bluuebunny/crossref_metadata_2025 huggingface dataset:
Corrosion Mitigation Using Nonmetallic Piping for In-Plant Hydrocarbon Service
Authors: alghanim Abdullaziz Abdullah
Published: December 2021

The underground hydrocarbon metallic lines are usually subjected to severe corrosion due to several reasons such as high water table in the area and due to intermittent bi-directional crude service or similar environmental factors. To meet the challenge, non-metallic underground crude transfer lines may be considered to carry oil from/to the bulk storage sites. Since there are not many non-metallic applications in HC services, it may become a challenge to get the necessary approvals from the various stake holders in terms of concerns for asset integrity and the costs. This report details the conversion of metallic crude pipeline application to a non-metallic one.

Normally, the in-kind replacement will involve an internally coated CS line to reduce corrosion rate. However, engineering studies and assessments reveal that there are greater economic benefits when adapting to a non-metallic counterpart. For a generic case, hydraulics on a 1.7km crude transfer line with 48" diameter and the intermittent crude service revealed that 36" non-metallic version could do the job with less installation costs as minimal site activities will be required and there will be no requirements of non-destructive tests (NDT). Only a service test following the installation may be necessary to prove the operational integrity. Cost comparisons showed a 28% less project cost in using the non-metallic pipeline while meeting all other application requirements.

The introduction of non-metallic line would take away the problem of the external and internal corrosion from the equation. Especially in the aging facilities where fatigue becomes an issue, the carbon steel line always requires additional maintenance activities and there was always a chance to develop an underground pin hole. Therefore, an extensive inspection program had its own costs to maintain the line. With the non-metallic pipe usage, not only the construction costs can be lowered but it could avoid major inspection and maintenance program costs. The Nonmetallic line is considered low to maintenance free, and additional long-term savings are expected.

This application opens the door for the utilization of nonmetallic material in plant hydrocarbon processes. And given the size considered of this line (36 inches), this allows for further consideration to install nonmetallic piping on a wide range of applications. Also, non-metallics are especially effective for sluggish or intermittent flows and areas with high water table to avoid all sorts of erosion and corrosion issues internally due to process conditions or externally due to environmental conditions.
Integrated Logistics Solutions Provider Project
Authors: DeJonge Markus Alfred , Abdul Salam Mohammad , Ward Pete Miguel
Published: December 2021

The Integrated Logistics Solutions Provider concept was introduced to support offshore drilling and production operations, save 20% on logistic costs, increase operational efficiency to achieve Just-in-Time deliveries and enable the upstream portfolio to focus on core competencies, thus seeking an One-stop contractor for logistics.

This manuscript details how the logistics provider changed its operating model to an Integrated Logistics model, changed the status quo to become a competitive low-cost operating logistics provider and enabled operational and cost efficiency for Exploration and Production (E&P) customers. It also reflects on the technologies and commercial mechanisms used to drive the functioning of the operating model that meets the requirements of oil and gas operators.
Integrating Laboratory Testing and Numerical Modelling for a Giant Maturing Carbonate Field in UAE — II. Coupled Geomechanical Modelling of Stacked Reservoir Intervals
Authors: Noufal Abdelwahab , Nasreldin Gaisoni , Al-Jenaibi Faisal , Martin Joel Wesley , Guerra Julian , Al Sahn Hani , Muniz Eudes S. , Khan Safdar , Shehab Abdulla M.
Published: December 2021

A mature field located in a gently dipping structure onshore Abu Dhabi has multiple stacked oil and gas reservoirs experiencing different levels of depletion. The average reservoir pressure in some of these intervals had declined from the early production years to the present day by more than 2000 psi. Coupled geomechanical modelling is, therefore, of the greatest value to predict the stress paths in producing reservoir units, using the concept of effective stress. This paper examines the implications for long-term field management—focusing primarily on estimating the potential for reservoir compaction and predicting field subsidence.

This paper takes the work reported in Noufal et al. (2020) one step further by integrating the results of a comprehensive geomechanical laboratory characterization study designed to assess the potential geomechanical changes in the stacked reservoirs from pre-production conditions to abandonment. This paper adopts a geomechanical modelling approach integrating a wide array of data—including prestack seismic inversion outputs and dynamic reservoir simulation results. This study comprised four phases. After the completion of rock mechanics testing, the first modelling phase examined geomechanics on a fine scale around individual wells. The goal of the second phase was to build 4D mechanical earth models (4D MEMs) by incorporating 14 reservoir models—resulting in one of the largest 4D MEMs ever built worldwide. The third phase involved determining the present-day stress state—matching calibrated post-production 1D MEMs and interpreted stress features. Lastly, the resulting model was used for field management and formation stimulation applications.

