bluuebunny/crossref_metadata_2025 huggingface dataset:
Water Intake Riser – Hydrodynamic Damping Modelling for Fatigue Assessment
Authors: Minguez Matthieu , Zhao Wenhua , Gao Zhenguo , Efthymiou Mike
Published: November 2020

The Prelude experience has underlined the potential strong impact of both the hydrodynamic damping and any potential superimposed current to properly assess the Water Intake Riser life time, refer to Minguez & al. (2020). This effect, resulting from the considered hydrodynamic modelling, remains qualitatively suggested within the different riser design standards (e.g. either the DNV-GL-RP-C205 2017 or the ISO-13628-7 and ISO 19902 2007) but no quantitative recommendations agree on the way to properly address such a topic. The proposed numerical developments underlined the gap between the different Best Practices and the impact in terms of fatigue assessment. The different recommended damping models are considered and experienced to assess the quantitative impact on fatigue assessment.

Based on this critical review, a large-scale model test focusing on a simple riser response is proposed to position the different existing hydrodynamic models. This has been done by imposing forced motions to a rigid cylinder mounted under a spring system. The system, free to move, is plunged within a basin in which different current speed and direction are imposed. Both loads and dynamic responses of the model have been monitored.

The numerical developments proposed in the frame of this research suggest both any damping and drag empirical formulation to properly address such fatigue concern from engineering point of view.

This work finally recommends that caution be exercised when the DNV guidelines and the International Standard are followed due to the contradiction of the recommendations with the experimental evidences reported in this study.
A New Insight into Friction Reducer Evaluation for Slickwater Unconventional Fracturing
Authors: Karadkar Prasad , Alabdrabalnabi Mohammed , Bataweel Mohammed
Published: November 2020

Slickwater fracturing has increased over the past couple of decades in the development of shale and tight formations. Friction reducer is the main component of slickwater, which reduces drag in the tubular. For successful and economical slickwater hybrid fracturing treatment, selection and optimization of friction reducers play a key role. This paper presents a new insight into optimizing friction reducer using helical coiled flow loop at high-pressure, high-temperature (HPHT) conditions.

Usually, friction pressure is estimated by pumping slickwater fracturing fluid through a straight tube and measuring differential pressure across the tube. This required pilot-scale laboratory setup and testing at HPHT bit challenging. In this paper, small sized equipment, helical coiled flow loop was utilized to estimate friction pressure of slickwater fracturing fluid. Friction reducers can be rigorously tested for degradation because secondary flow resulting from centrifugal forces can be caused by the coil curvature. Correlations for Darcy friction factor as a function of Reynolds number has been developed for helical coiled fluid loop in both laminar and turbulent flow regime.

The present study evaluates different friction reducers in ¼ in. ID smooth helical coiled flow loop. The correlations developed for Darcy friction factor was well validated for water with data available from literature. Polyacrylamide based friction reducers with different concentration were used in this study. The friction pressure, with and without friction reducers, was compared at different flow rates. Percent drag reduction at different polymer concentration was also evalauted using helical coild flow loop. Thermal degradation of friction reducers was evaluated by varying temperature up to 300°F.

New correlations to measure friction losses using helical coiled flow regimes are presented in this paper. Reduced drag reduction due to secondary flow resulting from centrifugal forces in helical coil can judge friction reducer more thoroughly then conventionally used straight tube flow loop.
Digital Concept and Machine Learning for Cost Estimation of Oil and Gas Development
Authors: Muhammad Abdull Jamil Kamilah , Lebang Yusuf Theo , Farid Mohd Faidsal
Published: November 2020

The aspiration of cost estimation for oil and gas development is to deliver sharper, accurate yet competitive estimates. Accuracy of cost estimation highly depends on certain attributes such as scope definition and project schedule. In addition to that, uncertainties and pace of change in oil and gas market such as fluctuation of oil price and supply chain, trade wars and geopolitical issues, are external challenges that will affect the accuracy of cost estimates.

Strong database is required to predict the cost based on historical and future market rates. One of the solutions is using probabilistic model to have range of possible outcome for an estimate. Recently, computing techniques such as data analytics and machine learning for quick and accurate cost estimation has been seen as an alternative to overcome the uncertainty of input parameters. Digital Concept such as Machine Learning leverages on statistical approach, nonlinear equations and genetic algorithm programming is used to model the cost. The metrics are used to supply meaningful and timely management information regarding techniques and process. Cost Estimate Relationship (CER) is established to model the correlation against the technical deliverables at any stage gate process to support the target metrics.

