bluuebunny/crossref_metadata_2025 huggingface dataset:
Technical Methodology for ASTER Global Water Body Data Base
Authors: Fujisada Hiroyuki , Urai Minoru , Iwasaki Akira
Published: October 2018

A waterbody detection technique is an essential part of digital elevation model (DEM) generation to delineate land-water boundaries and set flattened elevations. This paper describes the technical methodology for improving the initial tile-based waterbody data that are created during production of the ASTER GDEM, because without improvement such tile-based waterbody data are not suitable for incorporating into the new ASTER GDEM Version 3. Waterbodies are classified into three categories: sea, lake, and river. For sea-waterbodies, the effect of sea ice is removed to better delineate sea shorelines in high latitude areas, because sea ice prevents accurate delineation of sea shorelines. For lake-waterbodies, the major part of the processing is to set the unique elevation value for each lake using a mosaic image that covers the entire lake area. Rivers present a unique challenge, because their elevations gradually step down from upstream to downstream. Initially, visual inspection is required to separate rivers from lakes. A stepwise elevation assignment, with a step of one meter, is carried out by manual or automated methods, depending on the situation. The ASTER GWBD product consists of a global set of 1º latitude-by-1º longitude tiles containing water body attribute and elevation data files in geographic latitude and longitude coordinates and with one arc second posting. Each tile contains 3601-by-3601 data points. All improved waterbody elevation data are incorporated into the ASTER GDEM to reflect the improved results.
Comparison of Cohesive Models in EDEM and LIGGGHTS for Simulating Powder Compaction
Authors: Ramirez-Aragón Cristina , Ordieres-Meré Joaquín , Alba-Elías Fernando , González-Marcos Ana
Published: October 2018

The purpose of this work was analysing the compaction of a cohesive material using different DEM simulators to determine the equivalent contact models and identify how some parameters of the simulations affect the compaction results (maximum force and compacts appearance) and computational costs. For that purpose, three cohesion contact models were tested (‘linear cohesion’ in EDEM; ‘SJKR’ and ‘SJKR2’ in LIGGGHTS). The influence of the particle size distribution (PSD) on the results was also investigated. Further assessments were performed on the effect of selecting different timesteps, using distinct conversion tolerances for exporting the 3D models to STL files and moving the punch with different speeds. Consequently, it was possible to determine that a timestep equal to a 10% Rayleigh timestep, a conversion tolerance of 0.01 mm and a punch speed of 0.2 m/s are adequate for simulating the compaction process using the contact models in this work. In addition, the results determined that the maximum force was influenced by the PSD because of the rearrangement of the particles. The PSD was also related to the computational cost because of the number of simulated particles and their sizes. Finally, an equivalence was found between the linear cohesion and SJKR2 contact models
Estimation of Livestock Methane Emissions in the Extensive Crop-Livestock Farming Areas of Bale Highland, Oromia, Ethiopia
Authors: Defar Girma , Mengistu Ashenafi , Berhane Gebreyohannes
Published: October 2018

The study was conducted in the potential mixed farming areas of Bale highland to estimate livestock methane emissions. Using multi-stage purposive sampling, 156 households of the three wealth groups were selected based on their livelihood assets as described under methodology. Structured questionnaires, focus group discussions, key informants interview and field visits were the employed methods during the study. Feed nutrient balance was estimated based on the demand and supply while the livestock methane emissions were estimated according to the IPCC guidelines. Descriptive statistics and one-way ANOVA tests were used to analyze the data. Cattle were the dominant (84.25%) livestock owned by the households. The estimated enteric CH4 emission rate from mature cattle, growing cattle, sheep >1 year, sheep ≤ 1 year, horse and donkey were significantly (P<0.001) higher for the better wealth group while mature cattle (69.78%) shared the highest rate. Though, higher emission rates credited to the large number of animals in the area, cattle stay crucial to the livelihoods of the households, beside the major sources of CH4. In conclusion, the estimated CH4 emissions should be focus areas of interventions. Therefore, proper husbandry and quality feed supply and promotion of farm level livestock technologies should be practiced wisely to increase productivity and protect the environment from emissions of the livestock sector.
Resistant Starch Supplementation Improves Bifidobacteria Colonization and Lipid Profile in Adult Obese Subjects Residing in Urban Vadodara
Authors: Sheth Mini , Johari Aanchal , Shah Isha
Published: October 2018