The 4D geomechanical modelling results indicated stress changes in the order of several MPa in magnitude compared with the pre-production stress state, and some changes in stress orientations, especially in the vicinity of faults. This was validated using well images and direct stress measurements, indicating the ability of the 4D MEM to capture the changes in stress magnitudes and orientations caused by depletion. In the computed results, the 4D MEM captures the onset of pore collapse and its accelerating response as observed in the laboratory tests conducted on cores taken from different reservoir units. Pore collapse is predicted in later production years in areas with high porosity, and it is localized. The model highlights the influence of stress changes on porosity and permeability changes over time, thus providing insights into the planning of infill drilling and water injection. Qualitatively, the results provide invaluable insights into delineating potential sweet spots for stimulation by hydraulic fracturing.
Success Implementation of Pressurized Mud Cap Drilling in Offshore East Java Prospect, Avoid Rig Flat Time During Loss Circulation and Continue Drilling with 400psi in the Annulus to Reach Target Depth Through Fractured Carbonate Formation in 2 Days
Authors: Fikri Irawan , Ali Ali , Airil Ismi , Andry Prasthio , Teguh Setiawan , Agung Pratama
Published: December 2021

The offshore East Java laid numerous carbonate formation, where depending on area, carbonate formation is exercised as the reservoir. The carbonate exploration drilling campaign, which is naturally fractured, risks the operation not just from safety aspect but also deliverability of well objective to explore uncovered reserve in the area.

In this well, total loss circulation was experienced while drilling, despite no record of similar event from offset wells data. The field operator determined to call out Rotating Control Device (RCD) and installed prior to drilling 12.25in. hole section. The Pressurized Mud Cap Drilling (PMCD) method is prepared in advance as mitigation plan to overcome the exploration uncertainties. PMCD is one of the Managed Pressure Drilling (MPD) variants used in oil and gas wells that experience severe to total loss circulation. PMCD method involves drilling with closing flowline valve completely while using RCD system to seal the annulus.

While drilling the 12.25in section, absence of return fluid observed as drill string penetrates the carbonate reservoir section (target formation). Activation of the annulus flooding system enables to pumps seawater through annulus, continued with pulling out the string to last casing shoe, and then installation of RCD bearing assembly to convert drilling strategy into PMCD method. As the PMCD components required such as RCD and drill string Non-Return Valve already equipped and all associated procedures prepared in advance, swift transition to PMCD mode results to lesser drilling flat time. After reaching target depth, the PMCD setup also assists in the deployment of open hole logging operation by installing RCD logging adaptor.

With the successful PMCD implementation, the field operator managed to reduce drilling risks, reach exploration target successfully, reduce flat times and increase in ROP. This paper present success story of PMCD well drilled and lessons learned as the operator evolves to improve PMCD execution further.
Innovative Solutions to Decarbonize Hydrogen Production
Authors: Pitcher Matt , van 't Hoff Martin , Basmajian Narik
Published: December 2021

The Energy Transition mandates durable long-term solutions for reducing greenhouse gas (GHG) emissions by addressing future energy needs in terms of generation, storage and utilization.

Hydrogen is essential to low-carbon energy solutions, particularly in the "difficult-to-decarbonize" segment of energy markets. Deeply decarbonized, cost-effective hydrogen production solutions are already accessible at industrial scale, for both new plants and for retrofits. For newly built plants we easily arrive at deeply reduced carbon footprints, and KPI's comparable to the most competitive green solutions. Retrofitting existing hydrogen plants to "blue plants" is not only feasible, but is a particularly cost-effective carbon reduction measure.

This paper addresses carbon intensity of various hydrogen production routes: ranging from traditional grey hydrogen (itself with proven options for carbon mitigation) through blue hydrogen with various schemes and capture depths, as well as green hydrogen (generally by electrolysis).
Advanced Engineering Solutions to Achieve Best in Class Performance in Drilling Extended Reach Dual Lateral Wells in the Sultanate of Oman
Authors: Al Amri Yahya Badar Nasser , Al Rawahi Qasim , AL Adawi Humaid , Al Maashari Badar , Soden Ludovic , Al Kaifi Ahmed , Al Hussaini Marwan
Published: December 2021

A Large Omani Operator successfully achieved best in class performance in drilling extended reach dual-lateral wells in Oman. Turning the legs to achieve the required separation distance and continue drilling to the required depth through a thin fractured reservoir resulted in complex well trajectories and harsh drilling environment. This paper will focus on the newly innovative designs, engineering optimizations and utilizing lean methodology to overcome drilling risks and achieve best in class performance.

