bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments: Unconventional Access
Authors: Donnelly John 
Published: February 2015

Editor's column
PTT Exploration and Production’s (PTTEP) agreement with Statoil to take a share of a Canadian oil sands development is just the latest in a string of deals by Asian oil companies made to gain access to unconventional resources in North America. Firms from China and India bought into projects throughout 2010 looking to gain access to new reserves as well as to gain technical knowhow.
Thailand’s PTTEP acquired a 40% interest from Statoil Canada in the Kai Kos Dehseh Oil Sands Project in western Canada in late November for USD 2.3 billion for its debut in the oil sands market. Statoil will keep the remaining 60% of the project. Kai Kos Dehseh has estimated reserves of 4.3 billion bbl and, using steam-assisted gravity drainage (SAGD), is on target to reach early production of 10,000 b/d in the first quarter of this year. Peak output is projected to be 300,000 b/d, which would help PTTEP move toward its goal of more than tripling current production to reach 900,000 BOEPD by 2020. “This acquisition provides the company access to a highly attractive oil sands deposit in Canada and a strong platform for future growth into unconventional resources,” the company said in a statement.
This follows deals by China firm Sinopec to buy ConocoPhillips’ stake in oil sands producer Syncrude Canada, China Petrochemical Corp.’s purchase of Calgary-based Addax Petroleum, and PetroChina’s buy-in of a stake in Athabasca Oil Sands’ MacKay and Dover oil sands projects. China first began buying small stakes in oil sands projects in 2005.
Asian state oil companies are investing billions of dollars in oil sands projects in Canada and shale plays in the US. The goal is to secure new resources to fuel their booming economies and to learn the techniques and technologies that will help them develop unconventional resources in their own backyards. With oil prices steady above USD 70/bbl, SAGD oil sands projects remain economic and, with gas prices still depressed, independent producers are welcoming the infusion of Asian cash. Shale developments in North America have attracted a string of deals over the past 2 years, the latest being Chinese National Offshore Oil Corp.’s purchase of a one-third stake in Chesapeake Energy’s Eagle Ford shale acreage in south Texas in November.
Although reserves estimates for Asia’s unconventionals potential are sketchy, the International Energy Agency puts China’s unconventional gas reserves at 144 trillion cm. Some analysts believe that figure is much higher. Last August, China inaugurated a shale gas research center and set goals of locating 1 trillion cm of recoverable shale gas reserves, building 15 billion cm to 30 billion cm of production capacity, and producing 8% to 12% of China’s natural gas needs from shale by 2020. The US government is also encouraging China’s development of shale in hopes that it will help the country cut carbon emissions.
Upgrading Formation-Evaluation Electronics for High-Temperature Drilling Environments
Authors: Dirksen Ron 
Published: February 2015

Technology Update
Globally, increasing amounts of hydrocarbon resources are being found in fields that have very high thermal gradients. (It gets hot very quickly as you move downward.)
On the drilling side, challenging, high-pressure/high-temperature (HP/HT) wells customarily have been drilled with the simplest of tools, such as turbines and mud motors, which have minimal electronics and make no measurements. Logging-while-drilling tools, which do contain electronics and require electrical power to operate, have not been used thus far in these wells.
Most formation-evaluation tools have lots of electronic components, and so initially couldn’t be used in HP/HT wells. However, these wells are often located offshore, where high rig rates force operators to look for all possible means to increase drilling efficiency and optimize wellbore placement for maximum production.
Meeting HT Challenges
The main challenges in these environments are preventing the electronics from becoming damaged, maintaining measurement accuracy and precision, and generating or supplying the regulated power to the electronics reliably over the duration of the drilling effort.
Several parallel technologies have been developed over the past 5 to 6 years that can be used on their own or in combination to address these issues. The technology developments have concentrated on three main themes: HT electronics and the operating environment, new sensor technologies and measurement methodologies to improve accuracy and precision, and active cooling.
In this connection, a 2-year project to develop measurement-while-drilling tools that can record and transmit data at temperatures of 230°C—running for 14 days continuously—has been initiated by Halliburton. The purpose of this project was to finalize some of the ongoing developments in high-temperature electronics and sensor technologies and package them into a tool capable of performing in this environment.
