bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Approach to Maximize Revenue by Maximizing the Condensate Production in A Giant Field Using Molar Fraction Optimization in an Integrated Production System Platform
Authors: Alsaeedi Ayesha Ahmed , AlHarethi Fahed Ahmed , Alsenaidi Shemaisa Ahmed , Al Bairaq Ahmed Mohamed , Soni Sandeep , Tripathi Deepak , Hidalgo Melvin , Alkuwaiti Hamda
Published: November 2020

Meeting the gas production target while maximizing the total gas condensate and hence the revenue from condensate reservoirs is one of the key business drivers for an operating company. This paper describes a comprehensive simulation process to strategize production optimization, which helps in meeting the target molar fraction at the delivery point from the overall asset producing from complex reservoirs with varying fluid properties and achieving the overall target of lean gas production.

This process uses an integrated approach encompassing the various nodes in a production system, starting from reservoir to the export system to assure a representative and accurate prediction. In the first step, using the representative fluid model and the desired target production from the field, the well capacity-based rates are allocated to the individual production strings. In the second step, a component level optimizer is used to estimate the contribution of each well based on the well production stream composition. In the third and final step, this contributed production figure is fed back to the surface network hydraulic simulator to assess the back-pressure impact on the overall production and the achievable field-target.

The objective of maximizing the condensate production was fulfilled considering the provided constraints of operating guidelines, reservoir, wells, and surface facility capacities. Two different scenario runs were put together where the target gas production was achieved while increasing the condensate production by maximizing the condensate specific molar components and minimizing the heavy molar components. The expected condensate production was forecasted to increase by 5% in the scenario.

As the predictive hydraulic model is seamlessly integrated with the true field operating conditions, the outlined optimization process ensured that various business-scenarios accurately forecast the system behavior under various operating conditions. In the scenario, the forecast was able to maximize the condensate while meeting the production target within 1% tolerance limit.

The outlined approach provides a clear step by step standardized process approach which can be expanded to cater to the other business needs, such as minimizing the H2S for reducing the corrosion problem, minimizing the C7+ components to produce a high-quality condensate.

Such a framework based standardized methodology incorporates a seamless integration between the molar composition optimization and the associated hydraulic calculations-based optimization. Solving the both objective optimization functions simultaneously, this approach provides a novel way to address a vital industry business objective.
Fast Power Anywhere: Reaping the Benefits of Mobile Gas Turbine Packages
Authors: Balestrino Cristiano
Published: November 2020

In the oil and gas industry, a dependable supply of electricity is critical to safe and profitable operation. Currently, many oil and gas facilities throughout the Middle East and North Africa (MENA) region rely on damaged and/or aging power infrastructure to meet their electricity needs. This paper discusses the benefits of utilizing mobile gas turbine (GT) packages that can be rapidly deployed to provide reliable power within in a matter of weeks, days or even hours. The packages can be used to provide fast, scalable power, supplemental power or serve as back-up in the event of extended outages.

The paper outlines the capabilities of multiple mobile aeroderivative GT models, with a particular focus on the SGT-A45, which is currently the world's largest mobile aeroderivative unit in terms of power output. The GT package is designed to enable delivery of a complete power plant solution on a fast-track basis, with each unit pre-assembled on trailers and tested at the factory in order to verify operation and performance and minimize the scope of commissioning work needed at site. The self-contained, plug-and-play design reduces the installation time needed at site to only two weeks and minimizes "Balance of Plant" equipment.

The high power density and compact footprint of the aeroderivative mobile unit minimizes usage of real estate as a back-up power solution. As an example, a 4X units installation can provide approximately 175 MW at ISO within just one hectare (2.5 acres) of land.

For illustrative purposes, a case study is presented in which the SGT-A45 was deployed for a gas-fired power generation facility. The facility currently provides power to approximately 200,000 homes in Afghanistan. The paper will describe how the technology has addressed the specific challenges of this application to provide critical support to the country's development and infrastructure.
Application of Seismic Inversion of PSTM and PSDM Data to Capture the Regional Geological Trend: An Offshore Abu Dhabi Case Study
Authors: Inoue Hiroyuki , Shimoju Ryo , Kleef Franciscus Van , Al Khamiri Ahmed Mubarak , Obara Hidenori
Published: November 2020

Seismic processing to PSDM is now a common approach in Abu Dhabi to improve the subsurface imaging. However due to the amount of well information in this region, it is challenging to provide additional geological understanding through seismic reservoir characterization. This paper demonstrates the impact of PSTM and PSDM processing results through various trials of deterministic seismic AI inversions to provide meaningful geological information and its pitfalls.