This paper presents an alternative method to estimate the cost which is applied to offshore platforms through machine learning as it compares the performance of two different machine learning algorithms: Support Vector Regression (SVR) and Artificial Neural Network (ANN). A comparison between SVR and ANN method is set to show the fundamental algorithm of each and evaluate the comparison between them to show the advantages and limitations. Performance of the algorithm is measured by the RMSE value, which in this case the predicted platform cost by the model against the actual cost observed. The results show that despite the limitation in the amount of data, the algorithms exhibit high performance with both SVR recording average error or deviation of platform cost of RM 27 million, which is the lowest RMSE value, and ANN recording RM 36 million deviation. In addition to that, both algorithms used in predicting the platform cost have returned highly accurate results when comparing them to actual platform cost generated using conventional method.
New Analytical Approach for Predicting Surge/Swab Pressure Gradient Using Mud Clinging Effect and Frictional Pressure Losses: for Yield Power Law Fluid
Authors: Krishna Shwetank , Ridha Syahrir , Vasant Pandian , Ilyas Suhaib Umer
Published: November 2020

Surge and swab pressure generated during pipe tripping operations tends to result in various wellbore stability and integrity problems. To monitor these problems, prediction of these differential pressure is required for the smooth functioning of drilling operations. An analytical predictive model is presented in this research for surge and swab pressure. This model is developed under steady-state condition for Yield Power Law fluid. A fluid filled wellbore with drill-pipe/casing is considered as two concentric cylindrical pipes for developing this model. In this concentrical cylinder inner pipe is moving at certain velocity and the outer pipe is stationary. Due to movement of inner pipe, drilling fluid will start displacing in annulus and results in pressure surges. A predictive model is developed by analytically combining the frictional pressure loss and mud clinging effect to forecast this pressure surge due to couette fluid flow phenomena in wellbore. The newly developed model (NDM) is validated with two existing analytical models and reported experimental data that are available in the published literature. A parametric analysis is carried out to identify the effect of various parameters on pressure differential. This research suggests that with the increase in pipe tripping velocity, surge pressure also tends to increase because of high viscous drag of fluid. It is also found that the increase in diameter ratio surge pressure also tends to increase due to large shearing effect between pipe wall and fluid. In conclusion this model is predicting the suitable range of tripping speed and diameter ratio under tolerable wellbore pore and fracture pressure to assure downhole wellbeing. Unlike most of the existing model, NDM requires less numerical analysis which make it easier to understand and apply in real case situation. The model considers mud clinging effect for precise prediction of surge/swab pressure gradient.
Recent Developments in Surfactant Flooding for Carbonate Reservoirs Under Harsh Conditions
Authors: Adila Ahmed S. , Al-Shalabi Emad W. , AlAmeri Waleed
Published: November 2020

Surfactant flooding is one of the most promising chemical enhanced oil recovery techniques. However, this technique has been mainly applied in sandstone rocks with limited applications in carbonates. In this study, we present a comprehensive review on surfactant flooding for carbonates under harsh conditions of high temperature and high salinity. This review starts with highlighting the underlying mechanisms of surfactant flooding. Surfactant types, screening studies, and surfactant retention are then discussed. Laboratory and modeling works as well as field applications are also summarized. In addition, other surfactant applications such as surfactant-polymer, alkaline-surfactant-polymer, low salinity-surfactant as well as foams are presented. At the end of this paper, a list of recommendations and conclusions for better implementation of surfactants flooding are also discussed. This paper gives more insight into surfactant flooding aspects and its different applications in the petroleum industry. The literature review shows that a field-scale application of surfactant flooding in carbonates under high temperature and high salinity conditions is feasible. Also, this paper is considered as a guide for implementing potential projects on surfactant flooding in carbonates under harsh conditions.
A Different Approach to Offloading a Newly Drilled Deviated Well
Authors: Rehman Abid Ur , Abdelbary Marwan
Published: November 2020

As the industry rebounds from recent pricing challenges, operators are searching for methods during each stage of their well—from drilling to production—to make the field more economical without compromising safety, health and quality. This paper describes a different method for offloading a newly drilled well.

In 2017, a well drilled in north Iraq targeted five productive zones. This directional well had a good potential to flow from upper zones which were producing around 3,000 BPD cumulative production. To get production from the upper four zones, conventional coiled tubing (CT) was utilized, and the well started to flow after lifting the drilling fluids. After testing the upper zones, the operator planned to evaluate the lower zone for the production. The well completion had sliding sleeve doors (SSD) and was installed for every zone separately. This well used a jet pump for offloading fluids from the last zone.

The upper four zones were plugged using the SSD, so only the last zone was open for flow. A jet pump was designed using jet evaluation and modelling software (JEMS). The design was based on the optimum size of the nozzle and throat selected for the lowest zone. A downhole jet pump was modified, based on the existing SSD, and installed in the well using slickline. High-pressure power fluid was injected into the well from the annulus and returns were taken from the tubing. The well was successfully offloaded using the jet pump. The well was then tested for production using the same jet pump system, which resulted in around 1,300 BPD production. Jet pump systems require critical observation and proper understanding of the system for this kind of application.