Rotary Steerable system was utilized to drill the extended reach drilling (ERD) in 3D with continuous proportional steering technology. Advance modeling including lateral shocks, Torque and Drag and BHA design were as well key enablers. Logging while drilling tools supported reservoir mapping and real-time well placement decisions. To excel in lateral applications and overcome harsh drilling

environment, a shallow cone tip profile with High Performance cutter bit technology was selected. A focus optimization project using lean tools was performed to map out the undercut process, visualize possible waste, perform root causes analysis and implement countermeasures to eliminate the process waste

Regional benchmark showed that the performance of 11 wells drilled since the start of the campaign is located within the best 10% of the benchmark data which is marked as best in class performance. Due to the continues improvement, the campaign manages to reach a learning curve of 30%. Furthermore, the actual production from the wells was 300% more than the forecast. Using the advanced RSS and bit technologies resulted in reducing the Torque values in the lateral section by 30% which effectively increased the reservoir drilled interval by 22%. The designed BHA also managed to complete wells including multi undercuts (up to 6) in one run. One trip Whipstock System for creating the second leg is used as part of the well design. The Whipstock system which is uniquely set in the horizontal tangent section has achieved 100% success rate in setting and retrieving operations. The undercut activities have improved by 50% as a direct result of the optimization Lean project. In addition, utilizing lean methodology resulted in reducing the cost impact of the additional sidetracks (undercuts) which enabled having best reservoir quality and achieving savings over the total cost of ownership TCO.

Extended Reach Dual lateral well design was utilized for the first time in PDO operations during this drilling campaign. This paper will present how advance modelling can enable the industry to deliver complex well designs. Additionally, it will introduce the company innovation in implementing the Lean philosophy to optimize the drilling operation.
Safety 4.0 for the Most Dangerous Industrial Objects
Authors: Razuvaev Igor
Published: December 2021

Isothermal Storage Tanks (IST) contains tens thousands tons of the liquefied gases (propane, ethane, ethylene, etc.) at very low temperatures. These are the most dangerous industrial objects. In the report the Integrated Structural Health Monitoring (ISHM) Systems for the management of the integrity of these tanks in real time is considered. The structure of the ISHM Systems, NDT methods, technical characteristics, data verification procedures, a decision-making algorithm and practical results are described.
Design of an Economical Polymer Flood Pilot Addressing Field Development Uncertainties in the Sabriyah Upper Burgan Reservoir of North Kuwait
Authors: Al-Murayri Mohammed T. , Kamal Dawood , Al-Mahmeed Najres , Al Kharji Anfal , Baroon Hadeel , Pitts Malcolm J. , Skeans Elii , Salehi Mehdi , Dean Elio , Obernyer Stan
Published: December 2021

The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.
An Innovative Approach to Install Production String with ESP to Avoid Productivity Impairment in Multistage Fractured Horizontal Well
Authors: Aftab Muhammad Nadeem , Amjad Kashif , Elmansour Ayman , Talukdar Animekh , AlHanaee Ahmed Rashed , El Sonbaty Tarek Mohamed
Published: December 2021

Objectives/Scope

Generally, tight reservoirs require hydraulic fracturing to enhance and sustain hydrocarbon production. However, fracturing requires frac string with bigger Internal Diameter (ID) to minimize frictional losses during hydraulic fracturing operation. This string ID may not be suitable to provide optimum Vertical Lift Performance (VLP) during production phase, particularly in oil wells. Therefore, it is required to replace the frac string with production string of smaller ID. Occasionally, artificial lift also becomes essential to overcome VLP issues in future due to progressive water production and declining reservoir pressure.

Methods, Procedures, Process

Completion replacement often causes reservoir damage due to killing operation, which can be removed in conventional carbonate reservoirs by matrix stimulation. However, formation damage removal is difficult in hydraulically fractured tight carbonate and sandstone reservoirs. Preventive measures become essential to avoid productivity impairment particularly in hydraulically fractured reservoirs. Different preventative options are proposed and reviewed to isolate reservoir with their advantages and disadvantages.