The upper Jurassic Formation in this study area is currently categorized as un-developed reservoir and consists of high porosity and permeability grainstone dominant carbonate within a limited areal extension, the so-called Oolite belt in this region. Aimed to improve the seismic image for this reservoir and above super-giant reservoirs, PSTM and PSDM processing were implemented. Through PSDM processing, a robust velocity model was generated to solve complex overburden geologies such as high velocity channels, strongly anisotropic shale and lateral heterogeneity of these giant-reservoirs. Here the PSTM and PSDM results are evaluated during a deterministic AI inversion step.

Due to the small number of wells penetrating this undeveloped reservoir, two low frequency models were evaluated: one log interpolation only and two using merge log interpolation with PSTM and PSDM velocities for the ultra-low frequency component, respectively. Each seismic inversion result for both PSTM/PSDM seismic with these low frequency models shows a good agreement with log calculated AI and porosity. However, the low frequency model strongly influences the result away from well locations. In view of the regional geological trend, inversion results from PSDM seismic with PSDM processing velocity shows a good match to the regional geological features such as the extension of the Oolite belt and the inner ramp to mid ramp boundary. Additionally this seismic inversion result shows local high porosity regions at the crestal area and porosity changes at the flank area. These variations could be interpreted as porosity preservation after oil migration and local fracturation in depositional environment, respectively. AI inversion results from PSTM lead to more pessimistic GRV estimates and may lead to wells placed in less productive areas during the appraisal and development phases. Additionally these results mislead regional geological interpretation and potential exploration targets.

The benefit of PSDM processing is not limited to better imaging but also produces a robust velocity model leading to an improved understanding of reservoir distribution and characteristics. Integrating regional geological knowledge and seismic inversion using PSDM velocity models will help to identify exploration targets, derisk future appraisal wells and reservoir development plans.
Smart Reservoir Management with Real-Time Monitoring in an Offshore Carbonate Digital Oil Field under Miscible Gas Injection
Authors: Javid Khalid , Bascialla Guido , Sainz Alvaro , Hossni Ali Mohamed , Ettireddi Srinivas , Kumar Anurag Atul , Gonzalez Cerrada Luis Oscar , Mohamed Mohamed Sayed , Ibrahim Alhosani Khalil , Scheed Andreas
Published: November 2020

This Green Field was commissioned and put on production few years ago and subsequently within a few months Miscible Hydrocarbon Gas injection was started on a Field scale. It is a modern Digital Oil Field having two artificial islands built to drill all its field development wells with advanced completions such as ICV, ICD and Permanent Downhole Gauges in all Oil Producer Wells with automated multi-phase flow metering (MPFM). This paper will describe the utilization of real-time data for better and efficient Field/Wells Monitoring along with quick and smart reservoir management decision-making & improved reservoir characterization.

Real-time Dashboards (some of these were published last year, [1]) are utilized for robust screening of wells as per predefined rules and alerting Engineers for any wells, which are close to violating any of the Reservoir Management Guidelines, after QC and verification timely decisions, are made to avoid those violations. These Reservoir Management Guidelines for wells BHP & WHP are taken from Fluid Model (i.e. Equation of State) since the Field has a challenging considerable vertical compositional gradient for each of its reservoirs. The Guidelines are accordingly adjusted whenever a new verified information from PLT or PVT is available. Inter-well Gas Tracers Project implementation on Field scale is ongoing, where Tracers will be injected in all Gas Injection Wells/Strings to improve Reservoirs surveillance, Reservoirs understanding, Gas Injection Management, future wells locations and completion strategy etc.

Real-time MPFM Flow Tests & Permanent Downhole Gauges Pressure data is utilized for Real-time Pressure Transient Analysis (PTA) and well shut in time for PBU is therefore optimized. Moreover, All Field/well Shut Down duration opportunities are also utilized for real-time Pressure Build-up (PBU) analysis & recording WHCIP & BHCIP surveys for Oil Producer wells and therefore considerable cost of running Memory gauges and intervention operations is saved.

This paper shows examples of PTA data interpretation through real time data that improved decision-making and optimize the performance of each well. The benefits of implementing a digital oil field philosophy for improved decision making in order to maximize oil recovery in a challenging enhanced oil recovery offshore project is also discussed. Successful & Smart Reservoir Management is a result of collaborative and multiple discipline Team Work.
Novel Magnetic Resonance Data Processing Method, In Correlation with Mercury Injection Capillary Pressure Pore Throat Profile and Porosity-Permeability Property to Solely Predict the Rock Type First Pass
Authors: Susanto Maria Indriaty , Al Nuaimi Mayyada Awadh
Published: November 2020

This paper intends to utilise magnetic resonance (MR) data to predict the rock-type (RRT), by correlating its profile to the Mercury Injection Capillary Pressure (MICP), using a novel semi-automated method. Data presented come from Oilfield A, a reservoir highly affected by diagenesis causing reservoir properties to vary laterally. As a first step the feasibility of the method will be tested on the pilot well dataset, where its suitability will be assessed before applying the technique to the development well MR dataset. The fieldwide application in both pilot and development wells will improve the confidence of rock-type distribution.

