This document describes a System Cost Analysis (SCA) methodology used to quantify the total costs of drilling fluids beyond just material costs. An SCA considers costs from lost time due to problems like lost circulation, as well as impacts on rate of penetration. The analysis equates all incidents affecting cost to dollars. Two examples are provided: one comparing water-based and oil-based fluids in Western Canada found inhibited potassium-based fluids most effective; another comparing drilling fluid systems in Ecuador found a KNO3-based fluid improved rates of penetration and reduced solids control costs. The SCA provides a framework to measure drilling fluid performance and identify opportunities to reduce costs.
PIOGA/MSC Observations/Questions on PA DEP Radiation in Shale Drilling StudyMarcellus Drilling News
A document produced in August 2013 jointly by the Marcellus Shale Coalition (MSC) and the Pennsylvania Independent Oil and Gas Association (PIOGA) questioning some of the criteria and scope of a proposed study now under way and being conducted by the PA Dept. of Environmental Protection (DEP). The DEP is studying the extent and scope of radiation in shale drilling waste, and whether or not they need to establish regulatory standards to control it.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technol...ASC-HRSC
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technologies
This presentation was given at the AEHS 33rd Annual International Conference on Soils, Sediments, Water, and Energy on October 18, 2017, at UMASS, Amherst, Massachusetts
http://www.aehsfoundation.org/east-coast-conference.aspx
Session 15: Synergistic Remediation Technology Solutions
Day: Wednesday, October 18, 2017
Time: 1:30 PM - 5:00 PM
Location: Room 168
Session Type: Platform Session
PIOGA/MSC Observations/Questions on PA DEP Radiation in Shale Drilling StudyMarcellus Drilling News
A document produced in August 2013 jointly by the Marcellus Shale Coalition (MSC) and the Pennsylvania Independent Oil and Gas Association (PIOGA) questioning some of the criteria and scope of a proposed study now under way and being conducted by the PA Dept. of Environmental Protection (DEP). The DEP is studying the extent and scope of radiation in shale drilling waste, and whether or not they need to establish regulatory standards to control it.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technol...ASC-HRSC
Improving Remedial Actions Through Integrated Use of Direct-Push HRSC Technologies
This presentation was given at the AEHS 33rd Annual International Conference on Soils, Sediments, Water, and Energy on October 18, 2017, at UMASS, Amherst, Massachusetts
http://www.aehsfoundation.org/east-coast-conference.aspx
Session 15: Synergistic Remediation Technology Solutions
Day: Wednesday, October 18, 2017
Time: 1:30 PM - 5:00 PM
Location: Room 168
Session Type: Platform Session
A mathematical modeling proposal for a Multiple Tasks Periodic Capacitated Ar...IJERA Editor
The countless accidents and incidents occurred at dams at the last years, propelled the development of politics
related with dams safety. One of the strategies is related to the plan for instrumentation and monitoring of dams.
The monitoring demands from the technical team the reading of the auscultation data, in order to periodically
monitor the dam. The monitoring plan of the dam can be modeled as a problem of mathematical program of the
periodical capacitated arcs routing program (PCARP). The PCARP is considered as a generalization of the
classic problem of routing in capacitated arcs (CARP) due to two characteristics: 1) Planning period larger than
a time unity, as that vehicle make several travels and; 2) frequency of associated visits to the arcs to be serviced
over the planning horizon. For the dam's monitoring problem studied in this work, the frequent visits, along the
time horizon, it is not associated to the arc, but to the instrument with which is intended to collect the data.
Shows a new problem of Multiple tasks Periodic Capacitated Arc Routing Problem and its elaboration as an
exact mathematical model. The new main characteristics presented are: multiple tasks to be performed on each
edge or edges; different frequencies to accomplish each of the tasks; heterogeneous fleet; and flexibility for
more than one vehicle passing through the same edge at the same day. The mathematical model was
implemented and examples were generated randomly for the proposed model's validation.
Use of GCxGC-TOFMS in litigious mixed condensate plumes: Environmental forens...Chemistry Matters Inc.
Authors: Court D. Sandau and Lisa N. Kates
Chemistry Matters Inc.
Abstract; Condensate is a complex mixture of light petroleum hydrocarbons that is primarily used to dilute heavy crude oil for transport through pipelines. Many heavy oils, especially bitumen from the oil sands in northern Alberta, use condensate to dilute the bitumen to allow the product to flow to refineries where the oil can be upgraded. This is where the term ‘Dilbit’ was derived. Condensate is valuable; it can be recycled and reused and is frequently transported through the North American pipeline network. Pipelines gather at pipeline terminals where there can be multiple sources and multiple suppliers of different types of condensates. When leaks occur at these terminals, it can be difficult to determine the exact source of the leak, especially if pipeline integrity seems intact. GCxGC-TOFMS is the ideal technique to examine mixed condensate plumes as it allows the comprehensive fingerprint of the condensate to be determined and simultaneously provides substantial data to evaluate weathering and plume movement. In addition, the amount of chemicals measured using GCxGC-TOFMS can allow source apportionment of multiple sources so that allocation of the cleanup responsibility can be made. This presentation will discuss the use of GCxGC-TOFMS in legal case studies involving mixed condensate plumes. Real scenarios of condensate plumes will be presented showing how GCxGC-TOFMS data clarified the results compared to conventional analysis. This presentation will also cover the hurdles of using a novel and unconventional technique for litigation proceedings.
UntitledExcessive Water Production Diagnostic and Control - Case Study Jake O...Mohanned Mahjoup
For mature fields, Excessive water production is a complex subject in the oil and gas industries and has a serious economic and environmental impact. Some argue that oil industry is effectively water industry producing oil as a secondary output. Therefore, it is important to realize the different mechanisms that causing water production to better evaluate existing situation and design the optimum solution for the problem. This paper presents the water production and management situation in Jake oilfield in the southeast of Sudan; a cumulative of 14 MMBbl of water was produced till the end of 2014, without actual plan for water management in the field, only conventional shut-off methods have been tested with no success. Based on field production data and the previously applied techniques, this work identified the sources of water problems and attempts to initialize a strategy for controlling the excessive water production in the field. The production data were analyzed and a series of diagnostic plots were presented and compared with Chan’s standard diagnostic plot. As a result, distinction between channeling and conning for each well was identified; the work shows that channeling is the main reason for water production in wells with high permeability sandstone zone while conning appears only in two wells. Finally, the wells were classified according to a risk factor and selections of the candidate wells for water shut off were presented.