The well was economically offloaded using a jet pump system. This method saved a significant amount of time and money for the operator. Additionally, the jet pump system can be easily installed, designed and modified as per well and completion specifications. The nozzle throat combination can be changed on-site, depending on production results. The installation and operation procedure will be explained in detail for a comprehensive understanding of the system.
Well Condition Diagnosis of Sucker-Rod Pumping Wells Based on the Machine Learning of Electrical Power Curves in the Context of IoT
Authors: Wang Cai , Xiong Chunming , Zhao Hanjun , Zhao Ruidong , Shi Junfeng , Zhang Jianjun , Zhang Xishun , Huang Hongxing , Chen Shiwen , Peng Yi , Sun Yizhen
Published: November 2020

Sucker-rod pumping wells are the most widely used producing wells in China. 94% of the 200,000 oil wells in CNPC are sucker-rod pumping wells. It is urgent to reduce the cost of every single well based on the well diagnosis and optimization methods under the background of low oil price and the IoT. Rich working experience of field engineers could help them diagnose some conspicuous abnormal well conditions by electrical power curves easily, but the scientific diagnosis methods have still not be established, and the potential of electrical power curves of the producing well is far from being fully tapped.

The aim of this work is to diagnose the working condition of the sucker-rod pumping wells both on and under the ground based on the data from electrical power curves by machine learning. The methods shaped by the learning of the electrical power curves from nearly 600 wells mainly separate into 3 steps. The first is the diagnosis of conspicuous abnormal well conditions such as motor belt burning, motor belt slippage, two phase electrics, upper rod break, lower rod break et al. The prediction experience was obtained from the statistical learning of the mean and variance values after we equally split the 600 power curve values into 10 sub-groups. The second is the diagnosis of complex abnormal well conditions such as abnormal mechanical sound, slight tube leak, severe tube leak, pump stuck et al based on the combination of statistics and template vs diagnosed sample analysis. The third is the diagnosis of pumping conditions characterized by the remarkable prediction ability via deep learning. A surface well condition database was established and the corresponding electrical power curves were marked in real time. Based on the CNN technology, the model could recognize different pump working conditions such as insufficient liquid, gas influence, traveling valve leak, standing valve leak et al very well.

The work has been applied in the oil fields of Jilin and Daqing. The method has been tested on nearly thousand hundreds of producing well utilizing sucker rod pumping system. The model demonstrates very high accuracy with almost 90% similarity to the result diagnosed by corresponding pump dynamometers for large sample and 94% of abnormal well working conditions for small sample. What’s more, the work would reduce millions of investment on the sensors, equipment and manpower for the management of producing wells in CNPC each year in the context of industrial IoT.
Countercurrent Flow of Heat in Tubing and Annulus System: Jet Pump
Authors: Jang Minsoo , Hasan A. Rashid
Published: November 2020

Shale fields are currently over-reliant on electric submersible pumps (ESPs) in the early stage of artificial lift. However, harsh well conditions such as sandy and/or excessive gaseous flow increase the operational and capex for ESPs. Jet pumps are reliable and cost-effective alternative options for delivering significant savings and its dominance on the market is increasing. Current studies on jet pumps are mainly focused on the design parameters for maximizing performance of jet pumps. However, there have been very few investigations on predicting temperature profiles in the wellbore when with a jet pump.

In this paper, we present analytic models to compute temperature profiles in the tubing and annulus simultaneously throughout the wellbore. Our results illustrate that the temperature profiles in both conduits are nonlinear, and the difference between the two temperatures are not significant, especially near bottom-hole depth. Fluid temperature influences its viscosity, and hence, production operations. Utilizing the proposed model, we investigate the viscosity variation along the depth of the wellbore for better operational design with jet pumps. Generally, viscosity variation with temperature gets larger as the hydrocarbon has more heavier components, therefore, temperature prediction is very important in wells producing heavy oil.