After comprehensive studies and risk assessments, an innovative modification in the completion plan was introduced and finalized. This plan includes production string with Electrical Submersible Pump (ESP) to improve VLP. This completion provides full accessibility intervention job, which may be required for reservoir monitoring and surveillance in future.

Results, Observations, Conclusions

A comprehensive production test is performed to evaluate and compare the testing results of pre and post workover. Testing results show there is no impairment in productivity of the reservoir, which is avoided in workover process by isolating reservoir section.

This paper summarizes the completion design process, selection criteria, challenges, and lessons learnt during design and execution phases. This technique will provide the guidelines for installation of the Production string/ESP in hydraulically fractured reservoir without productivity impairment.

Novel/Additive Information

With modified design, the reservoir is isolated from wellbore and completion with ESP is run successfully without killing reservoir section. Underbalance conditions are achieved prior to establishing communication between reservoir and wellbore.
Applying Digital Technologies Beyond Design Life
Authors: Feijo Luiz Paulo , Wang Suqin , Machado Christiane
Published: December 2021

This paper focuses on Floating Production Installations, which are assets designed based on site-specific environmental conditions to determine their design service life. The longevity of these assets depends on the fatigue aspects related to the structural elements and mooring systems. Among the challenges involving the continued services of ageing assets is the integrity of these elements. When an asset reaches its end of design service life, Operators often decide to undergo a life extension process for safe continued operations.

Alife extension process generally includes three phases: investigation, determination and implementation. Following a baseline inspection to determine the present conditions of the structures, engineering assessments are to be carried out to evaluate the fatigue damage through the lifecycle of the installation and therefore determine the remaining fatigue life.

Collecting information to execute these assessments is challenging and can be automated with the use of digital technology. Digital tools allow an accurate collection of data, providing a continuous evaluation of the remaining fatigue life and supporting an informed decision-making process. Observing the operation of several aging assets and their structural behaviour, the parameters to be measured during the installation's lifecycle have been identified along with other aspects that also contribute to the determination of its continued service. The recommended data acquisition for relevant measurements is summarized in this paper.

The application of sensors and monitoring systems on the installations allows measuring these parameters on a continuous basis, and consequently, Operators are able to determine the degradation pattern that the structure is subject to. An estimation of the remaining fatigue life can be achieved by using predictive analysis, which, along with insights of the future expected corrosion, provides Operators the necessary basis to implement corrective measures and mitigations to avoid the occurrence of a failure.

This paper offers an innovative, forward-looking technology that allies physics-based processes with digital technology, supported by predictive analytics and continuous structural evaluation, to assess the integrity of an offshore asset in support of safe continued services.
Managing Energy Transition - Adapting Power to Gas Technology PTG - Project Management Review of Complexity, Technology and Integration Aspects
Authors: Purayil Prasannakumar K. , Pratap Chandran Sujith
Published: December 2021

Managing climate change is a growing global concern. The Paris Agreement, the first ever legally binding global climate change agreement, enforced longer term actions for energy firms in terms of implementing newer means and technologies to reduce reliance on fossil fuel-based energy. In this regard, much attention is drawn to commercialized Power-To-Gas (PTG) - Hydrogen generated from renewable energy-based electrolysis can be introduced into natural gas utilities, thereby ensuring "Greener" natural gas mix. The integration of PTG plants and natural gas-fired power plants presents an attractive model to implement this. This paper analyzes the associated project management challenges, ranging from complexity issues to technology management and with a view on better integration and risk reduction.

Power-to-Gas (PTG) is the process of converting surplus renewable energy into hydrogen gas through electrolysis. PTG plants and natural gas-fired power plants can form a closed loop between an electric power system and an interconnected multi-energy system, and this is believed to be a sustainable solution towards environment friendly energy systems. Power-to-Gas (PTG) technology is yet to mature in terms of its commercial viability. As such, traditional project management processes and methodologies also need to be reviewed and adapted to suit the economic and execution models needed for project success. The dimensions that will be analyzed in this paper include project integration management, project complexity management, technology management and risk management strategies. A model for Joint Venture management will also be proposed.

PTG projects, as an effective means of transitioning to a ‘greener’ natural gas mix and the associated project life cycle process will be defined based on an integrated FEL (iFEL) model. Project risk management perspectives, its stakeholder influences and methods to mitigate risks towards better decision-making process shall be explored.