Cost (& Time) Optimization of Hydrogeological StudiesGidahatari Agua
Cost optimization has to identify the most common problems to the hydrogeological investigation as travel time and transport issues, seasonal restrictions, personal availability, protocols, etc. This post is focused on strategies and best practices for cost (& time) optimization, specially for hydrogeological investigation on mining projects.
Quick tutorial of how to conduct a bridge scour computation within HECRAS. Characteristics of stream stability fundamentals are also discussed. Abutment, pier, and contraction methodologies from HEC 18 are summarized. Tips to avoid common mistakes are provided. Helpful data sources to assist design are suggested.
Liquid & Gas Flowmetering & Custody MeasurementpetroEDGE
This course will familiarize process, instrumentation and custody transfer engineers with the procedures and practices involved in the choice of flowmetering systems and their associated supporting equipment. It will address these points in relation to both single- and multi-phase flows and will give guidance on the optimum commercially available flowmeters through a detailed comparison of their relative merits. Flowmeter calibration is crucial to these topics.
The course also covers the related issues of level and tank measurement as well as lease automatic custody transfer and truck custody transfer, leak detection, loss control and monitor and control production losses.
Impact of the Hydrographic Changing in the Open Drains Cross Sections on the ...IJMER
International Journal of Modern Engineering Research (IJMER) is Peer reviewed, online Journal. It serves as an international archival forum of scholarly research related to engineering and science education.
EXPERIMENTAL STUDIES ON THE INTAKE PORT OF A DIESEL ENGINE TO DETERMINE SWIRLijmech
This paper focuses on experimentalstudies of intake port of a four cylinder diesel engine for different
vacuum pressures and valve lift positions. In this study, the cylinder head is experimented through a paddle
wheel flow setup, which gives the flow coefficient and swirl number asoutput. Main scope of the work is to
understand the flow behaviour through the intake port and finally to determine mean flow coefficient and
mean swirl number for different valve lift ratios L/D, where L is valve lift and D is bore diameter.
[Oil & Gas White Paper] Getting Ahead of the Game: adopting best practices in...Schneider Electric
Burgeoning energy exploration is driving the construction of pipeline systems for hydrocarbon transportation. For a variety of reasons, including renewed scrutiny on safety by regulators, this is also driving new practices and standards for leak detection.
Computational pipeline monitoring (CPM) systems use real-time information from the field – such as pressure, temperature, viscosity, density, flow rate, product sonic velocity and product interface locations – to estimate the hydraulic behavior of the product being transported and create a computerized simulation. With it, controllers can be alerted to abnormal operating conditions that might signal the existence of a pipeline leak. Different CPM methodologies provide different leak detection capabilities, so different methods, or a combination of methods, might be better applied to different operations.
Selection of the right CPM for a given company or given pipeline relies on the thorough evaluation of several factors, including pipeline characteristics, business objectives, additional risk factors and special safety concerns, such as proximity to environmentally sensitive or urban areas. New standards and industry initiatives provide tools to assist in this evaluation, ensuring the pipeline industry continues to provide efficient, effective and safe hydrocarbon transportation.
A mathematical modeling proposal for a Multiple Tasks Periodic Capacitated Ar...IJERA Editor
The countless accidents and incidents occurred at dams at the last years, propelled the development of politics
related with dams safety. One of the strategies is related to the plan for instrumentation and monitoring of dams.
The monitoring demands from the technical team the reading of the auscultation data, in order to periodically
monitor the dam. The monitoring plan of the dam can be modeled as a problem of mathematical program of the
periodical capacitated arcs routing program (PCARP). The PCARP is considered as a generalization of the
classic problem of routing in capacitated arcs (CARP) due to two characteristics: 1) Planning period larger than
a time unity, as that vehicle make several travels and; 2) frequency of associated visits to the arcs to be serviced
over the planning horizon. For the dam's monitoring problem studied in this work, the frequent visits, along the
time horizon, it is not associated to the arc, but to the instrument with which is intended to collect the data.
Shows a new problem of Multiple tasks Periodic Capacitated Arc Routing Problem and its elaboration as an
exact mathematical model. The new main characteristics presented are: multiple tasks to be performed on each
edge or edges; different frequencies to accomplish each of the tasks; heterogeneous fleet; and flexibility for
more than one vehicle passing through the same edge at the same day. The mathematical model was
implemented and examples were generated randomly for the proposed model's validation.
Use of GCxGC-TOFMS in litigious mixed condensate plumes: Environmental forens...Chemistry Matters Inc.
Authors: Court D. Sandau and Lisa N. Kates
Chemistry Matters Inc.
Abstract; Condensate is a complex mixture of light petroleum hydrocarbons that is primarily used to dilute heavy crude oil for transport through pipelines. Many heavy oils, especially bitumen from the oil sands in northern Alberta, use condensate to dilute the bitumen to allow the product to flow to refineries where the oil can be upgraded. This is where the term ‘Dilbit’ was derived. Condensate is valuable; it can be recycled and reused and is frequently transported through the North American pipeline network. Pipelines gather at pipeline terminals where there can be multiple sources and multiple suppliers of different types of condensates. When leaks occur at these terminals, it can be difficult to determine the exact source of the leak, especially if pipeline integrity seems intact. GCxGC-TOFMS is the ideal technique to examine mixed condensate plumes as it allows the comprehensive fingerprint of the condensate to be determined and simultaneously provides substantial data to evaluate weathering and plume movement. In addition, the amount of chemicals measured using GCxGC-TOFMS can allow source apportionment of multiple sources so that allocation of the cleanup responsibility can be made. This presentation will discuss the use of GCxGC-TOFMS in legal case studies involving mixed condensate plumes. Real scenarios of condensate plumes will be presented showing how GCxGC-TOFMS data clarified the results compared to conventional analysis. This presentation will also cover the hurdles of using a novel and unconventional technique for litigation proceedings.
UntitledExcessive Water Production Diagnostic and Control - Case Study Jake O...Mohanned Mahjoup
For mature fields, Excessive water production is a complex subject in the oil and gas industries and has a serious economic and environmental impact. Some argue that oil industry is effectively water industry producing oil as a secondary output. Therefore, it is important to realize the different mechanisms that causing water production to better evaluate existing situation and design the optimum solution for the problem. This paper presents the water production and management situation in Jake oilfield in the southeast of Sudan; a cumulative of 14 MMBbl of water was produced till the end of 2014, without actual plan for water management in the field, only conventional shut-off methods have been tested with no success. Based on field production data and the previously applied techniques, this work identified the sources of water problems and attempts to initialize a strategy for controlling the excessive water production in the field. The production data were analyzed and a series of diagnostic plots were presented and compared with Chan’s standard diagnostic plot. As a result, distinction between channeling and conning for each well was identified; the work shows that channeling is the main reason for water production in wells with high permeability sandstone zone while conning appears only in two wells. Finally, the wells were classified according to a risk factor and selections of the candidate wells for water shut off were presented.
