bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Structural Health Monitoring for Structural Digital Twin
Authors: Liu Xiang , Liu Haitao , Serratella Christopher
Published: November 2020

The load-carrying capability of marine steel structures often suffers degradation and at times structural failure during their service life due to the corrosive sea environment and the extreme wave loads which they experience. Structural integrity is a high priority during asset design and operation to preserve human safety, environment protection, and to maintain operations.

Structural Health Monitoring (SHM), a process of deriving the health status and predicting structural damage via sensor-based measurements, data trending and analysis, has been commonly implemented in marine and offshore assets for decades. There are mature commercial SHM products on the market and available international and industrial regulations, guidance and classification rules (such as IMO MSC/Circ. 646, ABS Guide for Hull Condition Monitoring Systems, etc.). With the emergence of the Structural Digital Twin (SDT) concept in the marine industry in the recent years, the application of structural sensors on marine structures and the integration between sensor-based SHM techniques and structural digital twin approaches have attracted more attention. As a digital representation of the physical asset, the structural digital twin typically involves multiple-scale, multiple-physics, and data driven models and simulations. Leveraging the high fidelity full-scale SHM data, the structural digital twin is capable to provide more accurate assessments, predictions, and insights on structural integrity conditions and support the decision-making process regarding asset operation, structural inspection, repairs, and condition-based asset integrity management.

This paper reviews the mature and commonly employed SHM sensor techniques (such as electric resistance strain gauge, fiber Bragg grating (FBG) strain gauge, accelerometer, pressure transducer, etc.) and discusses their implementation on marine assets and integration with structural digital twin. The paper elaborates to provide some general guidance on the selection of the structural sensors and their installation, as well as the proper sensor specification, in the context of a structural digital twin implementation. The paper also discusses the required engineering mindsets and skillsets for developing and deploying sensor plans, and for implementing a sensor-based structural digital twin framework. The paper concludes that a successful SHM plan and structural digital twin implementation rely on sensor planning, data acquisition, data processing, analytic models and a proper integration of the data and data analytics. The overall planning and implementation should be governed by the suitability for the business purpose and implementation expectation.
Integrated Predrill and Real–Time Pore Pressure prediction for Exploration Well Drilling in Xihu Depression, East China Sea
Authors: Lu Fawei , Gui Feng , Wang Meng , Bordoloi Sanjeev , Reese Michael
Published: November 2020

The drilling of the exploration wells in Xihu depression in East China Sea becomes very challenging as the drilling campaign shifts towards the deeper part of the west slope. Due to the complex pressure compartments formed by highly faulted blocks, unexpected high pressure encountered in the targeted formations has caused the early abandonment of some of the wells without managing to properly evaluate the reservoir potential. Providing an accurate pore pressure prediction therefore becomes very crucial to enable the decision-making process required for drilling success.

An integrated approach was adopted to combine detailed predrill prediction with real-time pore pressure monitoring considering the uncertainties in the seismic velocities and varying geological conditions in different faulted blocks. During the predrill modelling, a few nearby offset wells were reviewed in detail to construct the pore pressure model and to understand the overpresure mechanisms and geological settings. Seismic velocities at offset well locations were also compared with the acoustic logs to understand the uncertainties in different datasets. For the planed well, a range of low, high and most possible pore pressure profiles were interpreted using all the available data including seismic velocity and depth-stretched logs from different offset wells to account for the geological and geophysical uncertainties. During the drilling of the exploration well, real-time pore pressure monitoring was conducted by integrating the Logging While Drilling (LWD) acoustic and resistivity logs, mud logging and drilling data. Pore pressure and fracture gradient profiles were updated in real-time to enable proactive decision making to optimize mud weights and casing points to reduce drilling risks and hazards.

This approach was applied in the drilling of one of the exploration wells in Xihu depression. The well was drilled successfully by optimizing the casing design based on the real-time pressure monitoring results. This enabled the operator to properly evaluate and appraise the reservoir potential owing to setting a liner just above the high overpressured section in the deeper formations that caused drilling issues in previous wells. The overpressure magnitude was confirmed later by blind drilling for testing purposes.

After the completion of the planed well drilling, a post drill summary was conducted to compare the pressure models at different stages. In addition to the final detailed pressure model, a clearer understanding and interpretation of the overpressure transition, overpressure mechanisms and pressure variations compared to the nearby area were summarized and correlated for reference, while planning for drilling of the future wells.
Ten Years of Successful Tailored Cement Design and Execution in HP/HT Wells in Indian Offshore Drilling Projects: Case Study
Authors: Gupta B. K. , Dange Mikhil , Fortner Kelly , Kumar Animesh
Published: November 2020

The challenges, experiences, and best practices established from cementing in high-pressure high-temperature (HP/HT) offshore wells in India are discussed along with the design and tailoring per the parameters of each well, real-time operation analysis, post-operation evaluation, and lessons learned from 10 years of experience. Challenges encountered, associated potential risks, and solutions implemented to overcome such challenges in a bid to achieve desired zonal isolation are presented.