Obesity continues to be a growing problem globally among all age groups, further associated with life threatening co-morbidities. Resistant Starch (RS) as a dietary component has been recently recognized as a prebiotic with potential role in improving the bacterial ecology of human gut. The present study was undertaken to evaluate the impact of resistant starch supplementation by the obese adults in urban Vadodara on microbial changes in gut flora with respect to Bifidobacteria and Enterobacteria. Using a non randomised control trial study design, 60 obese adults were enrolled from the free living population of urban Vadodara. Baseline information was collected and subjects were classified into control (n=30) and experimental group (n=30). Experimental group was supplemented with 10 g of RS daily for the period of two months (60 days). The control group were not given anything during this period. Blood and stool samples were analysed for lipid profile and the presence of Bifidobacteria and pathogenic Enterobacteria, respectively both at baseline and after the intervention period. Results revealed a significant increase in the mean log counts of Bifidobacteria by 11.7% with no significant reduction in the mean log counts of enteric pathogens and lipid profile of subjects. Hence study concludes that a daily supplementation of 10 grams of RS for 60 days to the obese subjects improved colonization of beneficial gut microbiota in terms of Bifidobacteria, but had little effect on obesity.
Morbidity due to Infections in Preschool Children from Urban Low Income Households
Authors: Lakshmi R. V. , Sylvia Subapriya M. , Kalaivani K. , Ramachandran Prema
Published: October 2018

Respiratory infection, diarrhea and fever are three common infections in underfive children; there are substantial differences in the reported prevalence and ranking of these three morbidities between studies and surveys. Seasonal and year to year variation in prevalence of morbidity and impact of health care on the duration and severity of infection has not been explored. A large scale mixed longitudinal study of under-five children from urban low income households was carried out to document year to year and seasonal variations in the prevalence and type of morbidity and utilization of health care for morbidity and their impact on duration and severity of morbidity. Between January 2012 and Dec 2015 a total of 3888 pre-school children were investigated and 74636 observations were made; prevalence of morbidity was 10.3% (range 7.2%-11.6%). Prevalence of morbidity was higher between July and October. Respiratory infection was the most common and diarrhea was the least common illness in children. Over years there was a rise in the respiratory illness because of increase in construction activity in the study area. There was a fall in diarrhoeal diseases after construction of water supply and drainage system. Majority of the households accessed health care; as a result duration of illness was short and severe morbidity was rare. Improvement in environmental hygiene can result in reduction in morbidity. Access to health care reduces duration and severity of infection.
Barasi’s Human Nutrition A Health Perspective
Authors: Balasasirekha R.
Published: October 2018

No abstract.
Gradient material Pd-PdHx
Authors: Goltsova M. V. , Zhirov I. G. , Nazarov D. A.
Published: October 2018

There was analyzed videotape recording of palladium plate bending during its one-side saturation with hydrogen in experimental conditions of isothermal temperature 130 °С, step hydrogening up to РН2 = 0,01МPа, 0,033, 0,05 МPа. For experiments pure palladium plate of (68×5,5×0,27) mm size electrolytically covered with copper was used as well as specially constructed hydrogen vacuum device. It is shown, that palladium plate bending processes in two stages. In the first stage it is very intensive and quickly reaches values much more than plates thickness. In the second stage the plate is returning to initial state but fixing a small residual form changing. The second stage is much more slow than the first one. Repeated hydrogening lead to a decrease in the maximum bending of the plate. It is shown that the bending is caused by internal stresses induced by hydrogen concentration gradients but the responsibility of such a behavior possessed by temporarily existing gradient material Pd-PdHx. In the first moments of saturation the layer of PdHx is formed in palladium subsurface layers and a side near copper is free from hydrogen. As hydrogen concentration in plate becomes equal through the plate thickness, the plate returns to initial form.

There were calculated parameters of temporarily existing gradient material Pd-PdHх in frames of model discussed. Results of the work are of interest for development of hydrogen sensors.
Guest Editorial: Putting the Power Into Empowerment To Drive Digitalization
Authors: Heilmann Matthias
Published: October 2018

Guest editorial

It is time to put a common misconception to rest. The oil and gas industry is not lagging behind other industrial sectors in the race toward digitalization. We are leading the charge. This confidence is born from our status as one of the earliest adopters of digital technologies to efficiently transform complex reservoirs into revenues.

However, two things have happened since our industry first started adopting digital in its original form several decades ago. First, oil and gas businesses are experiencing new pressures from the downturn, which has placed increased focus on productivity and the navigation of diverse energy dynamics. Second, the Industrial Internet of Things (IoT) or Digital 4.0 technologies have developed at an increasing rate, with the democratization of cloud computing and the advancements in data analytics, artificial intelligence (AI), and machine learning creating new opportunities beyond the consumer space. The resulting environment is one in which the oil and gas industry must consider the role these new digital technologies will play in navigating shifting industry dynamics.