Sensitivity studies have been conducted regarding the impact of operating parameters such as injection fluid temperature and flow rate on fluid temperatures. Injection temperature affects the annulus temperature profile in the swallow depth, leading to a distinctive change of the frictional pressure loss. In contrast, injection rate has less influence on temperature profiles, although of course, higher fluid velocity in the annulus cause greater frictional loss. According to the results, hotter and relatively small flow rate leads to lesser cost by reducing the frictional pressure drop during the operation.
An Innovative Flexible Pipe Annulus Monitoring System to Cover a Wide Range of Riser Applications
Authors: Raman Venkatalakshmi , Delcroix Olivier , Protasio Marcelo , Wasserman Francis , Albuquerque Victor , Turatti Augusto , Carvalho Claudio , Santos Renato
Published: November 2020

Annulus condition is a key information to follow up integrity of flexible risers in service. Traditional ways to measure water level in annulus are performing offshore inspection or monitoring with "passive" systems. This paper presents ISAGM (Instrumented System for Annulus Gas Monitoring) -an innovative "active" monitoring solution that enables permanent surveillance of this important informationwith the particularity of covering a wider range of riser applications thanks to a deep understanding of the kinetic behavior of the annulus with regards to pressure and gas flow.

The system is autonomous, capable ofmonitoring several risers in parallel and based on the injection of nitrogen at low pressure (below 1barg). As it is not relying on the gas diffusion process from the riser, it allows a more accurate and reliable data interpretation compared to the traditional passive way.

First of all, ISAGM description and principle are introduced elaborating on the two first world commercial applications, including one for a Malaysian field. Then, the results of tests on a reference bench rig and flexible pipe are presented. Finally, the challenge of performing annulus free volume measurement of riser interconnected annuli with high diffusion rate is presented through test and simulation results.
An Environmentally Friendly Method for Treating Acidizing Flowback Fluid in Carbonates Reservoir
Authors: Gao Jichao , Yang Shuhui , Yang Guowei , Shao Shangqi
Published: November 2020

Flow back fluid during matrix acidizing in carbonates reservoir has the characteristics of complex composition, variable physical and chemical properties, high content of crude oil and suspended solids. If discharged directly to the ground, it will cause serious environmental pollution and waste resource. A novel and environmentally friendly treatment method to solve this problem has been developed by optimizing surface flow back process, selecting chemicals, modifying filter types and equipment structure. The overall treatment strategy is to separate oil, gas, water and solid phase, inject dehydrated crude oil into pipeline, ignite gas, discharge water after meeting the requirements of industrial wastewater discharge standard, and treat solid phase harmlessly. Some problems such as emulsification, foam fluid and organic scale have been solved by optimizing acid recipe and adopting new chemicals. This novel technique successfully solved the environmental pollution problem and has high economic benefits.
Utilisation of Front End Loading Planning in Technology Readiness Level 5 TRL 5 for Foam Assisted Water Alternating Gas FAWAG and Polymer EOR Pilot
Authors: Hanafiah Norshariza , Chai Ching Hsia Ivy , M Yusof M Faiz , Abu Bakar M Azuan , M Sahak M Zakwan , Shaharom Shaharil Mazri , A Salam Irzie Hani
Published: November 2020

This paper discusses on planning and integration works of two Enhanced Oil Recovery (EOR) pilot projects (Foam Assisted Water Alternating Gas (FAWAG) and Polymer Injectivity test) via utilization of front end loading in Technology Readiness Level 5 (TRL 5) starting from Stage Gate 1 to execution. This pilot is a single well huff and puff pilot injection is to proof the two chemicals performances concept at near wellbore area in order to meet Technology objectives and maturation. The planning covers pilot injection schemes, injection facilities, chemical preparations and pilot test’s surveillance and monitoring program. In Stage Gate 1, chemical screening and feasibility studies were conducted whereas in Stage Gate 2, three concepts identified; which are, pilot on accommodation work barge (AWB), jack-up barge or ‘on platform’ concept with only one being selected for Front End Engineering Design (FEED) in Stage Gate 3. FEED study includes design for chemical injection, volumes and flowback system, offshore logistic selection as well as pilot surveillance. Since key drivers of this EOR pilot project is on cost, consideration on fit for purpose design and procurement strategy is crucial in ensuring data to be collected for pilot. Stage Gate 1 result is the invention of chemical formulation via the screening process with RND criteria achieved for the intended fields. Stage Gate 2 has resulted pilot concept of single well injection with facilities on platform. In Stage Gate 3, FEED study has resulted chemical injection process and flow back design. The study includes chemicals dispersion analysis and chemical blending upscaling process, based on lab scale data. Pilot injection test scheme workflow was developed to cover any uncertainties risk during operation. In Stage Gate 3, the planning processes were enhanced with value engineering study, risk assessment, technical reviews such as Hazard and Operability Study (HAZOP), Hazard Identification (HAZID), 3D model reviews, etc. In execution stage, technology providers and vendors for offshore logistics, surveillance monitoring and data logging, polymer mixing systems and EOR produced water treatment are among the vendors being engaged and considered to assist pilot operation. In conclusion, a thorough project planning is crucial for any EOR pilot project in order for the pilot to be operated successfully. This paper will contribute additional information to the EOR application specifically in Pilot stage to fulfill the Technology readiness level before being fully applied to the oil field. By sharing this EOR Pilot planning and know-how, technology professionals may be able to plan their project at highest value functions and getting optimum pilot design while successfully meeting their technology objectives and mitigating the uncertainties of the Technology.
Rigid Riser System: Alternative System for Coiled Tubing Rig Up on Spar
Authors: Raman Intiran , Selamat Kasim , Ghazali Muhammad Nabil , Blacklock Jon David , Chabot Luc , Ramnarine Ronald
Published: November 2020