The obvious presence of high temperature (>400°F) and high pressure (>15,000 psi) as well as a narrow range of fracture gradient and pore pressure created challenges in cement, spacer design and field execution. Another task was to maintain desired rheological hierarchy and fluid compatibility of fluid pumped to achieve the desired displacement efficiencies under these vital well conditions. The introduction of specialty chemicals to develop cement and spacer fluid, which can help maintain downhole properties under these extreme conditions, has been vital to the success of dependable cement barriers in these wells.

The wells presented multiple issues during the course of planning, and a few of them had to be sidetracked one or two times. Losses during drilling, gas flow, etc., were commonly encountered in both 12 1/4- and 8 1/2-in. sections. This caused a reexamination of cementing practices, particularly for production sections completed with expandable liner hangers (ELHs). The successful liner operation in these wells encountered an additional challenge—placement of the cement sheath with a higher top of cement in a HP/HT environment. An integrated basis of design was developed to help mitigate challenges and achieve objectives, and it primarily included the following:

Successful running-in and placement of an expandable liner system Using specialty chemicals to sustain the downhole extreme environment throughout the life of the well Using computer-aided simulators to achieve excellent zonal isolation across and over the zones of interest

An expansive additive was used to enhance hydraulic isolation of the zones of interest because it helps the cement expand in an HP/HT environment and fill any microchannels. A 3D displacement fluid dynamics simulator played an important role in determining efficient placement of cement. This helps pinpoint potential fluid channeling caused by reduced standoff, poor displacement efficiency, or abnormal in-hole geometries.

Specialized additives were introduced when designing spacers to modify their parameters to withstand downhole HP/HT conditions, which generated the necessary friction pressure under a low pump rate to achieve rheological hierarchy, and eliminate compatibility problems with all drilling fluids. The successful design and cementation of more than 20 HP/HT wells was executed, including the deepest well in the operator's history throughout the previous 10 years.
Realising Lost Well Productivity via Wellbore Implosion
Authors: Rivas Mora Cenobio , Azman Muhamad Syazwan , Jumaat Mohd Shafie , Al Busaidy Adil
Published: November 2020

Perforating an existing producer with a completion in place would typically be limited in terms of gun size and perforation cleanup ability, hence affecting the well performance. This paper is a case study of a through-tubing additional perforating job, its performance analysis, and finally the implementation of a wellbore implosion technique for perforation tunnels cleanup. Job design and the well performance analysis are also presented.

The zone selected for the initial additional perforation was analyzed and a gun system simulation was performed. After the initial perforating job, surface and downhole surveillance data were collected for perforation performance analysis. Based on this analysis, a wellbore implosion technique was selected for perforation tunnels cleanup to enhance their productivity. Several wellbore implosion job simulations were performed based on various design scenarios. The optimal design was selected and executed successfully. Postjob well performance was then analyzed and compared with earlier performance. Although this implosion technique cannot improve or alter the reservoir rock deliverability, its ability to perform perforation cleanup is expected to be evident from the well performance analysis.

Analysis of the well performance after initial perforations showed a lower productivity index (PI), which was expected considering that the perforating job was conducted through-tubing while the completion was in place. The subsequent well implosion technique was executed successfully, and after that operation, the PI of the well improved, indicating the success of the technique to clean the perforation tunnels.

Because many wells suffer from improper perforation cleanup, this case study provides an important example for such wells, whether old or new, to replicate and instantly enhance their productivity. This technique can also be implemented in injector wells to enhance their injectivity.
Integrated Sub-Surface and Surface Modelling for Gas Field Planning and Refinery Feedstock Evaluation
Authors: Wong Siong Ming , Wan Hashim Wan Mahsuri , M. Norpiah Rohaizad , A. Samat Ida Nordiana , Ahmed Shata Karem , Hajizadeh Mubarak Alireza , Shridhar Kulkarni Sukrut
Published: November 2020