Two methods, normalised cumulative and cumulative are attempted, correlating the inferred NMR pore volume to the inferred MICP pore throat distribution, grouped according to the rock type scheme in two reservoirs. Both NMR and MICP data are arranged in the same format. On the normalised cumulative method, feasibility is conducted on MICP data to see at which normalised cumulative frequence the rock-type shows distinct pore throat clusters, while on the cumulative method the rock-type clustering is assessed on the cumulative frequency range at the total pore throat size. A key assumption is that the NMR relaxation profile representing the pore size, is similar to the MICP pore throat profile to classify the rock-type. QC is performed on the resulting curves to ensure they honour the reservoir property trends from core. One method will be chosen on this basis, where a set of criteria will be applied to the resulting curve to generate the first pass rock-type prediction.

This paper contains the step 1 of rock-type estimation in the pilot wells and the suitability of application to the development wells. The development well application itself is currently still ongoing.
Automatic Well Correlation by Aligning Multiple Well using Deep Neural Networks
Authors: Hong Youngjun , Kang Changbeom
Published: November 2020

The interpretation of well logs is crucial for understanding subsurface geological formations and reservoir characterization. Among various roles of well logs in an exploration stage, constructing subsurface stratigraphic structure over target area is an important task to estimate oil and gas layer. Well logs correlation which connects multiple well logs with similar traits is commonly operated for stratigraphic surface picking. However, since a subsurface stratigraphic structure is very irregular and complex, correct well logs correlation is a time-consuming and high-cost task that is usually done by many geology experts. Recently, various studies suggest using supervised machine learning algorithms to automate well logs correlation. Most works firstly build formation matched pairwise dataset and train deep neural networks such as convolutional neural networks. However, such labeled data for supervision is cost expensive and most of them are not publicized.

In this paper, we propose a simple and unsupervised method for automated well logs correlation with cutting-edge machine learning techniques. Unlike existing methods, we don`t utilize well logs paired data. Rather, we utilize well logs themselves, assuming nearby well logs would have similar characteristics at adjacent depth points. Most importantly, we introduce a time-series alignment concept to well logs correlation, which can deal with multiple well logs of different lengths. We show that our well logs alignment model is effective and can be applied to well logs in any oil and gas regions up to its simplicity.
Frac Plugs Milling Optimization in Depleted Gas Wells, from Learnings to Well Delivery Enhancement
Authors: Nunez Alvaro Javier , Sayapov Ernest , Chavez Juan Carlos , Al Hinai Adnan Saif , Al Kendi Al Muntaser , Eltorabi Yousif , Al Hatmi Hatim , Makawi Sami
Published: November 2020

The scope of this paper is to discuss and compare the different milling strategies of the frac plugs associated to hydraulic fracturing operations in both, vertical and horizontal gas wells, with formations depleted in Petroleum Development Oman (PDO); the main objective is to describe milling operations and the well delivery improvement by the optimization of clean out and milling strategy. The paper will show the enhancement of the milling operations and the outstanding results.

The paper will start by describing the execution of hydraulic fracturing operations in both vertical and horizontal wells, which is mainly related to plug and perf. It will also cover clean out and milling practices for frac plugs in depleted formations. Further, it will discuss the planning and design of the post frac clean outs and milling jobs based on the learnings previously captured.

Frac plugs milling operations have been successfully improved in severe depleted vertical gas wells and some horizontal wells with no severe depletion; initially the milling operation was done after all frac stages were completed in depleted wells, out of the critical path, however the experience showed that it was a lengthy and expensive process due to the severe formation losses while milling leading into a very low efficient operation impacting the frac well delivery. The subsequent step was to address the milling after every stage, during the critical path, which increases the cost of daily frac charges. With the use of an innovate downhole technology the milling strategy was changed and optimized showing outstanding results, milling frac plugs was achieved successfully at the end of the job in horizontal wells while in some previous wells the milling was done in between the stages; also for vertical depleted gas wells, fracturing stages have been combined to mill frac plugs together. The completion of the entire wells (well delivery) was achieved in a relative shorter period of time compared to previous wells; this is reflected on actual cost reduction of more than 20% of total cost/AFE

The optimization of the frac plug milling operations is a novel approach to enhance hydraulic fracturing and well delivery in depleted gas wells in PDO, this is in alignment with the continuous improvement (CI) ideas and the lean thinking across the oil and gas industry nowadays. It is easy to replicate in other gas fields expected to be depleted, which will reduce cost, Health, Safety & Environment (HSE) exposure and will help increase the recovery of hydrocarbon reserves.
Accurate and Convenient Missing Well Log Synthesis using Generative Model
Authors: Kwon Minsu , Yoo Jaeyoon , Kang Changbeom , Hong Youngjun , Jeong Hoonyoung , Yoon Sungroh
Published: November 2020