A rigid riser system has been designed, built, and proven as an effective method to conduct coiled tubing operations on floating platforms. This system is installed above the Christmas tree which is supported by the platform's production riser and riser tensioner system. The rigid riser set up is a passive system that does not require the use of a crane or other mechanisms to support or hold up the coiled tubing injector head during operations. The axial load resulting from the weight of the injector head, coiled tubing, and snubbing/pulling forces on the pipe are carried in compression through the rigid riser to the tree and wellhead. The excess capacity of the top tensioner riser (TTR) supports these loads while allowing for relative motion due to tide, waves, and platform motion.

The rigid riser system uses a purpose-built, heavy-wall riser and a spider beam insert to resist buckling effects and bending moments. In practice, this system has improved the rig-up time and mitigated HSE issues as compared to the conventional motion-compensated lift frame method.

In addition, the system has a support frame that increases the rigidity of the injector head and accessories, resisting the excessive bending and torsional loads imparted by back tension and movements of the coiled tubing (CT) reel. An engineering study was performed to determine the dynamic loads and stresses for the various operational and contingency conditions on all the components of the rigid riser system and to confirm sufficient capacity of the TTR system.

The rigid riser system has proven to be a safe and cost-effective solution for coiled tubing operations from a floating platform compared to current motion-compensated jacking frame systems. Coiled tubing well interventions were executed using the rigid riser system, and the operational results have been convincing. The passive nature of the system provides an HSE advantage by eliminating mechanical or human intervention during operation.

This paper reviews the design aspects of the rigid riser system, its advantages over the current coil tubing intervention systems, and the operational results after executing the coiled tubing interventions.
Flow Assurance Implementation for a Successful Fast Track FLNG Relocation
Authors: Wan Hashim Wan Mahsuri , Azuhan Aimi Samihah , M Norpiah Rohaizad , Idrus Aishah , M Johar Juhaida
Published: November 2020

One of the advantages of a floating LNG (floating Liquified Natural Gas) plant compared to an onshore plant is its capability to relocate from one location to another. For better economic opportunity, an existing FLNG plant is relocated to a new offshore location, 450 km away. Several studies are conducted prior to commencement of the relocation. One of them is to evaluate flow assurance issues before, during reconnection to the new facility, commissioning, start-up and subsequent operations. These aspects are evaluated through steady state and transient simulations, in particular to identify major issues that may require additional equipment or significant operational changes to mitigate the consequences arising from conditions at the new location.

The main objective of flow assurance study at the initial project stage is to identify and specify Long Lead Items (LLI). Two of the LLI aspects that had to be finalised early are pipeline size and distance between the gas exporting platform and FLNG vessel to meet FLNG's feed gas arrival temperature specification. At design flowrate, it is observed that Joule-Thomson (J-T) cooling resulted in fluid temperature arriving at FLNG riser below ambient temperatures. Parametric studies are also performed for commissioning, black start-up and gas ramp-up, based on operational experience at the first location. Recommended optimum start-up sequence is successfully employed during commissioning and recorded data is found to be comparable with results from simulations. Flow assurance is one of the critical considerations to relocate an FLNG vessel and associated systems to a new location. This paper explains how the study was done and shares the start-up experience for industry's first operational FLNG.
Reservoir Characterization Supported by Rock Physics Diagnostics
Authors: Gelinsky Stephan
Published: November 2020

To be of practical use for reservoir characterization, rock physics models are often perceived as too complicated and as dependent on too many difficult-to-measure parameters. Here we demonstrate how careful calibration of a common and quite simple rock physics model can provide valuable insights into the reservoir and seal elastic properties as function of porosity, fluid and mineral properties, andnet-to-gross. The model canbe used for quantitative seismic interpretation of reservoirs with variable net-to-gross and porosity away from well control.