Cost (& Time) Optimization of Hydrogeological StudiesGidahatari Agua
Cost optimization has to identify the most common problems to the hydrogeological investigation as travel time and transport issues, seasonal restrictions, personal availability, protocols, etc. This post is focused on strategies and best practices for cost (& time) optimization, specially for hydrogeological investigation on mining projects.
Quick tutorial of how to conduct a bridge scour computation within HECRAS. Characteristics of stream stability fundamentals are also discussed. Abutment, pier, and contraction methodologies from HEC 18 are summarized. Tips to avoid common mistakes are provided. Helpful data sources to assist design are suggested.
Liquid & Gas Flowmetering & Custody MeasurementpetroEDGE
This course will familiarize process, instrumentation and custody transfer engineers with the procedures and practices involved in the choice of flowmetering systems and their associated supporting equipment. It will address these points in relation to both single- and multi-phase flows and will give guidance on the optimum commercially available flowmeters through a detailed comparison of their relative merits. Flowmeter calibration is crucial to these topics.
The course also covers the related issues of level and tank measurement as well as lease automatic custody transfer and truck custody transfer, leak detection, loss control and monitor and control production losses.
Impact of the Hydrographic Changing in the Open Drains Cross Sections on the ...IJMER
International Journal of Modern Engineering Research (IJMER) is Peer reviewed, online Journal. It serves as an international archival forum of scholarly research related to engineering and science education.
EXPERIMENTAL STUDIES ON THE INTAKE PORT OF A DIESEL ENGINE TO DETERMINE SWIRLijmech
This paper focuses on experimentalstudies of intake port of a four cylinder diesel engine for different
vacuum pressures and valve lift positions. In this study, the cylinder head is experimented through a paddle
wheel flow setup, which gives the flow coefficient and swirl number asoutput. Main scope of the work is to
understand the flow behaviour through the intake port and finally to determine mean flow coefficient and
mean swirl number for different valve lift ratios L/D, where L is valve lift and D is bore diameter.
[Oil & Gas White Paper] Getting Ahead of the Game: adopting best practices in...Schneider Electric
Burgeoning energy exploration is driving the construction of pipeline systems for hydrocarbon transportation. For a variety of reasons, including renewed scrutiny on safety by regulators, this is also driving new practices and standards for leak detection.
Computational pipeline monitoring (CPM) systems use real-time information from the field – such as pressure, temperature, viscosity, density, flow rate, product sonic velocity and product interface locations – to estimate the hydraulic behavior of the product being transported and create a computerized simulation. With it, controllers can be alerted to abnormal operating conditions that might signal the existence of a pipeline leak. Different CPM methodologies provide different leak detection capabilities, so different methods, or a combination of methods, might be better applied to different operations.
Selection of the right CPM for a given company or given pipeline relies on the thorough evaluation of several factors, including pipeline characteristics, business objectives, additional risk factors and special safety concerns, such as proximity to environmentally sensitive or urban areas. New standards and industry initiatives provide tools to assist in this evaluation, ensuring the pipeline industry continues to provide efficient, effective and safe hydrocarbon transportation.
At the basis of a good flow measurement is a properly calibrated flowmeter. Field calibration of flowmeters is far from straightforward and its impact on the operation of a metering station in the field can be considerable. One of the options is including a fixed pipe prover in the metering system. For an article that appeared in this month’s edition of World Pipelines, Eveline Janse interviewed Erik Smits (VSL) and Shukur Aghazadeh (AzMETCO), who shone their light on various methods for the calibration of the pipe provers, their advantages and drawbacks.
Reducing Manufacturing Cost through Value Stream MappingEditor IJCATR
To survive in today's competitive world, companies require low costs and high customer service levels. As such,
companies pay more effort to reduce their manufacturing cost. Value stream mapping CVSM) technique has been used on a broad
scale in big companies such as toyato and boeing. This paper considers the implementation of value stream mapping technique in
manufacturing technical spring by railway spring manufacturing company. It focuses on product family, current state map and the
future state map. The aim is to identify waste in the form of non value added activities and processes and than removing them to
improve the performance of the company. Current state map is prepared to describe the existing position and various problem
areas. Future state map is prepared to show the proposed improvement action plans. The achievements of value stream mapping
implementation are reduction in manufacturing cost. It was found that even a small company make significant improvements by
adopting VSM technology. It was concluded that if we adopt the VSM technique the company could reduce the manufacturing
cost from 62.5Cr to 61.88Cr
Courier management system project report.pdfKamal Acharya
It is now-a-days very important for the people to send or receive articles like imported furniture, electronic items, gifts, business goods and the like. People depend vastly on different transport systems which mostly use the manual way of receiving and delivering the articles. There is no way to track the articles till they are received and there is no way to let the customer know what happened in transit, once he booked some articles. In such a situation, we need a system which completely computerizes the cargo activities including time to time tracking of the articles sent. This need is fulfilled by Courier Management System software which is online software for the cargo management people that enables them to receive the goods from a source and send them to a required destination and track their status from time to time.
Forklift Classes Overview by Intella PartsIntella Parts
Discover the different forklift classes and their specific applications. Learn how to choose the right forklift for your needs to ensure safety, efficiency, and compliance in your operations.
For more technical information, visit our website https://intellaparts.com
Quality defects in TMT Bars, Possible causes and Potential Solutions.PrashantGoswami42
Maintaining high-quality standards in the production of TMT bars is crucial for ensuring structural integrity in construction. Addressing common defects through careful monitoring, standardized processes, and advanced technology can significantly improve the quality of TMT bars. Continuous training and adherence to quality control measures will also play a pivotal role in minimizing these defects.
Water scarcity is the lack of fresh water resources to meet the standard water demand. There are two type of water scarcity. One is physical. The other is economic water scarcity.
Industrial Training at Shahjalal Fertilizer Company Limited (SFCL)MdTanvirMahtab2
This presentation is about the working procedure of Shahjalal Fertilizer Company Limited (SFCL). A Govt. owned Company of Bangladesh Chemical Industries Corporation under Ministry of Industries.