A gas field is producing condensate with higher density than typical due to its higher napthene and aromatic content. Several future gas fields to be developed also have condensate with similar properties as this single field. The changes in future condensate properties and increasing amount of this atypical condensate will have major impact on existing refinery. It was necessary to create an integrated reservoir and surface facilities model and characterised fluids that can produce prediction of future feedstock including these aromatic condensate to the refinery. The model also produced the usual outputs such as gas quality and condensate quantities forecast over the life of the gas fields. A compositional network model consists of fluid modelling, reservoir, well, topside facilities and pipeline modelling through to the onshore terminal process modelling were developed in order to model the export gas and condensate network. Steady state models were developed and validated against operating condition for each system and an integrator was utilized in order to integrate the subsurface and process simulator together. For the fluid modelling, a compositional model suitable to produce assays was used instead of black oil model in order to predict the quality of both the gas and condensate delivered. The fluid models for fields with aromatic condensate used True Boiling Point (TBP) assay instead of a standard gas chromatograph composition from a Pressure, Volume and Temperature (PVT) laboratory test report. Several characterisation methods were developed and tested in order to obtain representative and relevant properties for refinery design. Other gas fields which had a more common chemical characteristic of paraffinic dominant condensate used standard characterisation method. The model enables representative prediction of condensate properties relevant for refinery design and evaluate options to develop the fields. The work will show that an integrated sub-surface-surface network model is essential in order to define the impact for a development throughout the value chain, specifically the changes to the products and downstream facilities. It will also provide an insight on the impact of fluid characterization methods of different types of condensate.
Evaluating the Implementation of Resident UAV Unmanned Aerial Vehicles into Oil and Gas Industrial Facilities and Construction Sites
Authors: Tcherniguin Nicolas , Mortier Régis , Tan Jaime HuiChoo
Published: November 2020

Use of robotics for subsea field developments became common practice during the last few decades. The development of unmanned aerial vehicles in conjunction with Internet of Things (IoT), Artificial Intelligence (AI), Cloud and Edge computing, the fast-evolving technologies, are opening new horizons for construction monitoring and supervision and facility inspection, maintenance and repair activities. This paper presents the results of TechnipFMC's latest investigations and tests to develop the use of advanced Unmanned Autonomous Systems (UAS's) to leverage the operational performance of some of its activities.
Long Term Internal Pressure Strength of Spoolable Reinforced Plastic Pipe and Comparison of Qualification Requirement Based on API Specification 15S and DNVGL ST F119
Authors: Putra I Wayan , Shahru Haslan Tengku Mohd , Tan Chin Chien , Badaruddin Mohd Fauzi , Mohd Ali Napiah Mohd Nazmi
Published: November 2020

Spoolable non-metallic pipe (NMP) is recently getting increased popularity as material for onshore and offshore pipeline. Even though the material is generally more expensive than conventional carbon steel, the total life cycle cost (TLCC) reduction is driven by reduction of pipeline installation cost (faster lay rate, less manpower/equipment) and operational cost (no chemical injection to combat corrosion, less operational pigging and inspection). The most common types of spoolable NMP currently used are reinforced thermoplastic pipe (RTP) and thermoplastic composite pipe (TCP). Non-metallic composite material strength capacity to withstand internal pressure is naturally decreasing over time. As new material, limited long-term performance data are currently available for these types of pipes. To obtain the long-term strength degradation properties of the material requires long duration and expensive qualification process, which burden the development of these types of pipes. PETRONAS has performed series of qualification test for both RTP and TCP in collaboration with several manufacturers. The qualification was initially based on API RP 15S (edition 2006) with few additional testing to suit offshore application due to the recommended practice initially only covers spoolable RTP and generally for onshore application. The latest edition as specification (API Spec 15S) covers more general types of spoolable plastic line pipes, including bonded (fully non-metallic reinforced plastic pipe) and unbonded type (with metallic reinforcement). Recently DNV also issued DNV RP F119 in 2015, a recommended practice for TCP, which subsequently upgraded to become specification, DNVGL ST F119 in 2018. Both reference specifications/standards above have different requirements on how to design and qualify the reinforced plastic pipe, however in general, both are based on long term test requirement. This paper provides requirement of long-term qualification of the pipe, based on API RP/Spec 15S and compare the result if it is qualified in accordance to DNVGL ST F119. Different result in term of long-term strength capacity is observed between these two standards. This paper also explains the pros and cons and provide feedback to both referenced specifications above, to further improve the specification requirements and reduce the burden of either manufacturer or end user in performing qualification for the pipe.
Investigation and Remediation of Electrical Integrity Issues in a Subsea Production Control System
Authors: Hammond Steven , Osman Hazreen
Published: November 2020

Objectives/Scope

Subsea production control systems are unique because they operate using electrical power and communications but in an underwater environment. Over time water ingress into an electrical distribution system can cause degradation of system electrical integrity. The objective of this paper is to show how these issues arise, to discuss methods for finding the location of integrity faults, and to give an example of how integrity faults can be located, what action can be taken to effect repairs, and how to mitigate against further recurrence.

Methods, Procedures, Process

Since it is not normally possible to determine the location of subsea electrical faults using visual methods alone, various other methods can be used such as Time Domain Reflectometry (TDR), Insulation Resistance (IR) measurements and branch isolations. In addition to the complexities of determining a fault location subsea, the situation is further complicated by difficulties in gaining access to potential subsea fault locations using divers or Remotely Operated Vehicles (ROVs). This paper will show the fault diagnosis procedures that were employed in determining the location of an electrical fault in a subsea production control system and will also discuss the issues and the procedures used in order to gain access to potential fault locations such as opening hatches and removing protection covers under water.