While the industry is at a prime point, testing and beginning to put to work new digital ideas, the draw to return to age-old, tried and tested methods can be tempting. Unlike vehicle manufacturing, we are truly a process-driven industry where simulation, data measurement, and modeling are at the core of everything oil and gas does because everything is connected. We must move forward to adopt industrial IoT technologies that optimize across assets, processes, people, production, and the reservoir and wells by delivering answers in real time. Harnessing data that have been stranded will improve reliability, optimize production, and transform overall operations beyond what existing, siloed software solutions were able to deliver.

The value in data analytics at scale across an enterprise is visualization of historical and real-time performance across an entire business, from the reservoir and well to the refinery. Connecting digital across oil and gas businesses will be a key topic at the inaugural ENGenious conference and exhibition taking place in Aberdeen, 4–6 September 2018. Four key pillars of activity will be on the agenda: data analytics, automation and control systems, robotics, and smart communications. While the event will explore what innovation means for the onshore and offshore upstream oil and gas industry, it will embrace the learnings and experiences from a diverse range of industries. Using an ecosystem approach, this will create an enlightening forum to encourage cross-pollination of ideas and information exchange.
Can Putting Blockchain on Drilling Rigs Really Get Everyone on the Same Screen?
Authors: Rassenfoss Stephen
Published: October 2018

When Diamond Offshore Drilling announced that it will be equipping its offshore drilling rigs with blockchain, the calls started coming.

“I was shocked by the response on the first 4 days,” said Harris Reynolds, manager for research and development for Diamond Offshore. The reaction exceeded anything he had seen in more than 3 decades of product development.

The level of interest was surprising in an industry where customers are normally wary of new things until totally proven. Blockchain for drilling is an industry-first based on technology from outside the oil and gas industry that has never been field-tested, and will be valuable only if it disrupts how things are done.

The last point actually may be a positive. The hope is that blockchain can open the door to significant cost reductions by putting everyone on the same screen. The software created in partnership with a pioneer in that field, Data Gumbo, creates a common view of the plan, predicted costs, progress, and performance of everyone working in an offshore project, among many things.

While a drilling company took the initiative looking for a competitive edge, it was built for use by operating companies that will define how this tool will be used. Diamond is seeking initial users of its blockchain service, which it plans to install on its most advanced drilling rigs by year end and eventually on its entire fleet.

“We are just one part of the spread, a fraction of that,” said Reynolds, adding that the company is trying to speed an advance in the industry, which it expects will become common in a few years.

Blockchain’s claim to fame is the software used to record who owns Bitcoin. The safeguards built into the system create an “immutable ledger” of those who create Bitcoin and the parties involved when the crypto currency changes hands. That makes it possible to track a chain of ownership that can be audited.

In oil and gas, the goal is to use an industrial version of the software to create a common account of things that are tracked now using a variety of tools such as relational databases or spreadsheets. Blockchain descriptions often refer to these as ledgers. The problem is the numbers often vary, reflecting different points of view and different record-keeping systems.

“That is the thing. Their accounting software and my accounting system have got different records of what happened,” said Andrew Bruce, chief executive officer for Data Gumbo. Opportunities are missed because “data is out there but it is on an island,” Reynolds said.

The system creates a constantly updated chain of blocks, which cannot be altered, recording facts on a  certain topic. With blockchain, Bruce said, “everybody gets a record and there is no room for dispute.”
Downhole Plunger Speed Study in Sucker Rod High GOR and High Friction Wells
Authors: Ferrigno E.. , El Khouri D.. , Moreno G..
Published: October 2018

This work arises from the comprehensive study of a park of 50 wells with artificial lift pumping systems. These have intelligent well controllers and telemetry systems with downhole calculation modules deriving from the processing of dynamometry and surface production data.

In both controllers and telemetry software, dynamometer cards are processed using wave equation algorithms applied to vertical wells. These calculation methods do not consider the effects of Columbian frictions in deviated wells.

The aim of the study was to compare the dynamometer cards obtained using controllers and telemetry with other external softwares that do consider Coloumbian frictions and their effects in deviated wells. The goal was to assess whether, despite the limitations of the analysis, the results were acceptable to determine conditions of fluid pound, run algorithms to control pump filling, and to analyze Goodman diagram applied to sucker rods. Thus, it is possible to describe the scope of the technology available in the field to optimize wells in real time and to provide an operational diagnostic.

