JewelSuite 2012 Article

The Baker Hughes JewelSuite™ 2012 software puts the power of advanced 3-D reservoir modeling into the hands of land operators who need an economic reservoir modeling platform that looks at various aspects of the life cycle of an unconventional reservoir.

Reservoir modeling—the ability to create an interactive digital model that accurately represents subsurface hydrocarbon reservoirs—is usually the domain of a very few highly skilled geoscientists and engineers. Baker Hughes aims to change that by providing an economic, easy and efficient 3-D reservoir modeling software platform to operators looking to better understand their unconventional plays in order to plan effective drilling and fracturing campaigns to optimize operational costs and production.

The JewelSuite 2012 reservoir modeling package visualizes and uses various data from an unconventional asset to reduce operational overhead and improve productivity. It delivers faster results and leverages efficient workflows to produce unmatched reservoir model accuracy that allows geoscientists and engineers to look at the entire reservoir at once, or to zoom in to the scale of a single well.

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JPT Nanotechnology article - October

The magic of nanotechnology is on display in the form of a dull silver ball created by Baker Hughes.

What looks like solid metal is a composite that is light enough to flow through a well, strong enough to stand up to the impact and pressure associated with opening a sleeve on a multistage fracturing job, and then disappear when it is done.

The company is making 1,500 of the balls each week and based on customer calls, it could sell a lot more, said James King, director of applications engineering for sales and operations support at Baker Oil Tools, US Land. The company plans to increase sales, and add new products, but the supply of the material used to make the balls is limited.

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LLOG/EXMAR Who Dat Field Article

Through collaborative initiatives between LLOG Exploration Co. LLC and Baker Hughes, a series of three wells in LLOG’s Who Dat field were successfully drilled and completed, including multizone well architecture integrated with intelligent well systems. Optimization of the well architecture and completion design was achieved through a comprehensive understanding of the reservoir requirements and long-term production goals of LLOG’s Who Dat field. The overall technical and operational success of the project can be attributed to a combined team using Baker Hughes’ expertise across multiple technology areas and LLOG’s operational knowledge. Together with LLOG, Baker Hughes devoted some of its most experienced engineers and technicians, with years of experience ranging from 11 to 43.

The Who Dat field’s first well, MC 547 SS01, was completed in June of 2010 and set the bar for subsequent expectations. Well MC 503 SS02 was completed in September of 2010 as an intelligent well, and MC 503 SS01 was completed in January of 2011 with three frac packs integrated with intelligent well systems. The well designs included two intelligent well systems that enabled the operator to produce from separate zones or comingle production, resulting in optimal management of reserve recovery and well performance. Despite the complexity and scope of technology, the wells were drilled and completed with industry-leading efficiency and safety performance while meeting the goals under the planned cost.

Precise wellbore placement

Baker Hughes’ drilling and evaluation team delivered precise wellbore placement and critical formation data integral to the success of LLOG’s Who Dat project by using the AutoTrak G3™ rotary steerable system. In addition, an array of logging-while-drilling (LWD) services were implemented, including Baker Hughes’ OnTrak™ measurementwhile- drilling (MWD) service, LithoTrak™ LWD porosity service, SoundTrak™ LWD acoustics service, and TesTrak™ LWD formation pressure-testing service. To further define reservoir characteristics, a post-processing technique for logging mechanical properties was used to aid in determining reservoir compressibility and its affect on recoverable reserves.

The combined portfolio of technologies and services were implemented to minimize the overall project risk. Baker Hughes’ AutoTrak G3 rotary steering system combined with real-time MWD/LWD data enabled the rotary steering system to drill complex well targets. TesTrak services were used in the first well during the drilling phase to measure formation pressures in an unknown pressure regime, as well as provide fluid gradients and reservoir fluid mobility. The real-time formation pressure testing provides data to update the geological model as well as improve wellsite safety and enhance drilling efficiency. The LithoTrak advanced LWD porosity service was used in all three wells in the 12 ¼-in. and 8 ½-in. reservoir sections. LithoTrak provides neutron porosity, bulk density and acoustic caliper measurements. In addition, the bulk density measurement can be displayed as a borehole image spanning 360°.

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Our rotary steerable drilling system allows you to navigate precisely into the target using superior directional control in the most challenging well profiles.

View All Rotary Steerable Systems

Even under challenging borehole conditions, you can be confident we’re offering the industry’s most accurate porosity measurements.

View All Logging While Drilling

Minimize wellbore breakouts and possible collapse using reliable, real-time compressional and shear wave travel times in fast and slow formations.