Results, Observations, Conclusions

The results of this work were the safe and successful location and remediation of the subsea electrical fault. The subsea production control system was restored to full operation and there were no HSE incidents during the work. The performance of the system continues to be monitored and analysed for signs of any new degradation.

Novel/Additive Information

This paper will present information that will be of benefit to others in the subsea industry who are facing electrical integrity issues in subsea production control systems. The benefits that can be gained are both in terms of testing strategies that can be followed and in potential new technologies that can be deployed.
A Central Luconia Case Study: Pitfall of Using Statistics without Geoscience Interpretation
Authors: Cheong Yow Lam
Published: November 2020

Hydrocarbon column height is one of the most important parameters that affects the volumetric calculation. Previous prospect volumetric calculations were done using statistics built from the existing database of column heights of hydrocarbon discoveries of deeply buried carbonate pinnacles in Central Luconia. A re-look of the discoveries revealed that not all of the data in the existing database are applicable for a given prospect due to the different geological settings. As it is a common practice to update the database from time to time, a refresh was done after new multi-PSC 3D seismic acquisition and interpretation was completed and more published well information from adjacent PSC's were made available. A more scientific approach was taken this time around; the effective sealing unit of the deeply buried pinnacles was compared against our prospect. All the deeply buried pinnacles in the statistics were effectively sealed by the clastic 5.8mya depositional sequence. The percentage of hydrocarbon fill for each buildup was plotted on the existing paleogeographic map of the overlaying sealing strata. Given sufficient charge, multiple factors remain that can negatively affect hydrocarbon accumulation in Luconia carbonate buildups. These include high aquifer overpressure, crestal faulting, and channels which can impinge on the reservoir and act as thief beds. Some channels may clearly be seen in the seismic, while some appear to be pinched-out, and others may be sub-seismic. In the area of carbonate build-ups that were used in the statistical database, lower percentage of hydrocarbon fill coincides with the presence of a regional channel complex, interpreted to act as theif zones. However for our prospect, within this overall channel complex, several large buildups seem to act as baffles or barriers to the channels, deflecting them away from our prospective carbonate build-up. Thus, by comparing with our prospect, we realized that the regional statistics might not always be applicable, depending on several geological variables. Our prospect has no thieving channel at top seal level and is further protected by the updip channel belt by another carbonate platform. We should not use statistics generated from discovery wells that are affected by the thief beds. Statistics are always favoured whenever we have little knowledge about a basin or subject. By showing how geoscience can drive the statistics, we will be reminded on how using it without interpretation may be misleading.
Cost Optimization at Design Stage by Implementing Barefoot Completion in Carbonate Reservoir
Authors: Ghazali Hasyimah , Bernard Caesar Sokatte , Zahri Fakhrul Radzi , Khairul Salleh Nur Sakinah , M. Safari Lai Harni Farihah , M. Khir Khairul Ezee , Tuah Joroji , Mohamed Tatmimiddin Alhasani , Kouni Karim
Published: November 2020

Most of carbonate wells in PETRONAS Carigali Operated blocks in Malaysia are completed with pre-drilled liner. Barefoot completion is a new approach that is planned to be implemented in this particular carbonate field. This paper aims to share on how selection of lower completion based on in-house carbonate lower completion guideline could optimize overall well cost.

The offset well in X field are all completed with pre-drilled liner. As an initiative to further optimize the well cost and delivering an economic field development plan, barefoot completion has been proposed as a completion strategy for the upcoming drilling campaign. Selection of this strategy has taken into account the wellbore stability during production, geochemical effect and critical drawdown, including unconfined compressive strength (UCS) based on the outcome of the geomechanical study.

The advantages of the approach are mainly in reducing open-hole length thus reducing the drilling cost, secondly is eliminating all the equipment requirement for lower completion thus reducing completion cost by 14% in X field. This shows that the guideline is effective in choosing the fit for purpose and safe lower completion strategy for carbonate. The work evolved from replication of best practices and lessons learnt from the developed fields in Central Luconia.

Complimentary to the existing in house completion selection guideline, the new guideline for carbonate lower completion and its implementation in this design has contributes by minimized risk uncertainty in developing carbonate reservoir to a controllable level, thus becoming reference for future similar development within PETRONAS.
Dual Function Chemicals in Resolving Emulsion and Water Clarification for EOR and Normal Emulsion Application
Authors: Halim Nor Hadhirah , Salleh Intan Khalida
Published: November 2020

Emulsion created by EOR chemical flooding is difficult to break due to the presence of alkali and surfactant tightly bound with the oil and water. Many compounds have been used as demulsifiers in breaking this tight emulsion. Dual Function Demulsifier (DFD) is a copolymer based demulsifier synthesized for demulsification of water-in-oil and oil-in-water emulsion. By providing essential functionality with strong dehydration and dewatering capabilities, it is effective to dehydrate the oil at the separation point whilst improving the water clarity.