In the oil and gas exploration, well logs, the most convenient and economic data source, usually contain missing values due to various reasons. It is crucial to generate accurate synthetic logs for such missing intervals in terms of precise well log interpretation. In this paper, we propose a workflow of generating synthetic logs using cutting-edge machine learning techniques. Unlike existing methods, we exploit a generative model, which can deal with various missing patterns with a single model, and we combine it with a supervised model. With well log data of various regions, we show that our models accurately generate missing logs and outperforms existing supervised-only models. It is expected that our model is beneficial in the real field because of its performance and simplicity.
Geomechanics Characterization of Nahr Umr and Laffan Shales Through Anisotropic Geomechanics and Shale Stability Analysis for Drilling Optimization
Authors: Xi Guifen , Draoui Elyes Habib , Alblooshi Jamal Rashed , Al-Jaberi Salem Mubarak , Al-Badi Bader Saif , Muniz Eudes Siqueira , Guerra Julian , Donald J. Adam , Povstyanova Magdalena , Martin J. Wesley , Balliache Norka Marcano , Deenadayalu Chaitanya
Published: November 2020

Frequent drilling challenges for high-inclination well paths in the overburden Laffan and Nahr-Umr shales involve stuck pipe incidents and caving, leading to sidetracking in extreme cases. Advanced geomechanics studies including both an anisotropic wellbore stability model and shale stability analysis were conducted on acquired cores to better understand these problematic intervals for improving drilling efficiency and reducing costs by mitigating wellbore instability.

The study analyzed the preferential directions of deformation and failure (i.e., anisotropic) in the shales and their time-dependent behavior in reacting with drilling fluid. Shale samples were preserved to avoid changes in mechanical properties due to the high clay content and low permeability. Two overburden shale intervals were analyzed to determine strength and elastic anisotropy. Dynamic anisotropic elastic properties were obtained via ultrasonic wave propagation. Strength anisotropy was evaluated using the plane of weakness model that assumes a heterogeneous media composed of a matrix rock and plane of weakness (e.g., bedding/laminations, interface between lithotypes or laminations).

The test results showed a drop of compressive strength from 50% to 70% for samples with inclination from 38 to 62 degrees, which increases the chance of formation collapse of the laminated shales at such wellbore deviation. The anisotropic analysis proved that the stress field is higher when anisotropic properties are considered, which leads to higher propensity for failure. Shale stability tests demonstrated that most of the instabilities identified in the Laffan and Nahr-Umr formations were mechanical in nature. The optimal mud weight is strongly dependent on the well trajectory to account for the plane of weakness and strength anisotropy.

Combing data from laboratory tests with advanced sonic logs enabled a more robust evaluation of the formation anisotropy at the well scale, which improved both stress predictions and mud-weight window predictions along the well trajectory. This anisotropic well-centric model helped for determining more appropriate mud weights and salinities for upcoming directional wells.

By obtaining core samples in the shale formations, the operator was able to test and characterize the anisotropic behavior and also analyzed the time-dependent behavior. These results were combined with advanced sonic logs to better understand and mitigate wellbore instability induced from the plane of weakness.
A Rock Physics Based Time-Lapse Feasibility Workflow Calibrated to Core Measurements Which Incorporates Both Fluid Changes and Pressure Depletion
Authors: Proud Christian , Jakobsen Ask Frode , Ross Rob , McKenna Jason , Dvorkin Jack
Published: November 2020

Rock physics analysis is a useful tool in time-lapse seismic feasibility studies and can help to assess the effect of pressure and saturation changes on the elastic parameters which the seismic data is sampling and hence the probability of success of a 4D seismic survey. Calibration using velocity measurements made on dry core data at varying pressure conditions allows for forward modelling of the expected seismic response at different effective pressures as well as different hydrocarbon saturation levels. The step of forward modelling the pressure changes is performed less frequently and in a less well calibrated manner than that of changing the hydrocarbon saturation as there is often no core data analysis performed at different pressures.

In this study we show that incorporating pressure effects produces non-negligible changes to the elastic properties of the reservoir rock. Changes of up to 10% and 8% to acoustic and shear impedance respectively are observed in the most prospective reservoir interval when the pressure effect is included. Such changes would be detectable by high quality 4D seismic data. The authors recommend including the pressure change data whenever possible in 4D rock physics modelling.
Salt-Tolerant Surfactant for Dilute Surfactant Flooding in High-Salinity Reservoirs: Residual Oil Stripping and Displacement Mechanism and Efficiency by Ultra-Low Interfacial Tension
Authors: Yuan Chengdong , Pu Wanfen , Varfolomeev Mikhail A. , Tan Tao , Timofeeva Anastasia A. , Sitnov Sergey A. , Mustafin Aidar Z.
Published: November 2020

Dilute surfactant flooding is a promising EOR method. It is more economical and easier to be controlled in reservoirs compared with microemulsion flooding where high surfactant concentration is needed. In this work, we present a salt-tolerance surfactant that can attain ultra-low interfacial tension (IFT) by a low surfactant concentration (0.2wt%) under high salinity condition. And its oil stripping and displacement mechanism and efficiency under ultra-low IFT condition were investigated.

