eni NPT prediction models has led to a significant improvement in terms of events correctly triggered.
Implementation of HPHT RSS for Performance Improvement in Deep Shale Gas Drilling
Authors: Yan Juntao , Fu Yongqiang , Guo Chengfeng , Greenwood Jeremy A , Wang Lingjun , Xianyu Hansou , Hariri Nour
Published: December 2021

Sichuan shale gas development will move to reservoirs deeper than 3,500m TVD in the future after a production milestone breakthrough of 10 billion m3 per year from Southern Sichuan basin was achieved. 80% of Sichuan shale gas total resources will come from deep reserves compared to reservoirs at a shallower depth. Improvements in drilling efficiency are the key success factor of deep shale gas development to enhance production and cost control with the increasing activity.

Due to complex engineering and geological conditions, drilling deep shale gas horizontal wells in the Southern Sichuan basin is more challenging than traditional shallower wells. The High Pressure and High Temperature (HPHT) harsh drilling environment has caused the frequent failure of the standard Rotary Steerable System (RSS), Measurement While Drilling (MWD), and Logging While Drilling (LWD) tools during recent drilling operations.

The surface cooling system, combined with thermal mitigation practices, positively impacted the increasing trend of bottom hole circulating temperature (BHCT) and extended equipment life in short horizontal sections. However, thermal mitigation reduced in effectiveness with the increase in the length of the horizontal section as frictional heating increased. BHCT reached above 150degC while drilling and exceeded the operating limits of standard tools. The challenge of managing the circulating temperatures resulted in approximately 50% of the total runs in 2020 being tripped before the run objectives were met, creating non-production time (NPT) and significantly decreasing drilling efficiency.

To overcome this challenge and reduce NPT, two options were evaluated. A high-temperature Motor bottom hole assembly (BHA) brought risks of poor well trajectory control, resulting in well placement issues during geosteering, and lower potential reservoir exposure. For the first time in China Shale gas, an HPHT RSS with near-bit gamma-ray imaging was selected to maximize drilling efficiency and reservoir exposure. In addition to the tool selection, an HT optimization process was created that included horizontal well BHCT modeling and prediction and deep shale gas RSS drilling best practices. The near-bit gamma imaging quality was enhanced to improve steering. These changes delivered record runs in deep shale gas long horizontal wells and significantly decreased NPT. Reducing the reliance on surface cooling systems also increased overall operating efficiency.

This paper reviews the choice of equipment, implementation of HPHT RSS, and development of HT optimization process that improved the drilling efficiency, reduced well time and enhanced long horizontal well placement in this complex drilling environment.
A Highly Successful Way to Consistently Drill to Target Depth with Nano Polymer Water-Based Mud in a Highly Active, Problematic Shale Interval
Authors: Olivares Tulio Daniel , Pino Rafael M , Al-Zahrani Walid , Aly Samy Mahmoud , El Nahas Mohamed
Published: December 2021

The operational drilling history in a particularly challenging shale consistently shows that once the formation's shale reacts, and starts to disperse, in the face of a typical water base mud application, a variety of hole problems are experienced by the operator. These problems include wellbore instability caused by an unstoppable sloughing of the shale; the experiencing of tight hole conditions while performing the wiper trip; caved shale sticking to shakers while drilling; an increased dilution rate due to mud weight; a low LGS % (low gravity solids), and fluid viscosity.

To solve this longstanding drilling challenge, a team formed from operator and service provider experts determined via high-level research and testing the need for an innovative new technology of inhibitive fluid chemistry. After extensive testing, the team determined that a particular environmentally friendly Nano Polymer high-performance water-based mud (HPWBM)—one possessing the unique shale inhibition and cutting encapsulation capabilities capable of stabilizing this sticky shale—was the best fit for this application.