DFD formulated for normal emulsion was piloted in Field B, Malaysia with encouraging results better than incumbent chemicals during 8 days field trial. For EOR emulsion, since there is no EOR application in Malaysia as yet, the DFD chemical was tested at dynamic condition using Multi-Functional Separator Flow Test. The flow test involves a continuous fluid flow from the pipeline into the mini separator simulated Field A separator temperature of 60°C and 15 minutes retention times using 40 Liters commingled crude from Field A and 60 Liters Produced Water containing the EOR chemicals.

DFD implemented for pilot in Sarawak offshore been able to resolve the normal emulsion within Field B separator temperature of 40°C and 4 hours of separator and flow lines retention times until crude oil terminal. At 25 ppm DFD 0815, the chemical was able to treat the emulsion to less than 1% and reduced the Basic sediment & Water (BS&W) to 0.43%. This certainly meet the BS&W specification of the saleable crude to be less than 0.5%. DFD also reduced the Oil in Water (OIW) to 155 ppm from 900 ppm which the reduction is about 82%. For EOR induced emulsion study, 50 ppm of DFD A13 has proved to work successfully in the dynamic condition testing using Mini Separator Flow Test. The emulsion has been resolved from 30% to 1% and the Oil in Water was reduced from 239 ppm to 49 ppm. These two cases have proven the dual function capability of this chemical which is unique from the commercial demulsifier.
Steel Tube Flying Lead Accumulated Plastic Strain Calculation
Authors: Bansal Amandeep , Batrony Mimi , Prakash Sunil , Anand Vikash
Published: November 2020

This paper documents a study to determine the accumulated plastic strain (APS) developed in steel tube flying leads (STFLs) assembled in loose-tube bundle configurations throughout their product lifecycle. This lifecycle consists of the various processes involved in the manufacturing of STFLs,including initial tube manufacturing, load-out after tube manufacturing, subsequent shipping, potential over-sheathing, delivery and unspooling for flying lead manufacturing, pressure testing, and the flying lead final load-out. Throughout the product lifecycle, the steel tube undergoes the repetitive processoperations of coiling, uncoiling, straightening, and pressurizing. These operations cause plastic strains to be developed in the tube, which means that the tube experienceshardening,and its mechanical properties are modified throughout its lifecycle. Therefore, it is necessary to account for this accumulation of plastic strain and to ensure that the total APS at the end of the lifecycle is below APS acceptance criteria.

A kinematic hardening material model was used to simulate the nonlinear material behavior. The APS in super duplex tubing within loose STFLs for any number of bend cycles was calculated. The total strain developed in the tubing was calculated on outer fibers in a wrapped configuration. With the total strain (ε) known, the corresponding true stress (σ) can be determined using the tubing material’s true stress-true strain curve. The elastic strain is calculated by dividing the true stress by the tube’s elastic modulus (E). The plastic strain can then be calculated by subtracting the elastic strain from the total strain. Accumulation of plastic strain due to tubing bent about a radius and applied with internal pressure was difficult to obtain, as there were no analytical equations available to calculate it. To approximate the plastic strain developed due to pressure applied, a finite element analysis (FEA) study was completedfor plastic strain variation with respect to different bend radii. Results of the APS calculation were verified with the FEA results for each of the product lifecycle processes. Using this kinematic material model, the difference between the FEA and the APS calculation was within 3.5%.
Drilling, Geo-Steering and Reservoir Characterization Solution in Deep Carbonate Laterals
Authors: Al Muqarshi Moosa Masoud , Beche Amina , Vasquez Bautista Ramiro Oswaldo , Ovezov Murad , Delavari Kamran , Noor Marghub Nabi
Published: November 2020

In a heterogeneous and fractured carbonate hard rock with UCS more than 15K psi, drilling a highly deviated well is a challenging process that would require real time monitoring, using best in class MWD and LWD technology. A client in South Oman is in a development phase of drilling 1000m lateral wells to maximize the exposure for optimum oil production.

The carbonate formation is characterized as heterogeneous vuggy dolomites with a network of regional fractures acting as the secondary source of porosity. The thin reservoir is isolated by thick layer or Anhydrites above and Shale formation below & managing geological uncertainties in real time is going to be the differentiator between success and failure. A combination of hybrid RSS to manage aggressive steering requirements along with distance to boundary imaging LWD tool to identify the bed boundaries & keep the well on course along with an azimuthal resistivity ultra-high imaging for reservoir characterization were deployed to overcome these challenges.