A novel anionic–nonionic surfactant with a low concentration of 0.2 wt% was used to prepare surfactant solutions at different salinity conditions. Ultra-low IFT (10−3 mN/m) was obtained at high salinity condition. These surfactant solutions were used for oil film stripping experiments in visual oil-wet quartz cell and filtration experiments in transparent sand pack model as well as two-parallel core flooding model under heterogeneous permeability conditions to study oil stripping and displacement mechanism and efficiency by ultra-low IFT.

Oil film can be effectively stripped only under ultra-low IFT condition at high salinity condition with the occurrence of wettability reversal (from oil-wet to water-wet). Oil film is stripped in the form of oil drops by automatically shrinking. The stripping mechanism by ultra-low IFT can be attributed to the reduction of water-oil IFT, water-solid surface IFT, and wearability reversal, which thus reduces the work of adhesion. Filtration experiments showed that a high displacement efficiency (additional oil recovery is about 16-23% depending on the heterogeneity) was yielded under ultra-low IFT condition at high salinity condition in dilute surfactant flooding process. In addition, a new EOR mechanism was found that ultra-low IFT can re-mobilize the trapped oil in low-permeability layer that cannot be displaced by water flooding under heterogeneous permeability conditions without any additional conformance treatment.

This anionic–nonionic surfactant can obtain ultra-low IFT at high salinity condition at a low surfactant concentration (0.2 wt%), which can effectively strip residual oil film and re-mobilize trapped oil in low-permeability zone that cannot be mobilized by water flooding under heterogeneous permeability. The development of this salt-tolerance surfactant and finding of its EOR mechanism will improve the application of dilute surfactant flooding in those reservoirs with high salinity.
Multilateral Challenges and Solutions for Installations in the Middle East
Authors: Kelsey Matthew , Fanchin Thomas , Rondon Leonque
Published: November 2020

Multilateral technology can provide a higher recovery factor by achieving a longer field life supported by the cumulative production of the multiple laterals, turning otherwise unviable reservoirs into economically sound targets, keeping construction costs down and minimizing risk.

This paper will focus on TAML 5 systems that meet well integrity requirements by isolating the junction from reservoir pressure or stimulations and provide independent accessibility on both laterals during the life of the well. This capability eliminates the requirement to pull the completion should access be required to the lateral for cleaning, stimulation, zonal isolation, or data acquisition. Using this technology also leads to a reduction in the cost of well construction as well as intervention.

This paper discusses challenges faced to provide accessibility to both laterals from surface without using a re-entry deflector as well as solutions including segregated and commingled flow installations. Discussion will also cover completion designs that tie new laterals into existing production casing. Case studies will include a discussion of workover operations, isolation methods, and lateral creation systems.

In the Middle East, older TAML 4 wells have been converted to TAML 5 in order to prevent detected gas migrating into the mainbore at the junction. This conversion of a cemented junction well has enabled production to resume on the wells. This application has also been applied to the installation of new wells in the region. New and re-entry wells were completed with intelligent upper completions to enable flow control of each lateral.

The paper focuses on the challenges, solutions, and successful case studies of multilateral wells constructed in the Middle East. The paper also provides insight as to methodology for continually improving reliability of multilateral installations to maximize efficiencies.
How to Verify the Performance of a Flowmeter in Field Conditions Against Another Device
Authors: Pinguet Bruno , Pieper Anna
Published: November 2020

Multiphase and wet gas flowmeters (MFMs) are becoming drastically cheaper, allowing the capability to be used by most of the oil and gas companies today. If the CAPEX can be reduced, the main question about the reliability and the capability of such equipment to provide accurate data and to perform correctly compared to previous technology (usually a separation-based system) remains. The unrealistic specification of multiphase manufacturers made in the past led to suspicion of such products by oil and gas companies. Additionally, the reluctance of using MFMs could be due to a number of technologies that require significant effort to have a proper understanding of the device.

The buying process very often leads to some form of comparison test made either before delivery (usually tested in a third-party facility), or later in the field regularly or spot check against standard equipment (separators, tanks or any other trending devices). This fair initiative to understand the real performance usually leads to more questions about what/how/where/when to compare and are also incredibly important. Last but not least, what should define the "PASS/FAIL" criteria? It should also be noted that limited test envelopes (flow conditions) may not reflect the entire performance of the meter. Therefore, either additional measurements or statistic elements should be used to establish the actual statement or meter performance.