Explore the innovative world of trenchless pipe repair with our comprehensive guide, "The Benefits and Techniques of Trenchless Pipe Repair." This document delves into the modern methods of repairing underground pipes without the need for extensive excavation, highlighting the numerous advantages and the latest techniques used in the industry.
Learn about the cost savings, reduced environmental impact, and minimal disruption associated with trenchless technology. Discover detailed explanations of popular techniques such as pipe bursting, cured-in-place pipe (CIPP) lining, and directional drilling. Understand how these methods can be applied to various types of infrastructure, from residential plumbing to large-scale municipal systems.
Ideal for homeowners, contractors, engineers, and anyone interested in modern plumbing solutions, this guide provides valuable insights into why trenchless pipe repair is becoming the preferred choice for pipe rehabilitation. Stay informed about the latest advancements and best practices in the field.
Automobile Management System Project Report.pdfKamal Acharya
The proposed project is developed to manage the automobile in the automobile dealer company. The main module in this project is login, automobile management, customer management, sales, complaints and reports. The first module is the login. The automobile showroom owner should login to the project for usage. The username and password are verified and if it is correct, next form opens. If the username and password are not correct, it shows the error message.
When a customer search for a automobile, if the automobile is available, they will be taken to a page that shows the details of the automobile including automobile name, automobile ID, quantity, price etc. “Automobile Management System” is useful for maintaining automobiles, customers effectively and hence helps for establishing good relation between customer and automobile organization. It contains various customized modules for effectively maintaining automobiles and stock information accurately and safely.
When the automobile is sold to the customer, stock will be reduced automatically. When a new purchase is made, stock will be increased automatically. While selecting automobiles for sale, the proposed software will automatically check for total number of available stock of that particular item, if the total stock of that particular item is less than 5, software will notify the user to purchase the particular item.
Also when the user tries to sale items which are not in stock, the system will prompt the user that the stock is not enough. Customers of this system can search for a automobile; can purchase a automobile easily by selecting fast. On the other hand the stock of automobiles can be maintained perfectly by the automobile shop manager overcoming the drawbacks of existing system.
Democratizing Fuzzing at Scale by Abhishek Aryaabh.arya
Presented at NUS: Fuzzing and Software Security Summer School 2024
This keynote talks about the democratization of fuzzing at scale, highlighting the collaboration between open source communities, academia, and industry to advance the field of fuzzing. It delves into the history of fuzzing, the development of scalable fuzzing platforms, and the empowerment of community-driven research. The talk will further discuss recent advancements leveraging AI/ML and offer insights into the future evolution of the fuzzing landscape.
Overview of the fundamental roles in Hydropower generation and the components involved in wider Electrical Engineering.
This paper presents the design and construction of hydroelectric dams from the hydrologist’s survey of the valley before construction, all aspects and involved disciplines, fluid dynamics, structural engineering, generation and mains frequency regulation to the very transmission of power through the network in the United Kingdom.
Author: Robbie Edward Sayers
Collaborators and co editors: Charlie Sims and Connor Healey.
(C) 2024 Robbie E. Sayers
About
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
Technical Specifications
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
Key Features
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface
• Compatible with MAFI CCR system
• Copatiable with IDM8000 CCR
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
Application
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
Using a system cost analysis to quantify drilling fluids and
1. Copyright 2001 AADE National Drilling Technical Conference
This paper was prepared for presentation at the AADE 2001 National Drilling Conference, “Drilling Technology- The Next 100 years”, held at the Omni in Houston, Texas, March 27 - 29, 2001. This
conference was hosted by the Houston Chapter of the American Association of Drilling Engineers. The information presented in this paper does not reflect any position, claim or endorsement made or
implied by the American Association of Drilling Engineers, their officers or members. Questions concerning the content of this paper should be directed to the individuals listed as author/s of this work.
Abstract
A System Cost Analysis is a methodology used to
quantify drilling fluid costs to a common value, the
monies spent/saved which are impacted by the mud
system. Traditionally, most drilling fluid vendors and
operators are concerned only with the actual costs of the
mud materials, trucking, etc.. These “costs” only provide
a minor piece of the total impact which mud has on the
total well drilling costs. The System Cost Analysis
provides a more complete picture of drilling fluid costs by
considering both the material costs and actual time lost
and/or gained due to the fluid. In addition, production
data is readily included in a System Cost Analysis to
ascertain the amount of impairment seen in the drilling
process.
Items considered in an analysis include lost time due to
mud related problems such as lost circulation, borehole
instability, inability to log properly, ineffective solids
control, etc.. In addition, drilling fluids can have a
positive/negative impact on time by
increasing/decreasing ROP’s; the System Cost Analysis
fixes a dollar value to this important variable.
The measurement method provides a framework for
measuring both past, present and future performance of
drilling fluid performance in a given study area. This
paper describes how a System Cost Analysis is done
and gives examples of analyses completed on projects
in Western Canada and South America.
Introduction
Over the last number of years, the quantification of
drilling costs has been rising dramatically, especially in
offshore and remote locations. As a result, a number of
studies have been published on quantifying those costs
in order to both understand where the dollars are being
spent and where savings potential exists.
1-4
While drilling fluids normally account for a relatively
small percentage (< 10% normally) of a well cost, they
are directly involved in a large number of the costs
incurred on a well. This is especially true for borehole
instability where the correct drilling fluid choice can
eliminate problems, or conversely lead to large cost
overruns. Similarly, improper handling of solids control
equipment can lead to massive wellbore problems and
needlessly expensive drilling costs.
This paper will describe the use of a “System Costs
Analysis” methodology to quantify the actual costs of a
drilling fluid on the actual costs of drilling a well. The
analysis looks at more than just the material costs of
mud products. It also focuses on the problems
associated with poor drilling fluid performance and on
the benefits of that drilling fluids can provide in drilling
wells faster.
System Cost Analysis Methodology
A System Cost Analysis (SCA), in basic terms, equates
all incidences on a well impacted by drilling fluids, either
positive or negative, back to a fundamental value –
dollars and cents. The analysis attempts to remove the
“fuzzy” qualitative feelings often associated with drilling,
items such as “trying hard, unforseen circumstances,
bad luck, etc.”. While there will always be some
qualitative measurement needed to reflect trust and
honesty on the multidisciplinary task of drilling a well, the
System Cost Analysis provides a quantitiative
measurement tool. This tool is a direct measuring stick
on how well an operator and service company perform.