Within the framework of the above-mentioned study, and as part of the need to understand the high rate of early faults observed in wells, advanced studies of speed and cycle times of pump strokes were conducted. This paper focuses on the specific findings obtained as regards this topic.
Solving Gas Interference Issues with Sucker Rod Pumps in the Permian Basin
Authors: Allison A. P. , Leal C. F. , Boland M. R.
Published: October 2018

Gas/liquid ratios (GLRs) typically increase later in the life of a sucker rod-pumped well, and unconventional reservoirs may have high GLRs from the beginning of production. How to handle that gas production is important for sucker rod pumps, as the efficiency is reduced when gas enters the pump. A project was undertaken to quantify several methods used to handle gas production with sucker rod pumps and the effectiveness of each.

This project focused on three areas of design or operation intended to improve gas handling: Gas separator design: The sizing of downhole gas separators was reviewed, and steps were taken to match the pumping system with the proper separator. In cases where the separator was not pulled, the pump displacement was adjusted to ensure it was within the capacity of the existing separator. Where there was an opportunity to replace the separator, the design was modified to ensure the separator capacity matched the expected well production.Variable speed drives: Horizontal wells do not provide consistent inflow, but rather exhibit slugging behavior as portions of the lateral load up with liquid or gas. This makes pump-off control difficult with conventional rod pump controllers, which stop the pump completely when there is a lack of fluid at the pump. The performance of variable speed drives was studied to determine if continuous operation while adjusting the speed to accommodate slugging would improve production.Backpressure valves: Backpressure has been used as a method to improve the performance of wells with gas interference, but the benefits have been questionable compared to the negative impacts on equipment loading. Wells with elevated tubing backpressure were identified, the backpressure was reduced to line pressure, and the impact on performance was monitored.
Production Optimization for Progressive Cavity Pumps by Interconnecting a Steady-State Flow Simulator and a Black Oil Reservoir Model through Integrated Asset Management Software
Authors: Ali Maaz , Salinas Veronica , Cui Shihao
Published: October 2018

At a time when oilfield economics call for the most optimized strategies to produce a field or set of wells, reservoir understanding and artificial lift technologies merge as one combined solution to provide top-of-the-class analyses for optimized production and economic success for very challenging projects. One of the most critical aspects related to the economics of the production life cycle is the maximization of net present value (NPV). This becomes even more relevant for wells that have high capital investment and expensive operating costs.

The objective of this paper is to describe the simulation workflow developed to integrate the interactive response of the reservoir as a response to the drawdown induced when artificial lift is placed within a well. Based on the reservoir response, artificial lift operational parameters can be adjusted at each step to maximize the total NPV for a group of wells in a field located in the Middle East. Sample data describes a case of five wells connected to the same facility and completed with progressing cavity pumps (PCPs).

The individual wellbores containing the PCPs were simulated using a steady-state multiphase flow simulator. Single-well models were used to feed the surface network model with flow lines, chokes and a separator. At the reservoir level, a reservoir model for each well was created using a black oil simulator. The use of an integrated asset modeler enabled automated interaction among single models, network model and reservoir models, allowing the creation of an optimization workflow. The integrated asset management software optimized PCP speed for each of the five wellbores to maximize oil recovery, delay water onset and maximize NPV of the field for one year. The optimizer also had to consider several constraints at both the wellbore and surface facility level. Minimum bottomhole pressures needed to be maintained throughout the simulation to prevent the reservoir from depleting prematurely. Water production also had to be limited to match surface handling capacities. Finally, PCPs needed to be constrained based on a maximum operating speed and maximum horsepower consumption.

The workflow created effectively integrated reservoir modeling with artificial lift performance to deliver an optimized operational sequence for the case study, presenting as results PCP speeds and NPV per month. The results of the simulation showed the potential to increase the NPV and oil production by 10.5% and 9.5% respectively. Furthermore, the current workflow is flexible enough to be extended to other forms of artificial lift and has the potential to fully optimize and evaluate complete fields.
SRP Equipment Customization Creating Value by Increasing Run Life in a Low Oil Price Environment
Authors: Hoy M.. , Kometer B.. , Bürßner P.. , Puscalau G.. , Eder S..
Published: October 2018

This paper describes the measures undertaken to increase the run life of sucker rod pump (SRP) installations in the past five years in OMV Austria. Around 500 wells are currently operated with SRPs with an average water cut of 95%. Recurrent pump failures, caused by corrosion, mechanical wear, gas and sand production, significantly contribute to the operating expenditures of a mature oil field operator.

In the current low oil price environment the key strategy for economic oil production is seen in efficient low cost production optimization of the subsurface pump equipment. The primary objective was to reduce the life cycle cost (LCC) and deferred production - however, also the increase of production efficiency is an appreciated secondary effect.