It is incredible to see, today, in the billions of dollar oil and gas business that most of the systems are reporting flow rates without any information about the measurement uncertainty, this leads to the belief that the production is entirely known. Unfortunately, people working in allocation are the first to face this challenge and to reconcile the data. On the other hand, the top-class MPFMs are providing uncertainty on measurement, which is as good as, if not better than, some of the standard equipment that is used and so the uncertainty of both devices needs to be thoroughly taken into account in these comparisons to make allocation fair and indisputable.

The paper will embrace these comparison tests, the author has repeatedly faced such cases over the years and wishes to bring to light the relevant work that needs to be done before, during, and after the tests to make it conclusive. We expect to provide some practical statements which will progress and help all parties involved in these comparison tests where the presence of a third party (being impartial and independent) can ensure there is no bias in the overall statement.
Predicting Just in Time: Prognostic Health Management for Oilfield Equipment.
Authors: Bannikov Denis , Lyapunov Konstantin , Pantsurkin Danil , Parkhonyuk Sergey , Velikanov Ivan
Published: November 2020

Delays in the hydraulic fracturing stimulation process due to equipment issues may result in Non-Productive Time (NPT) and often associated with high costs. Both operators and service companies are interested in implementing a system to predict these events in advance so that they can proactively react and prevent failures before they occur. Our objective was to develop, implement, and demonstrate the capabilities of such a system.

Based on historical data, we identified the most NPT-prone subcomponents of stimulation equipment. We combined failure reports and maintenance records with sensors data to train Machine Learning (ML) models. The final solution was deployed on the cloud to predict remaining useful time (RUL) in real-time and to start specific notifications sending whenever RUL dropped below the preset value.

We analyzed 20,000+ failure records and identified the most NPT-prone equipment, subcomponents, failure modes, and root causes. We found out that root causes are very scattered. We evaluated the applicability of physics-based and data analytics approaches for Top-10 root causes by NPT duration and NPT count. When NPT count per root cause is low (<10), the trained ML models had insufficient accuracy. In this case, only subject matter experts and understanding of physics behind performance deterioration allowed us to boost data-driven models’ accuracy. We started with testing on historical data. Then we continued testing on real-time data without field intervention. This stage was required to check and to build trust in the predictive ability of the models. After initial testing, we eliminated some of the models and switched to monitoring with field interventions. For six months of operating, the model helped to decrease the NPT related to the selected subcomponent by 20 times.

This work presents the process of enabling Intelligent Diagnostics for hydraulic fracturing equipment by implementing failure identification and prediction models. It combines both domain knowledge (failure modes of the equipment, sensors data) and recent advances in ML (time series analysis, data processing, and feature engineering). The developed system to be further extended to different equipment, as the workflow described in the present study is not specific to particular equipment.
Pressurized Mud Cap Drilling Replacing Floating Mud Cap to Reduce Drilling Risk and Optimize Mud Consumption
Authors: Ullah Syed Zahoor , Ruzhnikov Alexey , Prasetia Andi Eka , Al-Fakih Abdulqawi , Almomen Mohammed Sami
Published: November 2020

Unmanageable losses through carbonate formations led to pumping water through the drill pipe and heavy mud cap in the annulus to drill with total losses. Although this technique overcomes the need to fly mix drilling fluid, it adds the complication of pumping heavier mud cap into the annulus. Pressurized Mud Cap Drilling (PMCD) was introduced the first time in the project to eliminate the requirement of mud cap for improve wellbore condition, efficient well control and to optimize the overall cost while drilling with total losses.

As mud cap density increases based on reservoir pressure, so does solids concentration in mud cap. Apart from mud cap getting extremely expensive at higher densities, it deteriorates hole condition due to continuous addition of solids especially for horizontal wells where solids keep piling up on the low side of the wellbore. With total losses in the reservoir, drilling is followed by image log, followed by reaming run and finally open hole completion runs to isolate those fractures.

On wells where higher density mud cap was used, severe hole problems leading to stuck pipe were faced either during logging or open completion runs. On most of the occasions, solids of mud cap have been proven as the root cause for worsening the situation.

PMCD has been introduced as a solution to such high-pressure wells to drill and complete them with total losses more efficiently and cost-effectively. It not only reduces the volume of solids dumped in the wellbore in the form of mud cap thus improving the hole condition but also saves the immense cost of mud cap which is especially massive for long laterals while dealing with long reaming operations.

The above motivation of finding a solution for drilling in total loss environment emerged from one of the wells where pipe conveyed logging string (TLC) got differentially stuck while pumping a 90 pcf mud cap. The pipe could not be recovered even after cutting it inside the casing shoe confirming it was packed off with solids laden mud cap. The well was sidetracked and was completed with PMCD successfully without any complications. After that job, PMCD has been implemented in five other land wells successfully and being recognized as standard practice for drilling high-pressure wells with total losses.