The proposed solution was put into challenge on well X for drilling 5.87in lateral section and 1000 m lateral was successfully drilled. Hybrid RSS with aggressive bend setting helped in geo-steering the well and managed to achieve directional objectives to chase the geological uncertainties. After confirming the formation dip the well was steered 6to 7ft from the bottom conductive layer with the help of distance to boundary resistivity imaging tool. Real-Time High-Definitionazimuthalresistivity images helped in petrophysical interpretation and formation evaluation. Later, better density memory imaging data helped in evaluation of full borehole structural features and detailed fracture characterization. Hybrid rotary steerable systems along with best in class LWD tools provide purpose to fit solution to drill and geo-steered well in the optimum place. Success of this combination has eliminated the risk of exiting the reservoir leading to costly sidetrack scenario. At the same time, it has also helped the client to optimize production by geo-steering the well in the high porosity sweet spot and by Identifying regional fractures.

Developing deep, hard and heterogeneous carbonate reservoirs is a complex and challenging affair and a conventional approach to overcome these challenges is not always producing the best results. A novel approach with the help of advanced rotary steerable and logging while drilling tools helped client in developing the field by minimizing the risks and maximizing the best reservoir exposure characterized, as the well are drilled.
Machine-Learning Guided Fracture Density Seismic Inversion : A New Approach in Fractured Basement Characterisation
Authors: Shamsuddin Annur Asma , Purnomo Eko Widi , Ghosh Deva Prasad
Published: November 2020

The main objective of this study is to map potential fracture density based on a new integrated study of a fractured basement area. A machine learning algorithm of well log fracture density - borehole image log (BHI) guided seismic inversion was performed. Structural seismic attributes which are including maximum and minimum curvature, coherence, ant tracking, neural network, and principal component analysis were used to validate this potential fracture density map. All fractures were interpreted after image from BHI was processed. These fractures were quantified as fracture density log (FDL) based on weight density fractures per meter. The inversion was performed based on the enhanced of Extended Elastic Impedance (EEI) with the FDL. It was done by defining the training data set relating the FDL and its associate EEI. The resolution of inversion is increased by conducting stochastic inversion to generate high frequency relative EEI. The absolute value EEI was obtained by adding the relative EEI with a low frequency model derived from the FDL. A study was conducted in the Field A of the Malay Basin, which is located in transtensional tectonic regimes with the domination of various rock types ranges from metasedimentary rocks to volcanic and igneous rock. The integrated study has been implemented to invert the potential fracture density of the fractured basement area. Based on the BHI analysis, the highest fracture density is defined as 1.3 fractures per meter. Inversion at the well location shows a high correlation and small error of the reconstructed fracture density (FDL). The analysis of cross section and the horizontal slice of inverted fracture density displays good fit with a fracture sensitive analysis, which is structural seismic attributes such as minimum and maximum curvature, coherence, ant tracking, principal component analysis, and neural network. This study provides a better fracture understanding as the resulted inverted fracture density is quantitative. It allows potential fracture density mapping by using geobody analysis through classification or cut off value. The novelty of the study is presented based on the potential to generate a 3D volume of well log calibrated fracture density by empowering the seismic elastic inversion with a sophisticated machine learning algorithm.
Planning for Success: Geomatics in Development Concept Select Phase
Authors: Endot Ernyza , Sim Peter , Ismail Suharti
Published: November 2020

Concept Select (Pre-FEED) is one of the critical and distinct phases in Upstream development projects. Concept Select phase comes before the finalisation of Field Development Plan (FDP). Objectives in this phase includes refreshing the value drivers and opportunity statement, refocus from identifying options to selecting concepts, identifying risks, maturing different operational philosophies in each technical area and for the integrated project, agree criteria on which decisions are to be made and develop tools to help the team focus on decisions (e.g., strategy table). All the objectives above are to narrow down the most possible concepts to be taken into considerations to produce oil and gas.

For a new offshore field development, key disciplines which was involved in the Concept Select phase are Subsurface, Wells, Front-End Engineering and Flowline/Pipelines Engineering. These disciplines will work together in order to deliver the best design which can yield the most optimized options which emphasise the safest and cost efficent with the target of fastest first oil/gas date for maximizing production.

Figure 1 shows a typical upstream project lifecycle. The first phase is after exploration discovery (or field acquisition), major issues are identified in an opportunity framing workshop. All the scenarios and issues are being brought in for evaluations. When downsizing concepts as portrayed in Gate 1, detail to few concepts are being made available. Hazard assessment are being performed and captured in a register which overlying major accidents and events in risk management. These two-phase shown in red box below are the Concept Select phase. The chosen concepts for the project are then being technically and economically evaluated in the Feasibility phase where the risks are being managed qualitatively. After that, comes the detail design and operations of the projects.
Harnessing Power of Technology for Flawless Execution of Marginal Field with Longest Lateral Carbonate Oil Rim in Malaysia
Authors: Runtuwene Michael , Michael Jeremiah , Maruthanuthoo Kumaren
Published: November 2020

What constitutes a marginal field varies greatly but it is certain that extended time periods of low oil prices only magnify the challenges in developing such fields as it can stir even the largest reservoirs to go from commercially viable to marginal. E field is a marginal development project that must contend with all these unique set of challenges. For many years the project struggled to achieve minimum thresholds for funding. To develop the field during a low oil price market represented a cost-opportunity whilst presenting a value challenge. It is an extremely challenging thin oil rim reservoir development, under a complex and heterogenous geological environment, involving six long-to-extended reach wells in a loss-prone karstified carbonate.