Consequently, the failure analysis was completely revised and historic data was fed into a new database. A new process was implemented - starting with equipment details, determination of both failure cause and reason and resulting in a ranking for a detailed root cause analysis.

The results obtained from the failure analysis led to a profound understanding and rendered a prioritization of necessary actions possible. The optimization measures include design modifications, a stricter quality assurance of new pumps, material upgrades and special pump parts for the respective production environment. In addition an economic assessment of the LCC was conducted in order to quantify the cost impact of pump optimization.

The new failure statistic highlights the importance of certain failure modes. Accordingly the necessary pump upgrades were ranked, analyzed and successively executed. The continuous study already shows a change of failure proportions and furthermore improved the in-house knowledge.

Even though deploying SRPs for more than 60 years, a structured failure analysis led to new insights of material weaknesses. The introduction of non-API special parts allowed the customization of standard pumps in order to fit to the actual production environment and significantly enlarged the application area of SRPs. In-house material technology center and research laboratory offered valuable information for the root cause analysis. This created the basis for a stricter material specification than demanded by the API 11AX to avoid recurrent systematic failures.
Life-of-Well Gas Lift Installations for Unconventional Resources
Authors: Latif Bilal , McKenzie K. S. , Rodgers W. M , Stephenson G. B. , Wildman S. L.
Published: October 2018

In unconventional shale plays, the production profile varies dramatically within an extremely short period of time. Wells often produce at extremely high rates when initially completed and deplete rapidly before reaching production plateaus. This rapidly changing production profile presents a significant challenge to engineers designing artificial lift systems. Because of the method's flexibility and tolerance to a variety of producing conditions, gas lift has become a popular artificial lift choice in these wells.

To achieve optimal system performance, engineers often design gas lift installations to produce up the casing early in the well's life. This configuration minimizes pressure losses in the production string, enabling deep injection, improved drawdown, and higher flow rates. As the wells deplete and the production rates decline, the wells must be converted to tubing flow to ensure well stability. As the wells further deplete, they are often converted to intermittent gas lift. Unfortunately, it is not feasible to produce wells with tubing flow gas lift or intermittent gas lift with the typical downhole equipment configuration used in annulus flow wells. Therefore, transitioning to these late-life artificial lift configurations has required a workover rig.

A novel downhole equipment configuration was developed to eliminate the need for a workover rig when transitioning from annulus flow to tubing flow gas lift. Side-pocket mandrels with a special pocket porting configuration were selected to enable annulus flow with enhanced gas passage early in the well's life. To transition from annulus flow to tubing flow, the slickline-retrievable valves were pulled and replaced with reverse-flow gas lift valves. A field trial was conducted to demonstrate and test this completion concept. While more investigation is required to justify full field implementation, the initial results have been promising.

This project demonstrated that it is feasible to produce wells in annulus flow, tubing flow, and even intermittent gas lift with a single completion using readily available, off-the-shelf artificial lift equipment.
Acquisition of Downhole Pressures without Downhole Gauges in the Gulf of Thailand via the Self-Powered Intelligent Data Retriever
Authors: Pattarachupong Wiwat , Piyakunkiat Nuttapon , Ananwattanasuk Thongchai , Sirirattanachatchawan Thum , Sompopsart Suwin , Toempromraj Wararit , Koseluk David , Finley Douglas , Redman Michael , Wattanasuwankorn Reawat
Published: October 2018

Bottomhole pressure is one of the most important sources of data used to determine reservoir characteristics. By analyzing the manner in which bottomhole pressures change with time and flow rate, properties can be derived such as permeability, skin, boundaries, and reservoir pressure, which can enable the evaluation of hydrocarbon reserves and make economically feasible decisions. Downhole pressure data in production wells are most commonly acquired by running downhole pressure gauges on slickline into the wellbore. However, in offshore wells in remote locations, there can be major deterrents to capturing bottomhole pressures using slickline. Examples of these limitations include equipment and manpower availability, crane functionality, and offshore accommodations. Furthermore, there can be physical limitations to data acquisition from the presence of sour gas, high bottomhole temperatures, high wellbore deviation, or mechanical obstructions that can prevent the use of downhole gauges in the well. This paper presents an innovative method for acquiring the needed bottomhole pressures in production wells when traditionally used methods may present challenges.