View All Logging While Drilling

Get directional, drilling dynamics, ECD, and geological information including gamma-ray and resistivity measurements from a single, compact BHA module.

View All Logging While Drilling

View the original article here

Factors Key To Deepwater Cementing article

HOUSTON–As deepwater oil and gas exploration expands around the world, well cementing is a critical aspect of well construction with unique considerations because of the deepwater environment and downhole conditions. To minimize risks, well construction costs and nonproductive time, it is important to understand the constraints for deepwater cementing and essential good cementing practices, and to carefully plan for contingencies that may arise when working in locations where cement must be placed properly the first time, every time.

Two of the most frequently asked questions regarding offshore operations are what makes deepwater drilling so challenging, and what is the major difference from drilling on the Shelf? To answer this question, one must understand that deepwater drilling rigs float thousands of feet above the surface location. They are kept on station either by anchors attached by miles of gigantic cables or by an automated dynamic positioning system that operates the rig’s thrusters based on very precise data from global positioning satellites. Both of these systems have limits, but they have propelled oil and gas exploration into water depths greater than 10,000 feet.

Deepwater semisubmersibles deploy two-story-high stacks of blowout preventers that sit on the seafloor and are exposed to extreme cold and external pressure. The floating rigs also carry small unmanned, remotely operated vehicles that monitor operations at the seafloor and use robotic arms to assist when necessary. These technological wonders and dozens more, developed and built by the service industry especially for the challenges of deepwater drilling, add to a huge capital investment by oil and gas exploration and production companies. The cost of developing a deepwater field can exceed $1 billion, and increases with increasing water depth.

The mechanics of drilling a deepwater well are also much different from drilling on land or on the Shelf. In deep water, the first two to three strings of pipe are installed without a connection back to the rig. Riserless drilling essentially eliminates any means of placing pressure on the well, other than the pressure exerted by the well fluids and the natural column of sea water. This means that mud and cement companies must have very specialized systems and training in order to counteract and control the problems associated with riserless drilling.

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PTQ Q1 2011 Article

In today’s refining climate, the economics of a visbreaking unit are mainly related to the conversion levels achieved. Conversion is limited by the impact of cracking reactions on the progressive destabilisation of the asphaltenes present in the unit feed. This destabilisation causes fouling phenomena, due to precipitation of the asphaltenes and conversion of some of the asphaltenes to generate coke particles at cracking temperatures above 400°C (752°F), and these phenomena limit unit run lengths. On the other hand, destabilised asphaltenes can easily aggregate over time and, since produced visbreaker resid is often a base stock for the production of heavy fuel oils, this can lead to problems with hot filtration test (HFT) results.

Visbreaker severity is monitored to maximise conversion, taking into account excessive coke generation and the tendency of asphaltenes to precipitate, either inside process equipment or as sediments in the heavy fuel oil produced. As fouling increases exponentially at higher conversions, process control becomes more and more important to prevent drastic negative outcomes.

Severity is a function of operating temperatures and velocity steam. This article presents a case of optimisation of these two variables at the Repsol Tarragona visbreaker, resulting in major improvements to visbreaker conversion.

Courtesy of PTQ Q1 2011, www.eptq.com.

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LLOG/EXMAR Who Dat Field Article

 

Through collaborative initiatives between LLOG Exploration Co. LLC and Baker Hughes, a series of three wells in LLOG’s Who Dat field were successfully drilled and completed, including multizone well architecture integrated with intelligent well systems. Optimization of the well architecture and completion design was achieved through a comprehensive understanding of the reservoir requirements and long-term production goals of LLOG’s Who Dat field. The overall technical and operational success of the project can be attributed to a combined team using Baker Hughes’ expertise across multiple technology areas and LLOG’s operational knowledge. Together with LLOG, Baker Hughes devoted some of its most experienced engineers and technicians, with years of experience ranging from 11 to 43.

The Who Dat field’s first well, MC 547 SS01, was completed in June of 2010 and set the bar for subsequent expectations. Well MC 503 SS02 was completed in September of 2010 as an intelligent well, and MC 503 SS01 was completed in January of 2011 with three frac packs integrated with intelligent well systems. The well designs included two intelligent well systems that enabled the operator to produce from separate zones or comingle production, resulting in optimal management of reserve recovery and well performance. Despite the complexity and scope of technology, the wells were drilled and completed with industry-leading efficiency and safety performance while meeting the goals under the planned cost.