We will present the investigational learning and effective field trial drilling of high problematic shale that was evaluated during and subsequently the utilization of nanoparticles (NP) to advance water-based mud (WBM) inhibition properties, proven to offer an eco-friendly Nano Polymer HPWBM substitute with the improved thermal and rheological permanency of the overall WBM formulation. Results will display that while providing more effective drilling and wellbore stability, this technology is also a far cleaner industry alternative.
De-Risking Fluid Compartmentalization of the Barik Reservoir in the Khazzan Field, Oman - An Integrated Approach
Authors: Al Anboori Abdullah , Dee Stephen , Al Rashdi Khalil , Volk Herbert
Published: December 2021

The degree of fluid compartmentalization has direct implications on the development costs of oil and gas reservoirs, since it may negatively impact gas water contacts (GWC) and fluid condensate gas ratios (CGR). In this case study on the Barik Formation in the giant Khazzan gas field in Block 61 in Oman we demonstrate how integrating independent approaches for assessing potential reservoir compartmentalization can be used to assess compartmentalization risk. The three disciplines that were integrated are structural geology (fault seal analysis, movement and stress stages of faults and fractures, traps geometry over geological time), petroleum systems (fluid chemistry and pressure, charge history) and sedimentology-stratigraphy including diagenesis (sedimentological and diagenetic controls on vertical and lateral facies and reservoir quality variation). Dynamic data from production tests were also analyzed and integrated with the observations above.

Based on this work, Combined Common Risk Segment (CCRS) maps with a most likely and alternative scenarios for reservoir compartmentalization were constructed. While pressure data carry significant uncertainty due to the tight nature of the deeply buried rocks, it is clear pressures in gas-bearing sections fall onto a single pressure gradient across Block 61, while water pressures indicate variable GWCs. Overall, the GWCs appear to shallow across the field towards the NW, while water pressure appears to increase in that direction. The "apparent" gas communication with separate aquifers is difficult to explain conventionally. A range of scenarios for fluid distribution and reservoir connectivity are discussed.

Fault seal compartmentalization and different trap spill points were found to be the most likely mechanism explaining fluid distribution and likely reservoir compartmentalization. Perched water may be another factor explaining variable GWCs. Hydrodynamic tilting due to the flow of formation water was deemed an unlikely scenario, and the risk of reservoir compartmentalization due to sedimentological and diagenetic flow barriers was deemed to be low.
Swinging Water Injection Targets SWIT
Authors: Al Musalhi Abdullah , Al Mawali Salim , Al Ruqaishi Ali
Published: December 2021

With increasing wells connected to central facilities, it is hard to manage water flood using traditional technique. Therefore, a novel control concept named Swinging Water Injection Targets (SWIT) was developed in PDO to manage the challenges and satisfies both surface/subsurface requirements. The objectives of SWIT are:

Maximize water injection well compliance. Minimize oil deferment due to water disposal restriction. Automated system that manages the variations in produced water flow with minimum interventions.

SWIT concept is using the tolerance of ± 20% of desired injection target (Compliance limit) for each water injection (WI) well. So rather than having a fixed target, a minimum and maximum injection flow are giving to each WI well flow controller. Those range are provided by subsurface to ensure minimal impact for the rate fluctuation. The injection flows are driven by WI header pressure controller. When the produced water, the WI header pressure increases then the pressure controller to control the pressure asks all WI wells simultaneously increasing their injection flow at the same relative portion (Optimized distribution). Also, when the produced water decreases all WI flow starts reducing in the same way.

SWIT concept proved success in PDO and it became a standard. It was first introduced in small field. Later, it was replicated across the company fields. The biggest scale implementation was in a cluster with more than 500 WI wells. Previously, in that cluster the WI header pressure was fluctuating indicating issues with water balance. Many manual adjustments were required to manage the situations when the produced water is more than the injection demand by closing oil producers leading to a considerable deferment due to water disposal restriction. Also, when the supply water is less than injection demand many WI wells start under injecting leading to low injection compliance. After SWIT was introduced in the cluster and all injectors started swinging in harmony via automatic control, it managed to balance the water system (controlled WI header pressure) regardless of the variation in produced water production.

This resulted in increase of WI compliance by 5% after implementation. As SWIT optimized the water distribution to the injectors, roughly around 50 m3/d of additional oil production was achieved. It also minimized deferment from disposal restriction to a minimum level. All of this without the hustle of manual interventions.
Design Improvement of a Generic Catofin Reactor Air Outlet Header to Reduce the Erosion Using Computational Fluid Dynamic CFD
Authors: Parihar Ajay Singh , Lott Philippe Thomas
Published: December 2021

Objectives/Scope

The objective of the current work is to study the erosion inside the air outlet header of a generic catofin reactors which are used to produce the propylene. During the regular maintenance cycle of these plants, it was found that at several places in the air outlet header region erosion and material removal were reported.