The simplest version of a System Cost Analysis for
drilling fluids is determined in one simple equation:
System Cost = Material Costs + Unproductive Time
This System Cost has been further refined, as will be
discussed in the following section.
The material costs are quite simple, the costs of the
drilling fluids added to the well, plus any associated
costs as required for trucking, engineering services, etc..
It is generally common for drilling fluid companies and
the contribution of fluids to be evaluated on this “material
AADE 01-NC-HO-19
Using a System Cost Analysis to Quantify Drilling Fluids and Solids Control Costs
Brent Warren and Leonard Baltoiu, Q’Max Solutions Inc.
2. 2 BRENT WARREN AND LEONARD BALTOIU AADE 2001
cost” alone.
The unproductive or problem time for drilling fluids
involves any drilling function that has to do with drilling
fluids. A list of items is given in Table 1. Reaming and
cleaning, lost circulation, stuck pipe and mud rings are
just some of the items included in the trouble time cost.
The actual dollar value of the trouble time cost is
governed by the rig cost, usually determined on an
hourly basis.
In practice, the rig cost is agreed upon by the operator
and drilling fluid provider prior to the commencement of
the analysis. Any additional items to be covered in the
trouble time costs are also agreed upon by the parties
involved.
System Cost Analysis Methodology - Enhanced
Quantitative measurement of drilling fluid performance is
only one step in the process of how mud impacts on the
well performance and costs. Three additional items may
be included in a System Cost Analysis. First, drilling
fluids will certainly impact the time to drill as seen in rate-
of-penetration (ROP). ROP’s will vary greatly depending
upon densities, viscosities and filtration control
properties. Solids control and disposal costs are directly
related to mud types, especially in offshore and
environmentally sensitive regions. Thirdly, the
production of hydrocarbons from wells and fields may be
included if formation impairment is a real possibility.
Therefore the expanded System Cost equation is:
System Cost = Material Costs + (Trouble Time*hourly rig cost)
+ ROP impact + solids control/disposal + production
For example, comparison of water-based and oil-based
fluids by only the material costs only will invariably show
that water-based fluids cost less. The SCA may provide
a different answer once unproductive time, ROP,
solids/disposal costs and production data is included.
Benefits of a System Cost Analysis
System Cost Analyses can be done for any drilling
project, but are best utilized in areas where drilling is
troublesome and where a number of wells have
previously been drilled. In order to provide a relevant
analysis, ideally the wells included in the study should be
less than two years old. Wells older than this tend drill
somewhat slower (and are more costly) because of the
changes in technology (bits, MWD, etc.). In addition, the
wells used in the study should be of similar deviational
design and pass through similar lithologies since
wellbore trajectory plays a major part in well costs.
Drilling fluids system costs analysis are primarily used
for the following applications:
• Benchmarking: Drilling in troublesome areas often
involves problems with borehole instability. A
number of drilling fluids are often used to alleviate
that instability with varying degrees of success. The
System Cost Analysis provides a means of
determining which drilling fluid, casing design, etc. is
the most efficient fluid to use. In addition,
benchmarking provides a dollar value on the
problems which are most acute in the drilling region.
A risk cost analysis at this stage provides an
excellent tool for determining which drilling fluid and
casing design is optimum for drilling difficult,
expensive wells.
• Measuring change: Benchmarking in itself is a good
tool to determine the optimal method of how a
well/area is drilled now. Most times in difficult drilling
areas, the benchmarking exercise provides a tool for
indicating where improvements need to be made
and then provides a method of measuring those
changes. The real beauty of a dedicated system
cost analysis is in the cooperation of the drilling fluid
supplier to lower the overall well costs to the
operator by the cost effective means of mud
technologies and practices. Measuring change
provides a method of accomplishing this objective in
a quantifiable organized manner.
• Production measurement: Drilling fluids are the first
fluid to contact the native reservoir and often have a
large impact on the formation impairment of a
well/field. The System Cost Analysis is easily
modified to include the fluid costs as well as the
production numbers in a field. This type of analysis
is ideal for fields where different mud types are
being used and/or horizontal and vertical wells have
or will be drilled.
System Cost Analysis - Examples
1. Chicken/Route Area – Western Canada
The Chicken/Route area of the Alberta Foothills
(Figure 1) is characterized by instability problems
leading to some reaming and cleaning, but primarily
an inability to get logs to bottom. A system cost
analysis of 38 wells in the field was undertaken to
determine the root cause of the problem, whether
different drilling fluid types have helped this problem,
whether the problem was localized to a certain
portion of the field, and to determine if any
improvements could be made to the drilling fluid and
drilling practises. Typical well design in this field is
to drill with flocculated water as deep as possible
3. AADE 2001 Using a System Cost Analysis to Quantify Drilling Fluids and Solids Control Costs 3
(usually about 3600-3900 feet) and then mud-up to
either a gel-polymer or K2SO4-gel mud system to TD
around 5300 feet.
Figure 2 shows the wells in which logs either bridged
on first (or more) attempts and wells in which no logs
were obtained. Also on this area map is an
indication of where major lost circulation occurred.
As can be seen, logging problems were evident on
23 of the 38 wells in the study. These problems are
evident in the system costs per foot seen in the wells
as shown in Table 2 and Figure 3. Wells with the
bridging problems always had greater system costs
than those without the problems. Note that the data
is given per foot to normalize the data and is only for
the main hole section where mud was in the hole.
Following completion of the data gathering and
analysis phases of the SCA, a number of
conclusions and recommendations were made,
including:
- Wells in the 62-8 sector were generally trouble
free as seen by the system cost being twice the
material cost. This “twice value” or less of
system cost over material cost is generally seen
for land-based wells experiencing only minor
problems.
- majority of lost time which increased system
costs were due to logging difficulties as caused
by poor hole conditions. Logs normally bridged
somewhere in the water drilled section of the
well between 2625 and 3275 feet.
- A direct correlation existed between logging
problems and mud-up depth in which wells
which mudded-up deeper than 3925 feet were
most likely to experience logging problems. For
future wells, recommendations to drill no deeper
than 3900 feet with water were made.
- For all wells in area study, recommendation was
made to use silicate sweeps while floc water
drilling to stabailize the wellbore.
- Recommend drilling wells in 62-8 sector with
simple gel polymer mud systems previously
used. In all other areas, an inhibited fluid with
K+ as provided from K2SO4 was recommended.