An operator in the Gulf of Thailand wanted to obtain downhole pressures on their production wells but did not wish to run slickline and downhole gauges because of the concerns specified above. A new self-powered intelligent data-retriever system was suggested to the operator as it offered a method that could derive accurate bottomhole pressures without running downhole gauges. The new system consists of a high accuracy, high resolution pressure gauge and a companion bottomhole pressure conversion algorithm. The pressure gauge is installed on the wellhead and captures high-frequency surface-pressure data. The conversion algorithm uses the surface pressure data, along with wellbore information, and fluid properties to calculate downhole pressures.

The results of a series of tests with the self-powered intelligent data-retriever system demonstrated that the system can provide accurate bottomhole pressure results in production wells. These facts will be verified by the test results as well as the case history, both of which will be presented in this paper.

This technology was designed to reduce the cost of capturing downhole pressure data, lessen many of the logistical concerns that could occur when using traditional systems, eliminate the risks of a downhole gauge getting stuck in the wellbore, and acquire necessary data when downhole environments are corrosive.
A New Fatigue Management Workflow for BHA Integrity Risk Reduction
Authors: Suryadi Hendrik
Published: October 2018

Our industry continues drilling more challenging wells - deeper and higher dogleg severity (DLS). Bottom Hole Assemblies (BHAs) have also become more complex and required to sustain higher loads. The current design and engineering practices still rely on prevention mechanical overload which based on calculated maximum stress versus component material yield strength. While fatigue failure is well known and recognized as the primary cause of component twist-offs downhole, but there still limited approach to prevent it during planning phases such as BHA design, execution monitoring, and evaluation. The industry still relies on inspection and traditional cumulative pumping hours tracking as a preventive action against fatigue failure.

Fatigue damage consists of two stages, crack initiation and crack propagation, with crack initiation accounting for most of the total life. Rotating bending is the driving force for fatigue cracking. It induces cyclic stresses and strains at the stress risers, which are the fatigue-critical features. Fatigue data can be presented in the form of S-N curves, where S is the applied bending stress and N is the total life in a number of cycles. An advancement in BHA modeling with the capability of finer detailed finite element modeling of drilling tool component allows for accurate calculation of BHA bending moment distribution. Given a bending moment, the cyclic stresses and strains at the most critical feature of the most critical BHA component can be determined. The life of the most critical component can then be calculated with the stress-life or strain-life curve of the collar material. This governs the life of the entire BHA.

This paper will present the development of new approach on fatigue management workflow which includes bending moment & stress analysis based BHA design, fatigue life prediction and sensitivity analysis during planning and execution monitoring on consumed fatigue life, including job tracking to component maintenance system. The paper will also discuss the accelerated cumulative fatigue due to shock & vibration.

A fatigue management workflow has been created for planning, execution monitoring, and post-job evaluation phases. During planning, the engineer can calculate the expected fatigue life of the BHA and optimize for the expected duration of the job. The result can be used to select reliable components with sufficient fatigue life for the job. While drilling, this method enables the engineer to continuously monitor the consumed fatigue life of any BHA component and make the decision to replace the tool before a failure occurs downhole. After the job, the consumed life can be recorded in the maintenance system to track the remaining life and decide what preventive maintenance is required.

The new modeling approach enables the drilling engineer to optimize performance and managing BHA integrity risk.
Application of Velocity String to Improve Productivity from Bottom pays after Hydraulic Fracturing in Multilayered Low Permeability Reservoir
Authors: Anand Saurabh , Johri Nitin , Chandak Krishana , Vijay Rachit , Tiwari Shobhit , Bohra Avinash , Vijayvargiya Utkarsh , Khemchandani Jivesh , Singh Ishaan , Agarwal Arpit
Published: October 2018

Raageshwari gas field is located in RJ-ON 90/1 Block in western India with Cairn Oil & Gas, a vertical of Vedanta Limited as operator of the field. Multistage hydraulic fracturing is required to achieve commercial production from the highly laminated retrograde gas condensate reservoir. It has been observed in almost all wells that the top high PI zones produce a majority of the gas. The wells have a water column across bottom few fracs which prohibits production from these zones. Water unloading through increased drawdown was not successful because of higher PI of the upper fracs. Coiled tubing-based nitrogen lift of the water column is not commercially feasible. It is important to find a low-cost solution for water unloading since bottom zones account for approximately 30% of total gas in place. A solution has been developed using a customized velocity string design, which can unload the water while maintaining high well production.

Conventional velocity strings are only installed in late life of gas wells when liquid loading is observed. These conventional designs limit the maximum rate to 2-3 MMSCFD and therefore cannot be used in Raageshwari gas field for water unloading as high individual well rates (8 to 12 MMSCFD) is required to meet field plateau production. After reviewing various options, an innovative and unique velocity string system design was developed which incorporates a customized surface spool and string hanging system. This customized design allows combined or independent gas flow conduits as described below:

Through the annulus of velocity string and tubing when higher gas rates are required. Through the velocity string to facilitate liquid unloading due to high gas velocity. Production from both the conduits to meet higher demands than the annulus flow alone.