Methods, Procedures, Process

Erosion wear is the loss of material due to repeated impact of solid particles on a surface and causes major economic losses across diverse industries such as oil and gas, hydraulic transportation, and chemical processes. Erosion severely damages flow passages, valves and pipe fittings, leading to higher replacement costs as well as the loss of valuable production time. For example, some oil and gas fittings can fail after just 30 minutes of operation due to high erosion rates. Engineers need to quickly evaluate the erosion on dozens of design variations to find ways of stretching the part's lifespan in order to reduce costs and maximize process up-time. Erosion is a complex phenomenon that depends on many parameters. Particle parameters can include the following: Particle shape or angularity, particle size and erodent particle hardness. Flow parameters, on the other hand, have a stronger effect on erosion as it determines particle concentration, particle impact angle, and impact velocity. Other parameters affecting erosion are properties of target surface, i.e. surface hardness and multiphase effects Progress in understanding the erosion due to solid particles has been achieved by the use of computational fluid dynamics (CFD). CFD allows the accurate modelling of fluid flow and particle trajectory through pipelines and bends. Once the impact velocity and angle of the particles colliding against the surface are calculated, empirical correlations to quantify the erosion rate can be implemented. Computational Fluid Dynamics (CFD) methodology was used to understand the cause of material removal and further perform design iterations to come up with new design to reduce the erosion drastically.

Results, Observations, Conclusions

Many design iterations were performed in virtual environment by performing CFD simulations to understand the flow physics as well as impact of various parameters affecting erosion rate inside air outlet header. Each design modification and its impact on erosion rate is compared with base design to check the effectiveness of modification. Finally, with the help of simulation, three better designs were identified, which reduces the erosion drastically.

Novel/Additive Information

With the help of CFD simulation, one can test various design modifications as well as find a solution in less time and with less cost as compared to cost associated with inspections and repair.
Challenges and Achievements of Drilling Record MRC Wells for Appraising and Developing an Offshore Tight Carbonate
Authors: Alyan Mohand Ahmed , Duguid Jamie Scott , Shahzad Atif , Alobeidli Amna Ahmed , Al Suwaidi Alunood Khalifa , Prim Matthew Thomas , Wills John Andrew
Published: December 2021

This paper describes the field development planning strategy for appraising and developing an offshore reservoir area via extended reach extra-long maximum reservoir contact laterals drilled from an artificial island. These single production and injection laterals are completed in excess of 20,000 ft on top of tens of thousands feet of drilled well path to reach the drain landing point. These laterals have a dual purpose, as in addition to reservoir appraisal, is to maximize the productivity and injectivity in an on-going development of a tight carbonate reservoir.

The well planning process starts from a careful selection of reservoir target coordinates to maximize the oil in place being developed from the artificial island and to enable reservoir testing and appraisal. From this data, initial 3D well designs are generated based on island location and rig capability to ensure ability to drill and run completion to total depth. The generated well tracks are used in a reservoir model to forecast production uplifts and inflow/outflow profiling along laterals. A strategic drilling step-out program has been implemented to extend drilling reach and completion deployment incrementally along with a reservoir surveillance program. The program was designed with built-in risk mitigations for any potential drilling and completion issues. The implemented program has enabled drilling into new areas and testing the reservoir properties at a small incremental cost of extending horizontal laterals. This has led to huge cost savings versus a very expensive appraisal program from a wellhead platform that included drilling a new well in addition to topside facility changes and pipelines conversions along with associated maintenance costs. The data gathered from these wells have enabled reduction of geologic uncertainty and de-risking of future developments. As a result, the field development footprint of developed oil resources was extended by additional 20% without the requirement of building additional drilling structures. Additionally, there is a well count reduction via lateral extension thus leading to capital costs saving. There were initial challenges encountered during lower completion deployment but they were resolved successfully in subsequent wells. An outcome of this strategy was the successful drilling of maximum reservoir contact wells with tens of thousands feet of drilled well path to reach the drain landing point and then with single horizontal drains exceeding 20,000 ft. The drilled wells resulted in unprecedented records in UAE and globally in terms of well total length, horizontal drain length and completion deployment.
Enabling Extended Reach Wells with the Aid of an Ultra-High Speed Rotational Reamer Shoe
Authors: Naknaka Manchukarn , Nkwocha Chimere , Prasongtham Pattarapong , Tongkum Tossapol , Phu Trinh Dinh , Siritheerasas Khamawat
Published: December 2021