The recommendations were implemented in the field
over a series of wells. The results from some of the
wells are shown in Table 3. All of the newly drilled
wells successfully ran logs to bottom on the first
attempt and hole problems due to wellbore instability
were minor. While the material costs were higher for
the post System Cost Analysis wells, the fewer
problems hours resulted in lower system costs.
2. Tipischa Jungle Basin – Ecuador
A System Cost Analysis in the Tipischa basin
compared the performance of an initial 14 well
program to a later 12 well program. The initial 14
wells were drilled with gel PHPA muds while a KNO3
ss-PHPA fluid was used on the later wells. A typical
well schematic with intermediate casing is shown in
Figure 4.
Table 4 and Figure 5 summarize the material and
system costs for the total well data for wells. Also
included is the solids control costs for the wells. The
following conclusions were made from the
information contained within the data:
- material costs/ft for the later drilled set of wells
was 13% greater than the previous wells. In
contrast the system costs were 5% less for the
later well grouping. The average amount of
unproductive time on the earlier wells was 79
hours while the later wells had 60 hours of
unproductive time.
- Solids control costs improved on the later wells
by 25% of $4.40/ft drilled. The savings were a
direct result of the KNO3 ss-PHPA system being
easier to strip solids from and tereby minimize
dumping and dilution of drilling fluid.
The Tipischa SCA study also analyzed drilling time
in terms of ROP, time to TD and time to rig release.
The data is summarized in Table 5 and Figure 6.
While the drilling fluid is certainly not the only
parameter which influences ROP, it is an important
variable. Other parameters such as bit type, weight
on bit, rpm, etc. are also of major importance. The
conclusions drawn from the data include:
- ROP, as refelcted in the drilling ft/day was ~ 175
ft/day faster in the later well set.
- The later well set was about 10% faster or 1.8
days to TD. This is due to a combination of
higher ROP’s and fewer unproductive hours.
- The days to rig release was also faster, 2.4 days
faster, on the later well set. The additional 0.6
days of savings resulted from increased
efficiencies in running logs and in conducting
liner/cementing operations.
Conclusions
• A System Cost Analysis provides a quantitative tool
for measuring the actual costs of drilling fluids on
overall well drilling costs.
• Simple System Cost is composed of drilling fluid
material costs, unproductive time due to drilling fluid
performance - converted to cost.
• An ideal total analysis of driling fluid performance
will include the System Cost as noted above, an
ROP analysis, solids control/disposal impact
4. 4 BRENT WARREN AND LEONARD BALTOIU AADE 2001
analysis and formation impairment – production
review.
• The prime benefits of a SCA are (1) benchmarking
current drilling fluid performance and (2) measuring
the impact of changes on the drilling fluid
performance.
• System cost Analysis provides operators and service
companies with methodology of determining where
costs are most prevalent.
• In general terms for a land-based operation, a well
with minimal problems related to mud will have
System Costs no greater than twice the material
cost.
• SCA lends itself well to using a risk analysis method
for determing relative well costs using varying well
casing and drilling fluid combinations. The SCA will
provide a large number of accurate input data sets in
order to generate accurate output well cost
information.
Acknowledgements
The authors would like to thank the many people
involved in the gathering of the data included in these
studies and in this paper. Special thanks goes to
George Rajbar of Q’Max who has brought the SCA to a
usable and functional methodology.
Nomenclature
ft = feet
K+ = potassium sulphate containing fluids
KNO3 =potassium nitrate
K2SO4 = potassium sulfate
MWD = measurement while drilling
N/A = not available
PHPA = partially hydrolyzed polyacrylamide
ROP = drilling rate of penetration
rpm = revolutions per minute
ss-PHPA = sterically stabilized partially hydrolyzed
polyacrylamide
SCA = System Cost Analysis
TD=total depth
References
1. Carter, T.: “A Model for Evaluating Mud Engineer
Perfromance” presented at the 1996 AADE Drilling Fluids
Technology Conference, Houston, Texas, April 3-4.
2. Trantham J.A. and Deagen J.M.: “Barrier-Free Learning for
Well Construction” SPE Paper No. 62833, presented at
the 2000 SPE/AAPG Western Regional Meeting, Long
Beach, California, June 19-23
3. Thorogood, L., Jackson, M.D., Thorsen, O.H., “Delivering
World-Class Exploration Drilling-Integration of Design,
Planning, and Execution”, SPE Paper No. 61798,
presented at the 2000 IADC/SPE Drilling Conference,
New Orleans, February 23-25.
4. Aldred, W.D., “Improving Drilling Efficiency Through the
Application of PERFORM*, Performance by Risk
Management”, SPE Paper No. 57574, presented at the
1999 SPE/IADC Middle East Drilling Technology
Conference, Abu Dhabi, UAE, November 8-10.
5. AADE 2001 Using a System Cost Analysis to Quantify Drilling Fluids and Solids Control Costs 5
SYSTEM COST ITEM DESCRIPTION OF TROUBLE TIME INCLUDED
Lost Circulation § Material costs and time (rig and other items such as water hauler).
Reaming and Cleaning § Reaming and/or cleaning while rih or pooh due to poor hole conditions. Does not
normally include reaming undergauge hole after motor drilling.
Logs Bridging § Due to poor hole conditions. Includes time spent reaming logging tool to bottom,
time lost due to no logs run, hole conditioning and running tool back into hole.
Casing/Liner § As above noted in “Logs Bridging” section.
Sidetrack/Redrill § Includes time and material costs incurred from running cement plugs to reaching
original depth before plugging back. Does not include sidetracks for geological
reasons.
Stuck Pipe § Includes material/time due mechanically stuck pipe. May or may not include
problems because of differentially stuck pipe.
Gravel/Boulders § Material costs and time.
Mud Rings § Material costs and time.
Kicks § Material costs and time.
Additional Costs § Includes items such as cementing, disposal (fluids and cuttings), trucking,
engineering, etc. as appropriate.
Rate-of-Penetration § Hours on bitover footage intervals. May include time spent on trips.
Production Comparisons § Captures formation damage issues. Works best for large sample sets and fairly
homogeneous reservoirs.