While the well planning and design built upon the Operator's considerable experience in carbonate and long reach drilling in the region, the campaign remained unique as the characteristic resided beyond the envelope of what had been accomplished before. The key distrincions were the much longer lateral length and the combined scope to target the thin oil rim in addition to the gas cap, which was the first-time application in this area. This is where technology played a vital part, as an enabler for delivering a complex project in a competitive manner.

This paper briefly describes the planning stage of the campaign to ensure that the project was competitively scoped and delivered a fit-for-purpose solution, with focus on the technology implementation to address specific drilling challenges. Furthermore, it explains how a robust front-end loading, replication, and strong collaboration were key to making developable what was previously uneconomic.
Well-Test Deconvolution Analysis of Gas Condensate Layered Reservoirs
Authors: Geravand Roya , Foroozesh Jalal , Nakhaee Ali , Abbasi Mojgan
Published: November 2020

Well testing, especially in offshore platforms, is quite expensive and traditional well-test analysis are not capable of fully capture the boundary dominated effects from short-time, constant-rate pressure buildups. The complexity of the well test behavior of gas condensate layered reservoirs causes the pressure data from drawdown flow periods become too noisy, which makes it extremely difficult to obtain accurate results using conventional well-test analysis. Hence, only build-up periods with unit flowrate are used in pressure transient analysis. However, the duration of build-up tests are hardly long enough to capture the boundary dominated effects / faults. Luckily, deconvolution approach has overcome this issue through converting the whole test periods including multiple drawdown and build-up periods into a constant-rate pressure drawdown. This work aims to apply the variable-rate deconvolution approach to analyze a series of short well-test data obtained from the single-layer drill stem tests (DSTs) carried out in an offshore gas condensate layered reservoir. The results demonstrated that compared to the pressure derivative method, the deconvolution analysis provided us with more range of data and increased the radius of investigation, which enabled us to identify the boundary dominated flow regimes such as leaky/partially communicating fault, sealing fault / no flow boundary, as well as constant pressure boundary at late-times. In addition, we evaluated the performance of the treatment job conducted during some DSTs, in the same reservoir.
Development of an Assessment Procedure to Predict Local Buckling Behavior Using Probabilistic Method with Finite Element Techniques for Reeled Pipeline with Additional Features
Authors: Abdullah Sheralia Ufairah , Ngai Tommy
Published: November 2020

Reel-lay method is a fast, cost effective method of pipelaying for pipelines with an ideal diameter between 4" to 16". Reel-lay pipelines are plastically deformed to conform to the radius of the reel drum that is fixed on the vessel. The reeling operation requires a high level of engineering to ensure the pipe does not buckle nor have a high lift off on the reel or aligner during spooling and installation. This comes at the design level where the selection of wall thickness is driven by the requirements to avoid local buckling. The requirements imposed are taken from DNVGL-ST-F101 [1], a submarine pipeline systems’ standard that is widely used in the oil and gas industry in designing pipelines. However, the requirements are based on displacement control check equations with some fixed safety factors. The safety factor is designed to take into account the presence of mismatches in bending moment between pipeline joints and its system effect.

A refined assessment procedure for pipeline reeling have been developed within the industry and has been published due to the discrepancy in the minimum reelable wall thickness [[2]]. Finite element models are developed and analyzed to create a failure boundary between safe and unsafe regions using different combinations of mismatches. The reliability index is then determined using the failure boundary, which is then used to calculate the probability of failure. This method normally requires multiple FEA to create the failure boundary which can be very time consuming.

This paper outlines the probabilistic method which is an improvement to the past approach, where it firstly defines the probability of failure in calculating the mismatch. Finite element model is then developed and analyzed using finite element software Abaqus FEA [3] to verify that the level of safety associated with the method is met. The reeling studies carried out in this paper has shown that the probabilistic method requires far less analyses to be done and is able to analyze pipeline with features while still meeting DNVGL's requirement. This method also allows pipelines with different geometrical and mechanical properties such as transition design and bulkhead to be analyzed. This method normally requires only a single FEA.
Saturated Gas Hydrate Drilling Hazard Prediction Using Controlled Source Electromagnetic Method
Authors: Tharimela Raghava , Baillie Graeme
Published: November 2020