Well X is an infill horizontal well designed for the Gulf of Thailand. It is challenging due to the following factors - A long 8 ½ inch open hole section, An extended reach section at horizontal or near horizontal, the presence of loss circulation zones, an Extended Reach Drilling (ERD) ratio of 2.725 and a Drilling Difficulty Index (DDI) of 6.762. The key challenge was to successfully deploy the 7 inch casing across 12,350 ftMD of open hole, with potential loss circulation zones. In spite of these difficulties, the 7 inch casing was successfully landed with the use of an Ultra-High Speed Rotational Reamer Shoe.

Historically, losses of circulation have posed significant challenges to well delivery in the Gulf of Thailand wells. In Well X, this is further complicated by a long open-hole section with a step-out of over 10,000 ftMD. It was determined that the successful deployment of the 7 inch casing would require some degree of agitation at the nose, and such a device must be tolerant to the Lost Circulation Materials (LCM) type and the composition of the drilling fluid and the cement. An ultra-high speed rotational reamer shoe was specially configured to meet the LCM requirements in the displaced fluid, for use in deploying the casing.

While deploying the 7 inch casing, losses of up to 20 bbls/hr occurred from 7,043 ftMD while running at 15 joints/hr. A loss circulation recipe comprising of 60 bbls of 30 ppb Tiger LCM was mixed and successfully displaced through the customized ultra-high speed reamer shoe to cure losses. The casing was washed down from 10,569 to 11,610 ftMD, filling casing each stand.

The 7 inch casing was successfully landed at the target depth of 12,353 feet and subsequently cemented. Drill out operations took 1.5 hours to complete. A formation integrity test (FIT) showed good shoe strength which was later confirmed by the cement evaluation logs. The comprehensive Ultra-High Speed Reamer Shoe was configured with a minimum restriction of 15mm, which is 5 times the diameter of the maximum particle size in the LCM of 3 mm. The tool was designed to tolerate the prescribed loss circulation materials, making it possible to cure the losses while running the casing string.

The innovative Ultra-High Speed Reamer Shoe has demonstrated its usefulness by providing a higher probability for successfully deploying the 7 inch production casing over the extended reach section of Well X. The application of this technology can mitigate against non-productive time such as wiper trips or excessive washing down or casing rotation. It has proven to be a reliable technology that can be used in the industry in challenging well designs.
Autonomous Corrosion and Scale Management in Electric Submersible Pump Wells
Authors: Van Spankeren Michael Hendrik , Hernandez Miguel Angel
Published: December 2021

Producers find a considerable amount of their operating expense (OPEX) comes from managing risks associated with corrosion and scale. Monitoring and chemical adjustment workflows are typically manual, and performed at low frequencies, leading to delays in event detection. As a result, the potential for negative events such as production shutdowns and well failures increase. This project's scope integrates chemistry domain experience with edge analytics, machine learning models, and intelligent equipment, to transform manual processes into an autonomous solution. The goal is to optimize operations, reduce well failures and workover costs, and maximize production. This solution is currently deployed in an oilfield, that has been historically challenged with a high number of electric submersible pump (ESP) failures due to corrosion and scale that resulted in significant production losses and unforeseen workover costs. The designed digital architecture supports autonomous management of scale and corrosion through remote monitoring and automated chemical injection. Real-time data is acquired from connected equipment, processed in an edge device running artificial intelligence, and autonomously sent to chemical pumps. Data from sensors, connected devices, and models are visualized in cloud applications, or integrated into existing client systems for end user analysis and full visibility of the entire process. The results show highly accurate models, precise chemical injection, and a reduction of well failures.
Big Data IAOM Project Management and Workflow Automation in a Giant Gas Field Digitization Drive
Authors: Alsaeedi Ayesha Ahmed Abdulla Salem , Elabrashy Manar Maher Mohamed , Alzeyoudi Mohamed Ali , Albadi Mohamed Mubarak , Soni Sandeep , Isambertt Jose , Tripathi Deepak , Shah Ankit
Published: December 2021

Integrated asset modeling, application of big data, and automation are among the top emerging trends in the oil and gas industry. The value associated with such implementation projects is very closely linked with the efficient use of the project management approach and a robust strategy to handle the technological challenges. This paper puts light on such initiatives implemented in a giant gas field.