Table 1 – Items Included in a System Cost Analysis
6. 6 BRENT WARREN AND LEONARD BALTOIU AADE 2001
Well LSD Mud Type ft drilled $ material $ material/ft $ system cost $ sc/ft
02-20-61-7 W6 K+/K+ 1365 33445 24.50 42445 31.10
12-26-61-7W6 PHPA 3491 25248 7.23 70623 20.23
05-33-61-7 W6 gel chem 1654 18586 11.24 76336 46.17
09-11-62-7 W6 PHPA 738 2735 3.71 9860 13.36
07-03-62-7 W6 PHPA 3940 33261 8.44 151761 38.52
16-21-62-7W6 PHPA 1165 16614 14.26 46052 39.54
06-22-62-7 W6 PHPA 3694 13640 3.69 25265 6.84
16-20-62-7W6 gel chem 3002 11939 3.98 43252 14.41
09-31-62-7 W6 PHPA 1388 10423 7.51 37611 27.10
14-07-62-7 W6 PHPA 965 28023 29.05 38336 39.74
16-15-62-7 W6 K+/K+ 978 22792 23.31 97417 99.64
16-14-62-7 W6 /K+ 2510 38744 15.44 56744 22.61
05-12-62-7 W6 /K+ 2707 25330 9.36 30393 11.23
11-23-62-7 W6 K+/K+ 2461 34095 13.86 53408 21.70
03-28-62-7 W6 K+/K+ 2411 34830 14.44 48143 19.96
04-18-62-7 W6 K+/K+ 2871 45434 15.83 62872 21.90
10-23-62-8W6 PHPA 548 4467 8.15 13280 24.24
14-11-62-8W6 PHPA 2126 12649 5.95 25024 11.77
11-14-62-8W6 PHPA 1234 13168 10.67 32293 26.18
05-26-62-8 W6 /K+ 2280 23632 10.36 33945 14.89
01-33-62-8 W6 PHPA 1772 8972 5.06 18160 10.25
02-04-63-8 W6 PHPA 1611 9102 5.65 29352 18.22
04-09-63-8 W6 PHPA 1453 5655 3.89 16530 11.37
08-12-63-8 W6 gel chem 600 9755 16.25 75943 126.49
13-12-63-8W6 gel chem 876 10353 11.82 45228 51.63
03-13-63-8W6 gel chem 1732 20868 12.05 30993 17.89
06-14-63-8 W6 gel chem 912 9742 10.68 63180 69.27
13-28-63-8W6 PHPA 1188 5480 4.61 15043 12.67
02-31-63-8W6 PHPA 1401 5297 3.78 16360 11.68
12-32-63-8W6 PHPA 1332 5190 3.90 13440 10.09
12-33-63-8W6 PHPA 1690 6667 3.95 28042 16.60
16-20-63-8W6 PHPA 755 5603 7.43 60353 79.98
13-14-63-8W6 PHPA 2051 11880 5.79 19005 9.27
04-15-63-8W6 PHPA 1325 6903 5.21 47966 36.19
10-18-63-8W6 PHPA 509 6102 12.00 32915 64.72
13-19-63-8W6 PHPA 525 5463 10.41 9963 18.98
07-21-63-8W6 PHPA 2461 5204 2.11 7829 3.18
05-22-63-8W6 PHPA 2927 6824 2.33 46387 15.85
10-22-63-8W6 gel chem 663 10699 16.14 66762 100.74
TOTAL WELL MEAN 1712 15265 9.73 41408 31.29
61-7 MEAN 2170 25760 14.33 63135 32.50
62-7 MEAN 2218 24451 12.53 53932 28.97
62-8 MEAN 1592 12578 8.04 24540 17.46
63-8 MEAN 1334 8155 7.67 34738 37.49
Table 2 - Chicken Area (Alberta) Material and System Cost Values in Main hole mud drilled section. Lowest
mean material cost/ft as well as the highest system cost/ft was in the 63-8 section. The 62-8 section had the
lowest system cost mean and therefore the fewest amount of problems.
7. AADE 2001 Using a System Cost Analysis to Quantify Drilling Fluids and Solids Control Costs 7
Well LSD Mud Type ft drilled $ material $ material/ft $ system cost $ sc/ft
61-7 MEAN 2170 25760 14.33 63135 32.50
06-36-61-07 K2SO4 2648 78335 29.58 90335 34.11
62-7 MEAN 2218 24451 12.53 53932 28.97
16-30-62-07 K2SO4 2415 29286 12.13 56474 23.38
12-18-62-07 K2SO4 2740 45821 16.73 64196 23.43
63-8 MEAN 1334 8155 7.67 34738 37.49
12-27-63-08 K2SO4 722 6720 9.31 24720 34.23
16-07-63-08 K2SO4 6115 46163 7.55 54788 8.96
Table 3 - Chicken Area System Cost Analysis Comparison for wells drilled pre- and post-analysis. The
individual well locations are for the post-drilled SCA wells. Note that all of the post-analysis wells achieved
successful logs on first attempt. The well @ 06-36-61-07 had a high material cost due to massive lost circulation.
WELL NAME Ft
DRILLED
$
MATERIAL
$ MATERIAL/ft $ SYSTEM
COST
$ SYSTEM
COST/ft
$ SOLIDS
CONTROL
$ SOLIDS
CONTROL/ft
INITIAL 14 WELL SET
M 8 8870 297531 33.54 421281 47.50 172,000 19.39
D 1 9599 351809 35.77 735559 74.79 186,000 19.38
F 18b 13 8656 135135 15.74 300135 34.96 132,000 15.25
F 18b 14 8557 122928 14.37 244178 28.54 122,000 14.26
F18b 15 8762 96549 11.02 96549 11.02 136,000 15.52
D 2 9600 216650 22.60 352900 36.81 134,000 13.96
F 18b 16 8150 149112 18.28 229112 28.08 116,000 14.23
D 3 9356 305746 32.68 610746 65.28 232,000 24.80
D 7 10805 218232 20.20 385732 35.70 148,000 13.70
F 18b 20 8880 N/A N/A N/A N/A 145,000 16.33
D 8 9093 148487 16.33 343487 37.77 100,000 11.00
F 18b 21 8880 N/A N/A N/A N/A 188,000 21.17
M 4A 9145 144592 15.81 144592 15.81 125,000 13.67
F 18b 26 9388 240252 25.65 547752 58.47 166,000 17.68
LATER 12 WELL SET
T 1 10255 193515 18.87 434765 42.40 159,000 15.50
F18b 27 9061 281302 31.04 753802 83.18 130,000 14.35
P 1 9017 243320 26.98 329570 36.55 141,000 15.64
F 18b 25 9036 191113 21.15 256113 28.34 57,000 6.31
F 18b 37 9413 427153 43.93 528403 54.35 121,000 12.85
D 6 9220 243940 26.46 360190 39.07 131,000 14.21
M 4A2 8771 234838 26.77 347338 39.60 84,000 9.58
M 4A3 9362 163872 17.50 321997 34.39 93,000 9.93
T 1 9249 219644 23.75 318394 34.42 98,000 10.60
F 18b 46 8890 264718 29.78 395968 44.54 93,000 10.46
M 4A4 9207 N/A N/A N/A N/A 89,000 9.67
T 2 9088 239000 26.30 312750 34.41 138,000 15.18
Initial 14 MEAN 9135 218588 23.51 417088 44.79 150,100 16.43
Later 12 MEAN 9240 245674 26.59 396299 42.84 111,200 12.03
Table 4 - System Cost Analysis raw data and solids handling costs for Ecuador Tipischa Basin area. Data is
included for total well analysis, surface hole to TD.