This paper illustrates the challenges faced by turn key project team due to total losses and drilling with mud cap, and overview of PMCD procedures, comparison of mud cap and the inherent advantages of PMCD over mud cap drilling. It provides details of the well which could only be recovered using PMCD after sidetrack due to stuck pipe.
Seismic Attributes for Channels Identification and Facies Modelling Application in a Siliciclastic Onshore Reservoir, Kazakhstan, Central Asia
Authors: de Sousa Ana , Bizarro Paulo , Ribeiro Maria Teresa
Published: November 2020

Seismic attributes often provide support for identification of several important parameters that could be applied in geomodelling for constraining reservoir properties such as porosity, permeability and fluid saturation. Additional insight can be gained as a way of detecting depositional features and geometries, and improve qualitative (e.g., data quality, seismic facies mapping) and quantitative analyses (e.g., net sand, porosity prediction).

The case study is a deep gas bearing Jurassic fluvial channel sandstone reservoir in an onshore field in Kazakhstan, Central Asia. The data set is scarce, with only a few wells penetrating the reservoir. The available 3D seismic data is weak to a reasonable quality, and an attempt was carried out to use a series of attributes for channel identification and imaging. After testing several attributes, only two of them have shown good results: Generalized Spectral Decomposition (GSD) and Variance. Geobody extraction was also tried, but the seismic quality was not sufficient enough to further pursue such methodology.

To overcome this issue, a joint approach for channels detection and extraction was tested by looking at the variance attribute in time slices and applying a workflow for an alternative way. With this technique (Alternative way for extracting geobodies), the facies property was generated in zones where the information was limited. The implementation of this approach, together with core facies interpretation has allowed a way of constraining other properties (e.g. porosity) and undoubtedly increased the robustness of the static model. Such model will support a more accurate estimation of HIIP volumes, future decisions on the most proper development plan and also investment decisions.

The alternative way for extracting geobodies was tested in two channels examples and for different zones in Jurassic reservoir with success. The described workflow helped in channel extraction and it can be used in facies modelling when the reservoir data set is scarce. A more robust facies model can be generated by combining the seismic attribute results with well data.
Accurate Reservoir Characterization in Multi Barrier Well Bore Systems with an Advanced Multi-Detector Pulsed Neutron Logging Technology
Authors: Elyas Mohamed , Freile Daniel Agustin , Tagarieva Larisa , Abu-Eida Abdullah Ibrahim , Al-Azmi Nasser Hadi , Patra Milan Kumar , Al-Sabea Salem
Published: November 2020

The five detector pulsed neutron (FDPN) tool is one of the most advanced tools in cased-hole reservoir evaluation. The evolution of multi-detector pulsed neutron tools (MDPN) created a turning point in the methodology to properly handle the different challenges within petrophysical cased-hole evaluation either in conventional or unconventional formations. This study demonstrates the applications of the FDPN tool and the methodology to handle the challenges in the multi-barrier well bore systems.

The FDPN tool was used in two double-barrier well bore field cases in addition to one case with a triple casing system. Each case was unique in terms of objectives and challenges: Case 1 (13.375 inch, 9.625 inch and 7 inch casings) aimed to estimate the presence of gas in the annulus between the two casings and the formation gas behind the double-barrier wellbore system, while Case 2 (7 inch liner and 4.5 inch ICD) required to perform a three-phase calculation. In Case 3 (13.5 inch, 10.75 inch and 7.625 inch casings) diffusion-corrected sigma was recorded to be able to determine the water saturation in a triple casing system. In all these case studies, Monte Carlo simulations (MCNP) were performed to characterize tool response and to determine if the data to be recorded will achieve the objectives of these jobs.

In Case 1, the FDPN tool helped to establish the presence of gas in the annulus between casings and determined the gas saturation profile in the formation using the difference between the normalized capture and inelastic ratios. This case was unique since other MDPN tools were not able to quantify the volume of gas in the formation due to their lower gas sensitivity. In Case 2, the objectives were successfully achieved. Also, it was possible to differentiate between the formation gas and the gas pockets between the 7 inch liner and the 4.5 inch ICDs using the comparison between inelastic and capture measurements. In Case 3, a diffusion-corrected sigma was measured and identified formation water movement in the zone of interest which helped to make a decision about drilling of the offset well.

The FDPN tool provides a higher spacing between the detectors and neutron generator which gives a better quantification of hydrocarbons especially for large casing and borehole sizes. Furthermore, the spacing between the long and proxy detectors is increasing the gas measurement sensitivity compared to other MDPN tools. Also, the 1.69 inch pulsed neutron logging tool was successfully run for first time in Kuwait to record diffusion corrected Sigma over a triple casing interval.
Development of Oriented Fracturing of Chemically Induced Pressure Pulse for Unconventional Gas Reservoirs
Authors: Al-Nakhli Ayman
Published: November 2020

Commercial production from unconventional reservoirs require new technologies to reduce the breakeven cost. Multistage fracturing was an enabler of gas production from such reservoirs; however, it is responsible to significant cost. Fracturing jobs cancelation, due to high pressure, results in non-productive wells, which also represent high cost. Moreover, unfractured wells results in locked and unproduced potential gas.