In this giant gas condensate field, a vast amount of data is generated and monitored on a daily basis. The frequent need to deliver the dynamic production target was driving this project implementation so that a value-driven system can be established while achieving the business KPIs. A phased approach was used to target multiple requirements into business deliverables where the early offline phases provided a robust base for full online integration. This project followed the agile approach focusing on getting insights from multiple stakeholders and domain experts and developing a lesson-learnt repository in all the project phases.

The online integration solution is a critical differentiator in the workforce and process efficiency improvement. The multiple technical solution workflows helped in reducing manual efforts and streamlining the methodology in a standardized fashion. In addition, the standard project management practices, such as initializing the phases in a planned manner, followed by an interactive execution, monitoring, and controlling stages, ensured delivering project outcomes in an efficient way. This implementation also established a robust collaborative team effort to identify various different roles and responsibilities for stakeholders. This helped in the end phase when the project sustainability was essential. A strong team base maintained and updated the integrated system while delivering daily well and facility surveillance objectives and KPIs from users ranging from planning, engineering, operation, and management team. A special focus on IT team involvement throughout the project phase led to a successful data integration and diagnostic, as the core of the solution was a data-driven analytical framework integrated with multiple corporate and real-time data sources. In addition, this solution was equipped with various one-of-its-kind solution features such as business intelligence, advanced surveillance, dynamic-reservoir integration, manage-by-exception workflows, intelligence alerts, along with a strong digital framework and data architecture.

The unique hybrid and agile project management approach focusing on delivering emerging trends and technologies to end-users in the most efficient way paved the way for achieving asset digitalization and standardization goals.
World'S First Successful Dual String Installation of a Digital Intelligent Artificial Lift DIAL - Interventionless Gas Lift Production Optimization System, Offshore Malaysia
Authors: M Ghazali M Haziq , Rozlan M Rizwan , Bakar M Farris , Ishak M Faizatulizuddin , Samuel Orient Balbir , Misron Mohd Al Perdaus , Ismail Mohamad Sazwan , Salleh Nurfarah Izwana , Rizwan Badroel , Amara Abdel Ben , Faux Stephen , Ahmad Azhari Ahmad Hafiz , Muara Azis Anak
Published: December 2021

PETRONAS completed well H-X on B field in Malaysia with a digital intelligent artificial lift (DIAL) gas lift production optimization system. This DIAL installation represents the first ever successful installation of the technology in an Offshore well for Dual String production. This paper provides complete details of the installation planning and operational process undertaken to achieve this milestone.

DIAL is a unique technology that enhances the efficiency of gas lift production. Downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention.

This paper focusses on a well completed in November 2020, the fourth well to be installed with the DIAL technology across PETRONAS Assets. The authors will provide details of the well and the installation phases: system design, pre-job preparations, improvements implementation, run in hole and surface hook-up. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits.

DIAL introduces a paradigm shift in design, installation and operation of gas lifted wells. This paper will briefly highlight the justifications of this digital technology in comparison with conventional gas lift techniques. It will consider value added from the design stage, through installation operations, to production optimization.

This DIAL system installation confirms the ability to be implement the technology in a challenging dual string completion design to enable deeper injection while avoiding interventions on a well with a greater than 60-degree deviation. With remotely operated, non-pressure dependent multi-valve in-well gas lift units, the technology removes the challenges normally associated with gas-injected production operation in a dual completion well – gas robbing and multi-pointing.

Despite the additional operational & planning complications due to COVID-19 restrictions, the well was completed with zero NPT and LTI. Once brought online, this DIAL-assisted production well will be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS’ upstream digitization strategic vision.