Precise wellbore placement

Baker Hughes’ drilling and evaluation team delivered precise wellbore placement and critical formation data integral to the success of LLOG’s Who Dat project by using the AutoTrak G3™ rotary steerable system. In addition, an array of logging-while-drilling (LWD) services were implemented, including Baker Hughes’ OnTrak™ measurementwhile- drilling (MWD) service, LithoTrak™ LWD porosity service, SoundTrak™ LWD acoustics service, and TesTrak™ LWD formation pressure-testing service. To further define reservoir characteristics, a post-processing technique for logging mechanical properties was used to aid in determining reservoir compressibility and its affect on recoverable reserves.

The combined portfolio of technologies and services were implemented to minimize the overall project risk. Baker Hughes’ AutoTrak G3 rotary steering system combined with real-time MWD/LWD data enabled the rotary steering system to drill complex well targets. TesTrak services were used in the first well during the drilling phase to measure formation pressures in an unknown pressure regime, as well as provide fluid gradients and reservoir fluid mobility. The real-time formation pressure testing provides data to update the geological model as well as improve wellsite safety and enhance drilling efficiency. The LithoTrak advanced LWD porosity service was used in all three wells in the 12 ¼-in. and 8 ½-in. reservoir sections. LithoTrak provides neutron porosity, bulk density and acoustic caliper measurements. In addition, the bulk density measurement can be displayed as a borehole image spanning 360°.

Download the PDF to read more.

DOWNLOAD PDF (810.3 KB)

Our rotary steerable drilling system allows you to navigate precisely into the target using superior directional control in the most challenging well profiles.

View All Rotary Steerable Systems

Even under challenging borehole conditions, you can be confident we’re offering the industry’s most accurate porosity measurements.

View All Logging While Drilling

Minimize wellbore breakouts and possible collapse using reliable, real-time compressional and shear wave travel times in fast and slow formations.

View All Logging While Drilling

Get directional, drilling dynamics, ECD, and geological information including gamma-ray and resistivity measurements from a single, compact BHA module.

View All Logging While Drilling

View the original article here

Factors Key To Deepwater Cementing article

HOUSTON–As deepwater oil and gas exploration expands around the world, well cementing is a critical aspect of well construction with unique considerations because of the deepwater environment and downhole conditions. To minimize risks, well construction costs and nonproductive time, it is important to understand the constraints for deepwater cementing and essential good cementing practices, and to carefully plan for contingencies that may arise when working in locations where cement must be placed properly the first time, every time.

Two of the most frequently asked questions regarding offshore operations are what makes deepwater drilling so challenging, and what is the major difference from drilling on the Shelf? To answer this question, one must understand that deepwater drilling rigs float thousands of feet above the surface location. They are kept on station either by anchors attached by miles of gigantic cables or by an automated dynamic positioning system that operates the rig’s thrusters based on very precise data from global positioning satellites. Both of these systems have limits, but they have propelled oil and gas exploration into water depths greater than 10,000 feet.

Deepwater semisubmersibles deploy two-story-high stacks of blowout preventers that sit on the seafloor and are exposed to extreme cold and external pressure. The floating rigs also carry small unmanned, remotely operated vehicles that monitor operations at the seafloor and use robotic arms to assist when necessary. These technological wonders and dozens more, developed and built by the service industry especially for the challenges of deepwater drilling, add to a huge capital investment by oil and gas exploration and production companies. The cost of developing a deepwater field can exceed $1 billion, and increases with increasing water depth.

The mechanics of drilling a deepwater well are also much different from drilling on land or on the Shelf. In deep water, the first two to three strings of pipe are installed without a connection back to the rig. Riserless drilling essentially eliminates any means of placing pressure on the well, other than the pressure exerted by the well fluids and the natural column of sea water. This means that mud and cement companies must have very specialized systems and training in order to counteract and control the problems associated with riserless drilling.

Download the PDF to read more.

DOWNLOAD PDF (828.6 KB)

View the original article here

Taking the measure of reliability article

Product and service reliability has always been an important criterion for oil and gas operations, but, historically it has been difficult to measure consistent levels of reliability.

Transferring know-how

Other business sectors have a greater maturity in the use of reliability and quality principles. Aerospace and defense, for example, have a mature reliability culture after 60 years of sustained focus on the topic. Flight safety led to mandates on use of processes and procedures in the Military Handbook and Military Standards to execute development programs that meet high reliability/safety requirements. Today, learning from these industries is yielding more costeffective and efficient programs and processes for industrial and consumer products.

In classic terms, Reliability (R), is the probability of failure- free performance over an item’s useful life, for a specified timeframe or mission time (t), under specified environmental and duty-cycle conditions where probability of failure-free performance is greater than 0.9995. For most commercial aviation applications, reliability requirements are very stringent: for a mission time of t = 10 hours, R(10) can be greater than 0.999999, which necessitates use of tools capable of supporting probabilistic engineering and data analysis.