Natural gas hydrates (NGH) are a significant hazard for drilling with direct implication on drilling and operation costs. Most often, the evaluation of the presence of gas hydrates is performed using seismic evidence such as bottom simulating reflector (BSR) and seabed indications such as seepages and pockmarks. Uncertainty in prediction of their presence is still large as the seismic signature is similar for both low and high saturated gas/hydrate accumulations, leading to instances where there is a BSR, but no significant amount of hydrates encountered when drilled. And conversely, where no BSR can be seen yet thick hydrate plugs were encountered while drilling. Seepages and pockmarks on the other hand indicate the presence of an active hydrocarbon system in the subsurface but does not indicate the extent/volume of the hydrocarbons that are the source of this gas migration. The only other alternative to confirm gas hydrate presence would be logging and direct core sampling. These methods, though reliable, can only provide point measurements and does not indicate the lateral distribution of hydrates. Adding more such point measurements would make the drilling operation more expensive.

Electrical resistivity has a more reliable relation with saturation of hydrocarbons (Archie, 1940). The controlled source electromagnetic (CSEM) method that maps bulk subsurface resistivity remotely can be used as an efficient and cost-effective alternative to detect and determine the lateral extent of saturated hydrate accumulations. Integration of the resistivity volume from the 3D CSEM dataset with seismic and other geophysical information will enable one to distinguish between low saturated and saturated hydrate bearing sediments, significantly reducing uncertainty in hydrate prediction. This would help in better selection of subsurface drill location and minimizing the need for additional logging and direct core sampling priori to drilling.

In this paper we discuss about the CSEM method specific to hydrate mapping along with case examples showing how the inclusion of CSEM in interpretation improves the understanding of the hydrate system in order to make a better hazard prediction.
First Successful Deployment of Improved Flowback System for a Deepwater Wireline Micro-frac Test
Authors: Zhang Tingting , Abd Rahim Mohd Helmi , Kim Igor , Ting Angelina , Moronkeji Dee , Hardikar Nikhil Prakash , Funes Daniel A
Published: November 2020

In a typical waterflooding philosophy, water injection is often constrained by the in-situ stress of the overlying geological seal, in order to avoid out-of-zone injection and ensure reservoir fluid containment. Direct measurement of in-situ stress from wireline Micro-frac testing is insightful as compared to a conventional leak-off test (LOT) conducted at the casing shoe, due to the smaller volume and lower injection rate used. Unlike the conventional LOT, Micro-frac tests can be performed at discrete and multiple intervals in one wireline run, away from the casing shoe.

In 2017, Shell Malaysia Exploration and Production (SMEP) conducted the first wireline Micro-frac test in a caprock shale, in a deepwater injector well, offshore Malaysia. The job was successfully executed with an improved design of the flowback mechanism, using a combination of a small volume pump and a drawdown chamber. While the small volume pump provided the advantage of accurate volume/rate measurement, the modified drawdown chamber setup provided a constant flow rate, to aid in a more accurate fracture closure pressure interpretation. The improved setup was the first successful application of this device for the purpose of Micro-frac. Both the methodologies showed good and comparable results, thereby adding higher confidence to the interpretation of fracture closure pressure.

A workflow has been developed to ensure successful execution of the logging job. Pre-job modeling was completed using offset well data to derive formation mechanical properties as well as in-situ stress profile. This information was then used to characterize formation breakdown pressure, selection of test intervals and optimum straddle packer positioning. Learnings from the test conducted at the first depth station were used to optimize the number of cycles for the subsequent stations. In addition, an operational decision tree was developed to assess the number of cycles required and contingency criteria.

The paper presents an improved flowback design using the drawdown chamber as well as the operational challenges in a deepwater environment. The methodology provided a reliable estimate of fracture closure pressure in a non-permeable formation. Results have been used to update the water injection envelope, in an effort to avoid undesired out-of-zone injection.
Characteristic of Tropical Storm Pabuk Based on Field Measurement
Authors: Shamsudin Mohd Azim , Latheef Mohamed , Abdullah Mohd Nasir , A. Rahman Azam , Rashid Rosedianty Marsilla
Published: November 2020

Tropical Storm (TS) Pabuk which occurred in South China Sea during the Northwest Monsoon season of 2018-2019 is a rare storm event. Even though it was originally considered weak, it was able to enter and remains active in the 5 degree latitude of weak Coriolis zone, then track further north, make a short land crossing before ending in Andaman Sea. At its early formation, it was in tune with the incoming monsoon's cold surge which perfectly align with the storm outer circulation that enable it to amplify like a little push that spun a spin-top going faster. The waves measured during this storm far exceeds the waves conditions associated with a 100 year Return Period (RP). In addition to being larger, they are also much steeper than the waves contained in the SEAFINE hindcast database spanning back over the past 59 years. However, interestingly, correlating the generated waves with the local wind field showed that at the locations where the data originated, the peaks in wave conditions are contributed by swell.