This work proposes establishment of a dedicated, technically competent and scalable Global PMO to oversee the PTG projects’ prioritization, concept/technology selection, JV management, contracting strategies, formulation of a proactive management response system and overall value assurance.
Successful Unconventional Fracturing Tight and Highly Laminated Silicilyte Reservoir Leading to Economic Field Development
Authors: Moiseenkov Alexey , Smirnov Dmitrii , Al Hadhrami Abdullah , Agrawal Pankaj , Harrasi Amira , Manthari Monther , Busaidi Asaad , Fanis Khayrutdinov , Sayapov Ernest , Isaee Omar
Published: December 2021

South Oman contains several tight silicilyte reservoirs with significant locked hydrocarbon volumes. Successful hydraulic fracturing is key for unlocking commercial production. Low production rates coupled with fast declines have remained a challenge and a new economically attractive development scheme was required.

Through integrated re-evaluation of the geology and reservoir, a modified frac approach was designed to create more connectivity to the reservoir height, using an unconventional frac design and frac fluids plus over-flush. Poor well productivity in tight silicilyte reservoir can be explained by low permeability of 0.001-0.1 mD and laminated texture with almost zero vertical permeability.

Fit for purpose modelling was performed to assess the forecasting range for sub-surface uncertainties and frac parameters. One of the key changes for a successful development strategy was to place a higher number of fracs to overcome the extreme lamination. [1]

It was observed that the "conventional" fracturing approach inaccurately assumed higher vertical fracture coverage of the reservoir and that the guar fluid used was much more damaging due to low recovery after frac clean-up.

Fifteen unconventional fracs were pumped successfully with over-flush pumping technique. To understand if this new unconventional approach was effective in overcoming the extreme lamination required additional understanding of fractures geometry and orientation.

To confirm fracture dimensions and flowing heights; a set of radioactive, chemical tracers and logging activities were completed. Flowback results showed that the unconventional frac [3] fluid used, was relatively easy to recover from formation and better cleaning-up of fractures can be achieved. This led to successful well clean-up compared to previous wells in the same field and confirmed better fracs clean up. Initial production results confirmed at least double well initial productivity, which should lead to better stable oil production from the field.

Radioactive tracers logging, Sonic logging and Spectrum Noise Logging (SNL) confirmed mechanical and conductive fracture heights. Sonic logging also confirmed frac orientation. Oil and water dissolvable tracers confirmed fractures clean up from water and oil production intervals.

Full geological and reservoir understanding, out of box thinking in frac technology allowed the asset team to come up with an unconventional development approach to improve commercial production from tight silicilyte reservoirs.

The new frac approach included unconventional frac design and fluids, and execution using over flush and resulted into unlocking significant reserves. A more economic full field development is being planned and replication of the new frac approach is already ongoing in other fields.
Reducing Gas Emission Mechanisms for Hydrocarbon Storage Tanks
Authors: Kamel Merhane , Eickhoff Jeffrey Daniel
Published: December 2021

Volatile Organic Compounds (VOC) which are emitted from tank farms of petroleum refineries are considered to cause harmful impacts to the environment and people. This paper presents the methodology of assessing potential targets for reduction of emissions, as well as proposed control mechanisms and their reductions, for hydrocarbon storage tanks at Jebel Al Dhanna Terminal. Some of the emissions reduction opportunities which are covered include aluminum dome retrofits, seal integrity improvement and guide pole treatments. The objective is to find significant reduction opportunities (from between 50% to 90% of current tank configurations) using passive technologies which prevent or inhibit emissions without the use of additional operational energy or active systems that would otherwise require significant maintenance or operational expense.
Submersible Pump with Line Shaft Pump in Shallow Water, Optimum Selection for Offshore Application in the Oil & Gas Industry
Authors: Mohammed Shafir , Kobbia Ibrahim
Published: December 2021

Seawater is an essential fluid used in various process circuits, such as cooling, reinjection into the wells and utilities, etc., in the offshore oil and gas industry. Vertical pumps facilitates with lifting seawater to the platform. This study investigates and compares two pump alternatives that has been widely used in oil and gas industry for seawater lift application: Vertical line-shaft pump and Electrical submersible pump.

Existing seawater lift pump operating parameters are used as the basis of this study. The pump that is considered for the study has a flow rate of 3415 US GPM (776 m3/hr.) with a total head of 250 ft. The motor rating is 350 HP. The overall length of the pump is 21 meters. The main methodology used is a Life Cycle Cost Analysis (LCC) where the total cost of ownership of the vertical line-shaft pump and electrical submersible pump were analyzed for a period of 30 years. Furthermore, this research also addresses the operational drawbacks associated with both the pumps.