Well integrity was assured by maintaining two independent barriers during commissioning, production phase and also during future string retrieval.

This paper will discuss in detail the design considerations of the velocity string and surface hanger system to achieve liquid unloading while maintaining high rate gas production. It will also have details on the dual barrier selection process and the design customization that have been done to ensure cyclic liquid unloading and high rate gas production.

This innovative velocity string design is technically a dual completion with a much lower cost and footprint. The same design can be implemented across a wide variety of applications to address well integrity issues, selective zonal production etc. The application of this design in Raageshwari field will ensure planned recovery of gas from the field and will also support plateau production phase. This design can be an efficient and economic technique to develop similar fields.
Design Optimization from 3 Strings to 2 Strings for Deep Wells in Sirikit Field
Authors: Tangkaprasert Phakphum , Rattanachan Sarit , Watchalapong Pimaroon
Published: October 2018

Oil and gas industry continues to increasing demand of more cost-effective well design and operations. Thus, PTTEP Thai onshore drilling team response to the mission by enhancing well design of deep wells in Sirikit Field from three strings to two strings well. This optimization not only reduce cost per well but also unlock reserve in deeper section which used to be uneconomic.

To implement two strings design for deep wells with long open hole section (more than 2,000 mMD), there are key challenges which has to be overcome as per listed below;

Directional control issue Higher torque, drag and side force Difficulty for wireline logging and casing running operation Formation stability and lost circulation Revised Casing Design

To overcome these challenges, not only suite of tools and technologies have to be studied and field proven but drilling practice also has to be reviewed. Risk assessment and feasibility study has been conducted to ensure that this design optimization would results in positive outcome

Since the first implementation in 2015, more than 50 wells have been successfully drilled and completed. The longest open hole section of 2,899.3 mMD with TD of 4,202 mMD has been achieved and average cost saving of more than 25% per well has been realized. Below list the technology applied to overcome challenges;

All targets have been penetrates without directional control issue using Rotary Steerable System (RSS). High drilling torque have been mitigated using high torque drill pipe and torque reduction tools. Reamer and back-reaming out of hole have been used to smoothen wellbore which facilitate wireline logging and casing running operation. Eccentric casing shoe and low-friction centralizers have been used to further aid running casing in high angle wells. High drilling fluid weight has been used in advance to combat formations stability issue. Hence, lost circulation materials (LCMs) have been prepared to mitigate loss circulation due to high ECD. Polymer based spacer system have been used for the wells which have potential of lost circulations while cementing.
BD Gas Field Near-HPHT and Critical Sour Development: A Journey to Maintain Well Integrity
Authors: Tian Yi , Yustendi Kiki , Lian Jihong , Etuhoko Michael , Soufanny Alfon , Jiang Kai , Luo Limin , Xiang Ming , Chang Congbing , Diemert Anthony Paul
Published: October 2018

BD Gas Field is located in offshore in the Madura Strait, Indonesia, and has a total of four producing wells - one vertical (Well Y1) and three horizontal (Well Y2, Well Y3, and Well Y4) from an unmanned platform. Its reservoir was considered near HPHT and critical sour with 8,100 psi bottom hole pressure, 300°F bottom hole temperature, 5.5% CO2 and 5,000 ppm H2S. This paper highlights on the Company journey to maintain well integrity during well design phase, well construction phase, and production phase of BD Gas Field.

During well design phase, material selection and design for 9-5/8 in. intermediate casing, 7 in. production casing, and 4-1/2 in. tubing were based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Cementing design for 7 in. production casing cement was tested and analyzed in the laboratory for 60 days in the HPHT chamber simulating reservoir properties. Top of cement was designed to the mud line to minimize wellhead growth. Completion design was monobore type and divided into lower, intermediate, and upper completion strings. All packers were V-0 (zero bubble) rating.

Maintaining well integrity during well construction phase was challenging. Batch drilling and completion was applied, and at all times, the wells were required to be suspended with proper and adequate barriers. During drilling and well clean-up phase, inter-casing pressure management (i.e., annulus pressure, wellhead growth monitoring, bleed off program, etc.) was implemented to maintain the casing and tubing integrity.

During production phase, routine wellhead growth measurement, constant monitoring and bleed off program were developed and communicated with related departments. Pressure control valves and alarm system were installed and tested to the annulus.