We show that the Hashin Shtrikman Upper Bound is useful to model the compressional and shear velocities of grain-supported clean sandstones as function of porosity, whereas matrix-supported claystone compressional velocities follow the concaveHashin Shtrikman Lower Bound. The corresponding shear velocity shale data plot similarly but for the Lower Bound to be useful to model shale shear velocities the clay-bound-water needs to be modeled with a small but finite shear stiffness. This update alsoimproves the shale compressional velocity model fit. The resulting unified compressional and shear Hashin Shtrikman model allows for the calibration of a sand-shale mixing model that can be used to interpret seismic-derived acoustic and shear impedances in terms of sand net-to-gross and porosity away from well control.
Enhanced Safety and Optimized Cost for Fire & Gas Detection System Design using Risk based Approach Methodology and Computerized 3–Dimenional Fire & Gas Mapping Software
Authors: Chua Kien Kek , Tan Fang Yee , NG Chien Han
Published: November 2020

Assessing the effectiveness of a fire and gas detector installation is critical in enhancing safety in oil & gas industrial environments, but currently there are limited software tool to effectively perform such function. Traditional methods of ascertaining fire and gas detector locations currently leverage on rules-of-thumb or estimates which would result in either over or under-engineering. Often, these guidelines were established without any proper validation of their effectiveness. An innovative methodology has been developed which coupled with simulation software called fire and gas mapping in determining placement of detector in systematic and effective ways meeting international safety standard.

Mapping studies has been deployed to more than 30 Oil and gas brown field sites as well as new projects. The application of fire and gas mapping has resulted in the optimization of fire and gas detectors at facilities where over-engineering was seen. At the same time areas with insufficient coverage were prescribed with additional detection. Engineering companies which has applied such methodology and conducted the mapping studies recognized the benefits of such structured risk based evaluation of fire and gas detectors. This new approach has gained popularity and rapidly becoming the best practices adopted in the industry.
Enhanced Oil Production with Autonomous Inflow Control Devices in a Thin Oil Rim Reservoir Malaysia
Authors: Tusimin Fuziana , Riyanto Latief , Ahmad Tajuddin Norbaizurah , Moradi Mojtaba , Marimuthu Raam , Konopczynski Michael
Published: November 2020

The added value of greater reservoir contacts with horizontal wells will be minimisedby an uneven reservoir sweep along thewellbore as the well may intersect heterogeneous formationswith varying properties. This results in early water and/or gas production in thewell. These challenges can be mitigated by deploying Autonomous Inflow Control Devices (AICDs)that can manage the reservoir fluid influx alongthe wellbore and therefore optimise the performance of well.The design of the well completion with inflow control devices is oneof the important steps in field development planning with a strong influenceon the production profileand thereby the economics. An integrated workflow was followed to deliver successfully the first AICDapplication for PETRONAS-Malaysia in an offshore oil reservoir with huge uncertainties in remaining oilthickness and current fluid contacts. The workflow comprised pre-drilling studies including AICD flow looptesting, well candidate selection, flow performance evaluation (static/dynamic modelling) and post-drillinganalyses including real-time completion design, history matching and comparison ofproduction data with neighbouring wells.

In the 2018 infill development campaign, improved productionwas targeted by the installation of AICDs in wells atoffshore Sarawak. AICD completions ensurebalanced contribution from all reservoir sections and limit gas and water production. The chosenhorizontal well was drilled in a very thin formation with the oil rim average thickness of 13ft, the thinnestAICD application to date. The well intersected two geological layers with differentproperties.Alarge gas cap and an aquifer were located above and below the well. The oilproduction from this well was expected to be impaired significantly due to a high probability of early waterand gas breakthrough, potentially within days or weeks. Two analogue wells drilled in 2013 suffer from both issues despite being completed with passive ICDs. Through teamwork between the companiesinvolved in the campaign, the well was successfully completed with an RCP AICD completion. The wellwas segmented in several compartments and a tailored AICD completions was designed to restrict theproduction of unwanted fluids properly. The AICD completion has delivered a 200% increase in oilproduction while it has significantly reduced GOR (up to 90%) and water cut compared to several offset wellswith various other completions.The AICD is an active flow control device that delivers a variable flowrestriction in response to the properties of the fluid and the rate of flow passing through. The lessonslearnt from pre and post-installation studies will be discussed here. The AICD completions enabled theoperator to implement an optimum reservoir drainage strategy that uses downhole control which willbe manipulated autonomously based on well dynamic condition instead of surface control.
Drilling Fluids Optimization – A Case Study in Overcoming Drilling Challenges in Excessive Over Balanced, Loss Circulation and Wellbore Instability Environment
Authors: B A Razak M Solehuddin , Ong Sheau Hun
Published: November 2020

The paper presents a case study of an Operator who successfully drilled two challenging wells through optimization of the drilling fluids. Well A was a HPHT well drilled with mud weight up to 18.6 ppg with overbalanced pressure as high as 6,800 psi – the highest overbalanced pressure experienced by the Operator to date. Well B was required to drill through depleted sand and unstable shale where series of severe loss circulation and wellbore instability issues were experienced in the nearby wells.