Submersible pumps have higher initial capital investment cost when compared to line-shaft pump of similar capacity and size. The energy consumption cost of submersible pumps are higher mainly owing to lower efficiencies of the motors. The power factor for submersible pumps are lower in relation to line- shaft pumps. One of the main benefits of submersible pumps are their less installation and pump pullout time. Submersible pumps occupies lower space above ground when compared to line-shaft pumps. Additionally, submersible pumps are less noisy and have lower vibration in comparison to line-shaft pumps.

This paper aims to provide key information and knowledge for engineers to make prudent decision regarding selection of the most cost effective pump for the seawater lift application with a tangible added cost value to both Capital Expenditures (CAPEX) and Operational Expenditure (OPEX).
Integrity Challenges Associated with Stray Current Corrosion Across Monolithic IJ's and Resolutions
Authors: Al Salemi Ebrahim Salem , Al Ameri Saleh Salem , Nair Ajiv Mohan , Ali Humaid Musabah Al , Zantua Mario Jr Javier , Ebaid Mohamed Ibrahim
Published: December 2021

Corrosion and subsequent failures is one of the main factors affecting uninterrupted operations of Oil & Gas Industries. Pipelines are considered as most convenient means of crude and gas transportation in Oil & Gas Industry. Buried pipelines generally made of low carbon steel material are protected externally by coating and applying impressed current cathodic protection (ICCP). Monitoring and maintaining adequate level of Cathodic Protection (CP) for such pipelines remains challenging for corrosion engineers due to increased level of field congestion, complexity in accurate current mapping and mitigation of corrosion phenomena. Failure of pipelines due to corrosion can be catastrophic with following consequences: Loss of containment fluid and thereby probable fatalityDamage to asset/company reputationSafety and Environment (Fire, Toxic gases and Oil Spill)Resource and downtime cost impact

Isolation joints IJ's are designed with very high insulating material at mating areas and installed on pipelines by welding to avoid loss of Cathodic Protection (CP) current. Due to high electrical insulation, a potential difference is formed across of IJ's due to applied CP current and stray currents. In upstream Oil & Gas Industry, multiphase crude transported via pipeline will have certain percentage of water and will induce an internal conductive path across the IJs resulting in ionic current discharge at anodic areas within internal surface. This study focuses on factors contributing to such internal stray current corrosion, limitation in monitoring methodology and mitigation programs. The study concludes with recommendations such as design modifications, improvement in internal lining properties and improved installation guidelines. The study practically illustrates effectiveness of combined resistive bonding and zinc earthing cells installation for controlling stray current propagation in order to reduce the corrosion rate so as to maintain Integrity of pipelines.
Innovative Approach to Build a Scalable Hybrid Model for Prescriptive Maintenance
Authors: Büssow Richard , Hain Bruno , Nuaimi Ismael Al
Published: December 2021

Objective and Scope

Analysis of operational plant data needs experts in order to interpret detected anomalies which are defined as unusual operation points. The next step on the digital transformation journey is to provide actionable insights into the data. Prescriptive Maintenance defines in advance which kind of detailed maintenance and spare parts will be required. This paper details requirements to improve these predictions for rotating equipment and show potential to integrate the outcome into an operational workflow.

Methods, Procedures, Process

First principle or physics-based modelling provides additional insights into the data, since the results are directly interpretable. However, such approaches are typically assumed to be expensive to build and not scalable. Identification of and focus on the relevant equipment to be modeled in a hybrid model using a combination of first principle physics and machine learning is a successful strategy. The model is trained using a machine learning approach with historic or current real plant data, to predict conditions which have not occurred before. The better the Artificial Intelligence is trained, the better the prediction will be.

Results, Observations, Conclusions

The general aim when operating a plant is the actual usage of operational data for process and maintenance optimization by advanced analytics. Typically a data-driven central oversight function supports operations and maintenance staff. A major lesson-learned is that the results of a rather simple statistical approach to detect anomalies fall behind the expectations and are too labor intensive. It is a widely spread misinterpretation that being able to deal with big data is sufficient to come up with good prediction quality for Prescriptive Maintenance. What big data companies are normally missing is domain knowledge, especially on plant critical rotating equipment. Without having domain knowledge the relevant input into the model will have shortcomings and hence the same will apply to its predictions. This paper gives an example of a refinery where the described hybrid model has been used.