In additional to the wellhead growth, transverse wellhead movement was observed in one of the wells especially during rough sea conditions. In order to reduce the tranverse wellhead movement which may induce more stress on the surface pipings and connections, it was planned to install under water shims in between the conductor pipe and platform jacket guide funnel.

Some surface piping and platform modification were also considered because wellhead growth leads to limitations on gas production to prevent safety issues.
Evaluation of Relative Permeability Modifiers in Sand-Control Applications: Case History, Results, and Improvements
Authors: Choodesh Attawit , Graham Grant Colin William , Wuthicharn Katha , Ramirez Cristian , Nusyirwan Ahmad , Santoso Doffie Cahyanto
Published: October 2018

Typical sand-control treatments applied in this field are high-rate water packs (HRWPs) or fracture for placement of proppant (FPP). In many cases, the use of a pad is necessary to maximize the amount of proppant placed into the formation and help reduce (bypass) overall skin using onsite data analysis. The gravel pack carrier fluid is a viscosified system with shear-thinning rheological properties and efficiently suspends sand in static conditions. Additionally, this fluid allows substantial flexibility in sand control design for varying degrees of sand support for gravel packing, fluid-loss control, friction-pressure reduction, and a low-damage fluid system (validated with extensive laboratory testing using reservoir cores with carrier fluid to validate returned permeability values).

The objective of the relative permeability modifier (RPM) in sand-control chemical treatments is to prolong hydrocarbon production over time with effective control of water production in one step as a prepad fluid, eliminating the cost and complexity of the water-shutoff treatment stage later as part of well life.

Applying the RPM process has not only reduced water production in these areas, but it has also resulted in more gas cumulative production. It is also important to monitor production for several months after the treatment to determine the success or failure of the application.

Globally, this is the first successful application of RPM delivery in the same aqueous gravel-packing carrier fluid system using a pad fluid consisting of high-grade xanthan polymer as a gelling agent. Implementation of this process provides the operator an additional tool to increase the possibility of hydrocarbon production from a reservoir that has not been considered viable. Use of RPM technique in sand-control completions provides the option to treat wells and control water production resulting from nearby GWC after sand-control treatments.
Thailand Joint Development Project Delivers 200°C M/LWD Triple Combo: Eliminating Wireline, Driving World Class Efficiency and Slashing Days Per Well
Authors: Kleawyothatis T. , Pruimboom J. , Dendandome S. , Pisarnbut N. , Thipmongkolsilp P.
Published: October 2018

There is no longer a requirement to run wireline Triple Combo logs in deep, high temperature wells. A joint development project has successfully delivered the world's first high-temperature M/LWD Triple Combo suite rated for 200°C [392°F]. Results to date are compared with previous performance in the Gulf of Thailand (GoT).

The new suite required a ground-up redesign of printed circuit board (PCB) electronics in order to meet the temperature qualification criteria of 200 hours at 200°C [392°F], with a survivability of 210°C [410°F] for four hours. The suite's sensors were developed in two phases, each with four milestones, over a period of 36 months. Initial rigorous thermal qualification was followed by harsh thermal vibration qualification testing routines. Several PCB redesigns were required in order to finally pass this testing. Ultimately, five prototype triple combo suites of tools were delivered to Thailand, on time and on budget, for in-situ field testing.

M/LWD Triple Combo field trials commenced offshore in the GOT, in fields exhibiting some of the global industry's most demanding drilling environments with respect to high rates of penetration [and accompanying punishing levels of vibration], extreme temperatures and significant well complexity. Compared to adjacent platforms with similar wells in the most challenging field, the new suite, together with other drilling efficiency measures, played a pivotal role in helping to reduce average days per well over 50% a considerable improvement. To date, more than 475,000 ft [145,000 m] have now been drilled in 71 GoT wells using this Triple Combo M/LWD technology. Furthermore, the new high-temperature Triple Combo M/LWD tools have been one of several key contributing factors in establishing two notable drilling records: drilling the GoT's longest well at 17,559 ft [5,532 m] and the longest single-bit run in the production section at 8,952 ft [2,729 m], without any failures at a maximum temperature of 199°C [391°F]. The suite provides additional benefits such as the provision of real-time annular pressure while drilling.

With this feature, engineers can closely monitor the equivalent circulating density (ECD) an important parameter for avoiding kicks and losses at up to 200°C [392°F].

The proven step change in drilling efficiency arising from this joint development can be attributed to the elimination of temperature mitigation measures and Triple Combo wireline logging, the problems associated with acquiring the wireline data, and an overall improvement in drilling practices.