8. 8 BRENT WARREN AND LEONARD BALTOIU AADE 2001
WELL
NAME
Ft
DRILLED
DRILLING
DAYS
ft/
DRILLING
DAY
DAYS
to TD
ft/ DAYS
to TD
DAYS to
RIG
RELEASE
ft/ DAYS to
RIG RELEASE
TROUBLE
TIME (hrs)
INITIAL 14 WELL
SET
M 8 8870 6.7 1318 24.0 370 26.6 334 49.5
D 1 9599 12.4 795 31.0 317 35.0 281 153.5
F 18b 13 8656 7.4 1168 14.0 615 15.7 546 66.0
F 18b 14 8557 7.3 1170 13.7 623 19.1 448 48.5
F18b 15 8762 N/A N/A N/A N/A 17.0 515 N/A
D 2 9600 8.8 1085 19.0 505 21.0 457 54.5
F 18b 16 8150 7.5 1094 13.6 600 17.4 470 22.0
D 3 9356 10.5 888 31.0 302 41.0 228 122.0
D 7 10805 14.7 735 24.6 440 27.5 393 67.0
F 18b 20 8880 8.9 1003 21.0 423 25.0 355 20.5
D 8 9093 7.8 1173 16.8 541 21.0 433 78.0
F 18b 21 8880 N/A N/A N/A N/A 34.0 261 N/A
M 4A 9145 N/A N/A N/A N/A 24.0 381 N/A
F 18b 26 9388 13.9 675 26.5 353 29.9 313 123.0
LATER 12 WELL
SET
T 1 10255 13.0 789 28.7 357 31.7 323 96.5
F18b 27 9061 11.3 801 18.7 485 29.4 308 179.0
P 1 9017 9.2 977 23.5 384 26.3 343 34.5
F 18b 25 9036 5.4 1662 11.3 799 14.6 620 26.0
F 18b 37 9413 7.4 1317 26.5 367 32.1 303 40.5
D 6 9220 5.9 1553 17.1 540 19.5 474 46.5
M 4A2 8771 8.3 1053 17.0 516 19.6 448 45.0
M 4A3 9362 9.8 955 18.6 502 19.5 479 63.25
T 1 9249 5.8 1591 16.4 565 17.5 528 39.5
F 18b 46 8890 9.3 956 18.9 471 22.5 396 52.5
M 4A4 9207 N/A N/A N/A N/A 21.0 438 N/A
T 2 9088 6.5 1398 19.2 474 20.8 438 29.5
Initial 14
MEAN
9135 9.6 1009 21.4 463 25.4 387 79
Later 12
MEAN
9240 8.4 1186 19.6 496 23.0 424 60
Table 5 - Time Analysis information for wells drilled in Ecuador Tipischa Basin area. Initial 14 wells used a gel-
PHPA system while the later 12 wells used a KNO3 ss-PHPA fluid. Drilling Days is a measure of rotating time to
reach total depth.
9. AADE 2001 Using a System Cost Analysis to Quantify Drilling Fluids and Solids Control Costs 9
Figure 1 - Location of Chicken/Route area in West Central Alberta
ΠΠ ΠΠ σσ
ΠΠ
ƒƒ σσ σσ ƒƒσσ
σσ σσ σσ σσσσσσ ΠΠ
ƒƒΠΠ
σσσσ
63
∋∋ σσ
∋∋ ΠΠ
ΠΠ ΠΠ ΠΠ ΠΠ σσ
σσ ΠΠ ƒƒ σσ
ΠΠ ΠΠ ΠΠ ƒƒ
ΠΠ
62
σσ
σσ
∋∋
61
08 07
Figure 2 – Chicken/Route area detailed well map. Wells with ΠΠ symbol indicate those with no logging or lost
circulation problems, σσ symbol indicates logging problems or no logs run and ∋∋ symbol is for wells with lost
circulation. A well with ƒƒ symbol has both logging and lost circulation problems.
Edmonton
Calgary
∗∗
∗∗
AALLBBEERRTTAA
Chicken/
Route
10. 10 BRENT WARREN AND LEONARD BALTOIU AADE 2001
Figure 3 – Comparative material and system costs for Main Hole section of wells in the various sectors of the
Chicken/Route area. Data taken from Table 2.
HOLE SIZE DEPTH CASING SIZE
17.5" 1400-1700' 13.375"
12.25" 7000-9000' 9.625"
8.5" 8500-10000' 7"
Figure 4 – Typical well design for Ecuadorian Tipischa Jungle basin wells.
0
5
10
15
20
25
30
35
40
61-7 MEAN 62-7 MEAN 62-8 MEAN 63-8 MEAN
$/ftcost
$ material/ft
$ system cost/ft
11. AADE 2001 Using a System Cost Analysis to Quantify Drilling Fluids and Solids Control Costs 11
Figure 5 – Comparison of material costs, system costs and solids costs for initial 14 and later 12 wells in
Tipischa study area. Costs are given per foot to normalize the data and are shown for the entire well. Data taken
from Table 4.
Figure 6 – Comparison of drilling rate (ROP), time to total depth and time to rig release for initial 14 and later 12
wells in Tipischa study area. Information is presented in value ft per days to normalize data. Data taken from
Table 5.
0
5
10
15
20
25
30
35
40
45
50
$ material/ft $ system cost/ft $ solids cost/ft
$/ftcost
Initial 14 MEAN
Later 12 MEAN
0
200
400
600
800
1000
1200
1400
ft/ DRILLING DAY ft/ DAYS to TD ft/ DAYS to RIG
RELEASE
ft/day
Initial 14 MEAN
Later 12 MEAN