Due to its HPHT nature, the design of the drilling fluids in Well A was expected to have a total solids content up to 70% by volume. Due to this high solid content, the rheology of the fluids system is inherently high posing an issue related to excessive ECD. To further exacerbate the issue, the extreme differential pressure which was expected to be observed in Well A requires the inclusion of bridging material in the system as part of the mitigation plan to minimize the risk of differential sticking. Conventional bridging material such as calcium carbonate and graphite with concentration between 20 to 40 ppb will further increase the amount of solids in the system. Likewise, in Well B, the Operator also observed that the application of common bridging material in the drilling fluids does not help in addressing the severe losses and wellbores instability issue observed in the offset wells. Almost 60% of the offsets encountered severe loss circulation as high as 6,000 bbl mud loss per well.

This paper will share several initiatives by the Operator during the design stage in order to optimize the mud formulation to address the challenges for both of these wells. These include evaluation of various types of bridging material and "a must have" mud testing to assess the performance of the drilling fluids system. Subsequently, the Operator has successfully drilled these wells with no issues related to differential sticking, loss circulation and wellbore instability.
Drillstem Testing at 436°F Using a Retrievable Packer and Multicycle Circulating/Tester Valve: Case Study
Authors: Sarode Mahesh , Khati Milind , Haddad Josmar
Published: November 2020

A leading exploration and production company in India drilled a high-pressure/high-temperature (HP/HT) well in eastern offshore India and required drillstem testing (DST) to be conducted using the service company's multiple-set HP/HT retrievable packer, multicycle circulating valve, and multicycle tester valve. The bottomhole temperature at reservoir depth was approximately 460°F. This case study discusses the recently conducted DST of the HP/HT well by one of the largest global oilfield service providers in collaboration with the operator.

The HP/HT environment presented many challenges. The operator initially decided to deploy a permanent packer; however, after comprehensive preoperation planning with the service provider, the decision was made to run a retrievable packer to save time and costs associated with setting and milling/retrieving a permanent packer. The hook-wall concentric bypass, 7-in. retrievable packer was designed and tested for HP/HT environments. It was decided to deploy a full-suite multicycle DST tool string rated to 450°F. To help ensure a higher success rate for the long duration of the test, a clear fluid system of lower weight (14.6 lbm/gal) was used for reliable functioning of the annulus pressure-operated DST tools after a hermetical test and heavy kill mud (15.7 lbm/gal) was used for the well kill operation.

Deploying a full suite of annulus pressure-operated, multicycle DST string rated for HP/HT conditions permitted the testing of the well to be performed safely and efficiently without any breach to safety and service quality. The initial cleanup, three-bean study, and downhole buildup were successfully completed.

Temperature recorded in this well at the 7-in. retrievable packer depth was 436°F, and the reservoir temperature was extrapolated to approximately 460°F. The reservoir was successfully tested with an annulus pressure-operated multicycle DST string designed to withstand the challenging HP/HT environment.

The operation set a new global record, which is the highest recorded bottomhole temperature during DST using the service company's retrievable packer and multicycle DST tools.
Cementing Production Casing for Steam Injection Wells: Case Study Wells Drilled in the Western Desert Region of India, Rajasthan
Authors: Ganguly Bibek , Sarma Arindam , Kumar Animesh , Fortner Kelly
Published: November 2020

Steam injection is a fundamental method for enhanced oil recovery (EOR) wherein the wells are drilled and steam is injected to heat the crude oil in the formation to help reduce viscosity and improve oil recovery. The best practices for zonal isolation in the Baghewala field in India are discussed in detail. For desired zonal isolation, cement should maintain long-term stability once placed. Pressure and temperature changes can cause failure within the set cement.

An effective annular seal designed in these wells will be exposed to high temperature, cyclic stresses, and potentially corrosive environments caused by the injection of high-temperature steam into the wellbore. The design stage should go beyond cement placement, compressive strength, and gas-migration prevention. The solution is rooted in the synergy between diagnostic tools and engineered cement systems. Such design methodology was developed to address the challenge of the loss of zonal isolation caused by changes in the wellbore that can stress the cement sheath and cause destabilization at any point during the life of the well.

Specific to the cyclic steam injection in the Baghewala field, a cement system was designed to address the following challenges: Achieving cement returns to surface without fallbackHelping ensure the cement system is thermally stable at the maximum expected temperature (i.e., no strength retrogression, radial cracking, debonding, etc.)Achieving a good cement bond throughout the open and cased holesHelping prevent wellhead growth during steam injectionEncountering different types of formations (halite, anhydrite, sand, and carbonate) in this fractured reservoirUsing a cement slurry designed to avoid strength retrogression of set cement during exposure to high-temperature injection

Proprietary 2D hydraulics, finite element analysis (FEA), and 3D displacement simulators are analytical tools designed for simulations or investigative modeling to simulate fluid properties and slurry placement during operations. Additionally, they help reduce the need for costly remediation and positively affect the long-term cement sheath integrity by assessing and addressing issues before they become problematic.