Novel and Additive Information

First principle models are typically expensive to build and not scalable. This hybrid model approach, combining first principle physics based models with artificial intelligence and integration into an operational workflow shows a new way forward.
Directional Radial Drilling Increases Reservoir Coverage with Precise Wellbore Placement Resulting in a Significant Production Increase from a Thin Reservoir
Authors: Bashirov Ayrat , Galas Ilya , Nazyrov Marat , Kuznetsov Dmitry , Akkuzhin Azamat
Published: December 2021

In many oil and gas provinces not only in Russia, but throughout the world, carbonate strata make up a significant portion of the sedimentary cover, and large accumulations of hydrocarbons are associated with them. However, the purposeful study of them as reservoirs for hydrocarbons in our country practically began only in the post-war years. In the special petrography laboratory carbonate rocks composing various stratigraphic complexes of almost all oil and gas provinces of the Soviet Union were studied, and in particular, Paleozoic carbonate strata of the Timan-Pechora province, Ural-Volga region, Belarus, Kazakhstan, ancient Riphean-Cambrian formations of Yakutia and relatively young strata of the Late Cretaceous of the northeastern Ciscaucasia.

Carbonates are widespread sedimentary rocks. A very significant part of them was formed in the conditions of vast shallow-water marine epicontinental basins. A large number of works are devoted to the study of such deposits. However, issues related to the conditions of formation of carbonate sediments and their postsedimentary changes cannot be considered resolved, as well as the classification of the rocks themselves.

The analyzed field is the Osvanyurskoye one. It was discovered in 2007. The field is located in the north-east of the European part of the Russian Federation, 2 km from Usinsk in the Komi Republic. The field is a part of the Timano-Pechora oil and gas province and it is a mature field (fig. 1). The objective was a 2.5m thick layer of the Serpukhov horizon.
An Approach to Natural Gas Valorisation Opportunities Screening Along the Decarbonisation Path
Authors: Iovane Massimo , Flisi Marco
Published: December 2021

Evolving energy needs and the global energy transition call for proper evaluation of how Natural Gas could support a Decarbonisation path, considering Natural Gas well recognised contribution to GHG emission reduction approaching the ambitious Green World.

However, the main question is how gas resources can be properly delivered to satisfy a wide range of markets and usages considering that fundamental driver is the goal of reducing carbon footprint.

A methodology was developed, named Gas Master Plan (GMP), which is an integrated study with a novel view, looking to synergic opportunities among energy sources while defining economically sustainable business models and meeting Decarbonisation targets.

A Gas Master Plan is a multidisciplinary study assessing the best valorisation routes for Natural Gas resources in a specified country or geographical region. This kind of study analyses gas and energy supply/demand balance, understanding current and future markets and looks for adequate destinations, check existing infrastructures and further possible developments carried by Local Governments or private entities, identify potential gas production for all the involved resources, business modelling, understanding the benefits to the global energy transition targets that such resources could deliver and screening monetization opportunities under a strategic plan view.

Thus, a GMP is not just an analysis of upstream volumes to verify whether they match commitments and still fit in their future development plans but it is company-wide joint effort to gather ideas, proposals, topics or issues to be addressed and possible solutions.

Broadly speaking resources considered in a typical GMP would be: those under an exploration phase, those just discovered for which a proper development has to be realised, those already in production but for which new market opportunities can be scouted in order to improve their benefit on the energy transition paths while seeking further economic returns.

The primary result is to develop a strategy to optimize present production and the development and valorisation of future gas assets, identifying the related GHG profile for each opportunity, supporting the decision-making process on new/future gas initiatives with a coherent plan.

The resulting outcomes and conclusions may address specific topics on the short to medium term, like associate to a gas field the proper development project to cover gas and energy commercial demand, or set targets achievable on the medium to long term like supporting a low carbon footprint growth in the energy sector and promoting gas-based industries.
Improvement Realized Through Digitized Engineering Business Process
Authors: Selvarasu Elugai Palanichamy , Al Hammadi Eslah Ali
Published: December 2021

Engineering Division provides services & support to Operations and Projects. Division develops deliverable / report / recommendation for various studies, operation issues related to Engineering, root cause analysis, etc. Division receives an average of five request in a week. Division is handling 175+ studies at a time with support of multiple discipline Engineers within division and are in different stages.

The division was handling the complete business process manually with dedicated resources to track the review, approval, execution and progress monitor.

It was difficult to track all the steps since the information were scattered with many stakeholders and manual entries are not robust / fool proof. The manual control was insufficient to manage document movement, monitoring engineering activities and progress.