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PTQ Q1 2011 Article

 

In today’s refining climate, the economics of a visbreaking unit are mainly related to the conversion levels achieved. Conversion is limited by the impact of cracking reactions on the progressive destabilisation of the asphaltenes present in the unit feed. This destabilisation causes fouling phenomena, due to precipitation of the asphaltenes and conversion of some of the asphaltenes to generate coke particles at cracking temperatures above 400°C (752°F), and these phenomena limit unit run lengths. On the other hand, destabilised asphaltenes can easily aggregate over time and, since produced visbreaker resid is often a base stock for the production of heavy fuel oils, this can lead to problems with hot filtration test (HFT) results.

Visbreaker severity is monitored to maximise conversion, taking into account excessive coke generation and the tendency of asphaltenes to precipitate, either inside process equipment or as sediments in the heavy fuel oil produced. As fouling increases exponentially at higher conversions, process control becomes more and more important to prevent drastic negative outcomes.

Severity is a function of operating temperatures and velocity steam. This article presents a case of optimisation of these two variables at the Repsol Tarragona visbreaker, resulting in major improvements to visbreaker conversion.

Courtesy of PTQ Q1 2011, www.eptq.com.

Download the PDF to read more.

DOWNLOAD PDF (530.4 KB)

View the original article here

JPT Nanotechnology article - October

The magic of nanotechnology is on display in the form of a dull silver ball created by Baker Hughes.

What looks like solid metal is a composite that is light enough to flow through a well, strong enough to stand up to the impact and pressure associated with opening a sleeve on a multistage fracturing job, and then disappear when it is done.

The company is making 1,500 of the balls each week and based on customer calls, it could sell a lot more, said James King, director of applications engineering for sales and operations support at Baker Oil Tools, US Land. The company plans to increase sales, and add new products, but the supply of the material used to make the balls is limited.

Download the PDF to read more.

DOWNLOAD PDF (624.4 KB)

View the original article here

Reduction of hydrogen sulfide in asphalt Article

Hydrogen sulfide (H2S) is a safety and environmental concern for the petroleum industry. For those refiners that produce asphalt from "bottom of the barrel" products, such as vacuum tower bottoms (VTBs), the concern is H2S exposure to workers and to the community.

Asphalt blend stocks often contain high levels of H2S and can pose significant danger to individuals involved in its production and handling. Many producers have H2S specifications at railcar and tank truck loading racks. Moreover, the American overnmental Industrial Hygienists (ACGIH) recently lowered the recommended threshold limit value (TLV) for hydrogen sulfide from 10 to 1 ppm. Finally, state air quality boards limit the amount of H2S allowed in ambient air at the refinery fence line in order to improve local air quality.

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Longer life with corrosion control article

Corrosion control in crude unit atmospheric towers is often achieved through a combination of multiple mitigation strategies. These mitigation strategies may include modifications to unit operating conditions and the proper selection of chemical additives. The key to identifying the most effective mitigation strategies is determining the best use of diagnostic tools, such as the Baker Petrolite Ionic Model. To obtain a thorough understanding of the corrosion mechanism(s) occurring in the system, physical examination of the affected areas is also required. This article presents a case study for a US Gulf Coast refinery in which multiple corrosion control strategies were employed to address amine hydrochloride salt deposition in the atmospheric tower overhead system. Mitigation strategies included desalter wash water acidification and modified tower operations to reduce the amount of amine recycled to the crude tower, thus reducing corrosion due to salt deposition. The implementation of these strategies resulted in lower corrosion risk and continued improvement of the run length of the overhead heat exchangers.

System description

The tower overhead comprises a two stage condensing system. The unit was designed so that the first stage would operate without bulk water condensation in the first accumulator drum (‘hot and dry’ operation). The unit processes approximately 150 000 bpd (23.8 m3/d) of primarily light crude (35° API). The first stage consists of four parallel banks of shell and tube exchangers in which overhead process vapours exchange heat with raw crude on the tube side. The combined shell outlet stream is fed to a separator drum from which the hot naphtha is combined with a top pumparound and then returned to the tower as reflux.

Process vapour from the first stage feeds a set of air coolers after which the multiphase product is separated in the second accumulator drum (cold and wet operation). An oil based corrosion inhibitor is injected into the overhead line upstream of the first stage condensers (E-1s). A neutralising amine is injected via a water wash upstream of the second stage fin fans. The neutraliser formerly used was monoethanolamine (MEA) based. All equipment in the overhead system is constructed of carbon steel. Figure 1 provides a simplified diagram of the overhead system.

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