One of the major challenges that is faced by fracturing companies is the high breakdown pressure of such reservoirs, which exceeds tubular and pumping pressure limitations. This results in non-fractured wells. A recently developed technology is chemically-induced pressure pulse, where exothermic reaction is triggered in-situ to generate pressure pulse sufficient to fracture the formation. Initiated fractures, then propagated with hydraulic fracturing. This paper study the generated fractures, using chemical pulse, on confined and unconfined conditions. Moreover, the study shows a successful new techniques of orienting the pulse fracturing.

The objective of developing a new method of orienting in-situ pressure pulse is to increase the stimulated reservoir volume in unconventional reservoirs, and ultimately enhancing commercial production. The technology will also enable fracturing high-stress rocks, deep unconventional reservoirs, as conventional hydraulic fracturing method fails to fracture the formation.

A novel technique for oriented chemically-pulse fracturing was developed. The invented method is to create oriented fractures around wellbore, therefore enhance productivity. Having an oriented chemical pulse fracturing, will significantly impact the application of this technology for unconventional gas, especially during long horizontal wells.
Application of Flat Rheology Drilling Fluid System for Overcoming Operational Challenges in Ultra Deepwater Environment
Authors: Alimuddin Sultan , Dey Rahul Sukanta , Srisai Wanchana , Aldea Catalin , Kaewpraphan Kingkarn , Temaismithi Kantaphon , Maheshwari Mukesh
Published: November 2020

This paper presents a comprehensive laboratory and field study discussing development, formulation, and application of a new flat rheology drilling fluid system that meets the challenges faced when drilling in an ultradeepwater well environment. The use of this new flat rheology drilling fluid system for the first time in Asia-Pacific Region has created the potential to efficiently drill more challenging deepwater and ultra deepwater wells in offshore Myanmar, Malaysia, and other associated countries.

In a deepwater block situated on Myanmar's west coast, conventional synthetic-based drilling fluids (SBM) have been used to drill all the wells to date. During the planning phase of an ultradeepwater well with a water depth of 2,300 m, it was found that the equivalent circulating density (ECD) with a narrow pore pressure and fracture gradient would have increased downhole complications leading to non-productive time (NPT). The main concern was not being able to reach total depth (TD) or successfully setting casing on bottom with the original well design, requiring implementation of a contingency casing and pushing the operational cost over authority of expenditure (AFE). To overcome the challenges, a new flat rheology drilling fluid system was introduced based on ECD challenges and rheology requirements. The initial study of modelled hydraulics showed a significant ECD reduction using a flat rheology drilling fluid system.

The first round of laboratory tests exhibited promising results of flat rheology across all temperature ranges and after iterating numerous formulations developed with local seed mud were narrowed down to two final formulations of 1.08 sg and 1.17 sg. The formulation was field trialed with some slight adjustment in chemical concentrations to meet specific field mud properties. The well was drilled successfully with no major variation in ECD or issues related to the large temperature range. Implementing this customized solution combined with precise strategy led to successful results in efficiently completing one of the most challenging wells of the campaign.

The paper presents a comprehensive study of the challenges formulating and implementing a new flat rheology drilling fluid system. Additionally, a detailed study on ECD challenges when drilling an ultradeepwater well is also done. The paper also discusses the comprehensive pit management program and required treatment plan for drilling. Finally, the paper aims to compare the existing results with previous drilling techniques, which will assist operators with the future advances in similar fields.
Ensuring Pipeline Integrity in a Marginal and Aging Asset
Authors: Chantawit Damrong , Tarasantipong Wason
Published: November 2020

In a marginal and aging asset, ensuring the pipeline integrity plays an important role in order to maintain fluid transmission. Shutting off a single pipeline could jeopardize the overall asset operation. This paper presents a methodology for the identification, assessment and mitigation of dragged submerged pipelines.

As part of Pipeline Integrity Management, the inspection of an anchor-dragged submerged pipeline was carried out with the aid of a Remotely Operated Vehicle (ROV) equipped with pipe-tracker module. This enabled us to determine the extent of the pipeline alignment deviation, as well as to conduct a close visual inspection of the pipeline. With the information retrieved from the inspection, a fit-for-purpose pipeline drag analysis was performed to assess the pipeline integrity. The pipeline was simulated using the Finite Element Analysis (FEA) methodology which considered various axial and lateral soil friction factors to achieve the closest approximation of the pipeline's actual condition. Once the best-fit parameters were determined, code checks were performed in accordance with the DNVGL-ST-F101 [1] international standard to assess the acceptable pipeline operating envelops. This assessment results provide the inputs to develop the mitigation plans required to safely keep the pipeline in operation until the pipeline repairs can be executed.