This paper highlights the methodology used to digitalize the business process and also the improvement / benefit realized.
Strategies for Successful Project Execution – A Transformation in Project Delivery without Disruption
Authors: Srivastava Yogesh Chandra , Srivastava Abhishek , Canning Daniel
Published: December 2021

Cost overruns on lump sum turnkey projects have challenged Engineering, Procurement, and Construction (EPC) project implementations. Several causes can be attributed to this problem but common to all is that despite significant efforts spent in planning and estimating the job, most projects fail in the execution stage. A new approach to EPC projects execution and delivery combines better management of scope brought by the Advanced Work Packaging (AWP) procedure and efficiencies from the LEAN principles of an engaged workforce that was Toyota's success in manufacturing industry can be applied to construction industry. The implementation of this enhanced process supported by a digital tool, an end-to-end platform, can be extremely useful for projects in Petroleum Industry.

Methods, Procedures, Process: The approach has been designed to tackle three crucial challenges of project execution: people (company culture), process inefficiencies and data handling. The sense of inclusion, empowerment of a worker and the clarity of scope of every activity to be performed have a profound impact on the performance of the worker. It is designed to involve all stakeholders (from the owner to the last member of the crew) giving them an opportunity to contribute to the project implementation. The proposed enhancement of the processes at every stage of the project (from engineering to completion) drastically reduces the traditional inefficiencies of EPC projects which are responsible for cost overruns, schedule delays and poor quality of work.

Results, Observations, Conclusions: A plethora of digital tools used today in EPC industry create a large pool of data that can be leveraged to have an insight on the projects. However, all the data produced by different and disconnected tools are still used in silo and large data available creates complexity in analyzing and interpreting it. The AWP+LEAN approach brings transformation without disruption: an automated integration with existing systems used in the organization can be established in order to collect, give consistency and synchronize all the available information hassle-free.

The novelty of the approach presented in the paper compared to the other practices is its non-disruptive nature. The idea is to combine in a consistent fashion, all the information collected during the project by different tools and orchestrate them to provide a deep insight and granular visibility to the project. This means that there are no switching costs for the EPC companies and less resistance from people in adopting the new processes, making the journey to improvement easy and smooth.
A New LWD Dual Imager with Incorporated Feedback Improves Image Quality in OBM: Some Learnings form Abu Dhabi Offshore Carbonates
Authors: Abbas Nashat , Al Noukhatha Jamal , Al Nayadi Khulood , Shrivastava Chandramani , Zhang Tianhua , Yang Shiduo , Shasmal Sudipan , Maalouf Janine
Published: December 2021

Recent developments in Logging-While-Drilling (LWD) technology have enabled high-resolution borehole imaging in oil-base mud that used to be a long-standing challenge. New applications to enhance image interpretation and maintain feature-integrity were developed with feedback from Abu Dhabi field examples of recently deployed LWD dual imager where hostile drilling conditions impacted the high-resolution ultrasonic image quality.

The new dual imager has 4 ultrasonic sensors and 2 electromagnetic sensors (for resistivity image) mounted on a 15-ft sub in the drilling bottom-hole assembly (BHA). It provides ultrasonic amplitude and travel-time images at two central frequencies in addition to apparent resistivity images composed of four operating frequency measurements. A long lateral of around 8000-ft was drilled with this new imager through challenging heterogeneous carbonates and data was analyzed for geological interpretation.

Based on the feedback for data quality improvement in certain intervals, the impact of shock & vibration on high-resolution (0.2") ultrasonic images was analyzed in time domain with simulated data first to understand the behavior of causative factors independently. Afterwards, the new algorithms were developed and deployed to maintain feature integrity of the data. The validation on field-data provided much-needed validation for the results in hostile drilling conditions.

Resistivity images provided all the bedding and textural information (vugs, stylolites) with high confidence images at around 0.8" resolution. Higher resolution (0.2") ultrasonic images provided concrete information about vugs distribution for secondary porosity with quantitative interpretation on vug-indices. In addition, feedback provided from real time data was incorporated in subsequent processing and development of an image processing app that effectively fixes the depth-filtering related to drilling-induced events and stick-slip. Re-processing of the data provided high quality images that were used for high-resolution geological interpretation. Confident feature recognition was input into interpretation application hitherto available only in water-base mud while drilling.

Results of this study with feedback incorporated to field-data from Abu Dhabi helped better the geological interpretation in hostile drilling condition as well, minimizing the need for e-line imaging.