More than 10 wells were successfully constructed with no issues reported during/after cyclic steam injections, which is endorsed by excellent cement bond logs. This helped minimize multiple potential risks and ultimately maximize production.

The cement design technology associated with FEA simulations and analysis provides the ability of the set cement to expand and contract in sync with the well's fluctuating temperature, reducing stress on the cement sheath. This occurs because these cement systems have approximately the same thermal expansion properties as the steel casing. Unlike conventional cement, particles can expand and contract thermally, thus reducing cement-sheath stress six times more than conventional systems.
Remote Support Technology of Bozhong 19-6 Drilling Engineering
Authors: Xu Tong , He Pengfei , Yu Zhongtao , Yuan Hongshui , Yuan Zeming
Published: November 2020

During the drilling operation, a number of data is not processed and analyzed effectively, and related problems are not researched thoroughly. In addition, wellsites are lack of timely technical interactivity and remote support with the base. In order to solve these problems, an auxiliary decision-making system for drilling was established. Also, a real-time dynamic drilling and completion database was studied and newly built, and the calculation models (e.g. coupled hydrodynamic model, drag and torque model, and ROP optimization model) were integrated with drilling simulator as the core, and thus real-time dynamic simulation, three-dimensional visualization and remote drilling monitoring while drilling is realized. Finally, based on its application in 9 wells of BZ19-6 exploration project, combined with friction factor inversion method, hydraulic simulation fitting method and stage correction method, the simulation accuracy of hookload/torque/hydraulic was above 90%, the monitoring accuracy of pore pressure was up to 97%. What's more, remote technical support based on expert consultation has been carried out accumulatively over 20 times. And eventually, a set of structure and method of remote auxiliary decision-making system for drilling based on transient simulation analysis was established.
Application of Probabilistic Method in Development of PRSM
Authors: Girsang Christian Hariady , Yusoff Norhayati , Nasri Huang Noorizal , Rohani Muhammad Joehan , Abdul Rahman Azam
Published: November 2020

Regional Suitability Mapping (PRSM) was initiated in 2013 with the aim of optimising operational cost efficiency and minimising potential incidents during jack-up emplacement, particularly incidents due to punch through failure. In the later stage of PRSM, a pilot study was carried out to assess punch through failure using probabilistic method. The proposed approach is found to be readily applied to multiple locations by using a standardised computational model. The probabilities of punch-through at 100 locations in Malaysian Waters were studied using this approach for Keppel FELS B Class jack-up rig in strong clay over weak clay scenario. The study indicates that the majority of boreholes fell into the extremes, either having less than 10 % probability of punch-through, or more than 90 % probability of punch-through. It was concluded that the proposed probabilistic approach enables the probability of punch-through in strong clay overlying weak clay profiles to be quantitatively computed such that the risk can be objectively evaluated. This is an advantage as compared to the standard industry practice which is to perform deterministic leg penetration analysis based on two design strength profiles corresponding to the low and high estimates.
Mechanism and Risk Assessment of Shallow Water Flow Based on Laboratory and Numerical Studies
Authors: Shentu Junjie , Lin Botao , Jin Yan , Shi Can
Published: November 2020

In the deep-water hydrocarbon recovery, the over-pressured sand originating from fast sedimentary compaction brings about difficulties in well control during drilling practices. When encountered by a drill bit, the sand section will generate shallow water flow (SWF) that could substantially jeopardize the integrity of the drill string and the associated equipment, eventually leading to drilling failure. The SWF hazard has been one of the predominant geological hazards in the deep-water drilling operation nowadays. Therefore, it is crucial to accurately identify the SWF hazard, estimate the risk, and take the appropriate measures to minimize the engineering and economic losses. In this study, a set of experimental facility and workflow were proposed, in order to investigate the flow failure behavior of the over-pressured sand section. The experimental findings indicated that the initial overpressure was one of the principal factors of the SWF hazard. Accordingly, a discrete element method-computational fluid dynamics (DEM-CFD) coupling approach and was proposed to model the process of the SWF hazard. The results of the numerical simulation were verified by the behavior of sand transportation disclosed in the laboratory experiment. The simulation showed that the sand production of a specimen increases with three influence factors, including the initial overpressure, the porosity and the sand grain size. Some critical points were discovered and studied in the investigations of each influence factor, and the rising tendency of the curve tended to undergo a dramatic increment at the critical point. Finally, the SWF risk prediction chart was proposed for the fast and convenient identification and evaluation of the SWF risk.