In considering the operating life of electronics, one of the main issues in HT environments is the increased rate of chemical reactions that cause the electronics to fail. In 1889, Svante Arrhenius documented the fact that chemical reactions require activation energy to proceed. The Arrhenius equation provides the quantitative relationship between temperature and the rate at which a chemical reaction occurs. This relationship is important for our industry because it governs many of the failure mechanisms for downhole electronics.
The rate of chemical reactions is defined by the equation
K=Ae–Ea/RT,
which documents the exponential relationship between rate (K) and temperature (T). Ea is the activation energy for a particular process, and this value can be changed (by adding catalyst or inhibitor). Ae (pre-exponential factor) and R (gas constant) are empirically derived constants. Many reactions double their rate every 10°C.
Nanosized Particles for Enhanced Oil Recovery
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 129933, ’Nanosized Particles for EOR,’ by Tormod Skauge, SPE, Sverre Hetland, Kristine Spildo, SPE, and Arne Skauge, SPE, Uni CIPR, prepared for the 2010 SPE Improved Oil Recovery Symposium, Tulsa, 24-28 April. The paper has not been peer reviewed.
Colloidal-dispersion gels (CDGs) have been used in enhanced oil recovery (EOR) to provide sweep improvement in reservoirs exhibiting an unfavorable mobility ratio. Coreflood results indicate an improved microscopic sweep or microscopic diversion by CDG. A new concept of EOR by improved microscopic displacement is defined as microscopic diversion. This method involves pore blocking and diversion of injection fluids.
Introduction
In most successful field applications involving CDGs, oil production increased and the water/oil mobility ratio decreased. There are few systematic studies regarding the detailed mechanisms of the CDG process. Most studies focused on the propagation of CDG in porous media and the gelation process. The gelation behavior of CDG systems was studied, with the aim of understanding the performance of CDG with respect to in-depth permeability modification.
Recently, coreflood data were published that report improved microscopic displacement by use of pregenerated CDGs. The objective and properties of the conventional approach from the 1990s targeted mainly macroscopic-sweep improvement, while the more-recent approach with pregenerated colloid particles has defined two classes of CDG. Here, pregenerated colloid particles are in the range of 100 nm. These solutions also have been called linked-polymer solutions and attempt to improve the microscopic-displacement efficiency in addition to the macroscopic sweep.
The purpose of this work was to investigate mechanisms for microscopic diversion by comparing the oil-mobilization properties of inelastic nanosized silica particles with those of CDG. Nanosized silica particles provide an environmentally friendly alternative to polymer or CDG flooding, thus lowering the threshold for implementation, particularly in offshore environments. Oil mobilization was investigated in a series of Berea-coreflood experiments.
A porous medium is a complex structure of pore bodies and throats with a range of sizes. Any material dissolved or dispersed in water may adsorb onto the solid surface. When a polydisperse solution of particles flows through a porous medium, particles with a size larger than or equal to the throat size will be trapped. This mechanism, which leads to blocking of narrow pore throats by larger CDG particles, is known as mechanical entrapment or straining.
Samarang Field - Redevelopment Evaluation Brings New Life to an Old Oil Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13162, ’Samarang Field - Seismic-to-Simulation Redevelopment Evaluation Brings New Life to an Old Oil Field, Offshore Sabah, Malaysia,’ by J.K. Forrest, SPE, Schlumberger; A. Hussain, SPE, and M. Orozco, SPE, Petronas Carigali Shd. Bhd.; and J.P. Bourge, SPE, T. Bui, SPE, R. Henson, SPE, and J. Jalaludin, SPE, Schlumberger, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed.
The Samarang field is offshore Sabah, East Malaysia, approximately 45 miles northwest of the Labuan gas terminal. The field surrounds a shallow reef with a water depth of 30 ft. Shell was the initial operator and relinquished the concession to Petronas Carigali Sdn. Bhd. (PCSB) in April 1995.
Field-Development History
Fig. 1 summarizes the production and development history of the field. The field was developed in phases, with the initial phase including the larger A and B drilling platforms; separate producing platforms at A, B, and C; and well jackets at C, D, and E. Subsequent development included well jackets at F and G. An additional well jacket, H, was planned by Shell for the east-flank development but was not implemented in 1986 because of low reserves potential and low oil prices.
Formation Evaluation and Characterization
A 1984 3D-seismic survey is available and was interpreted, but the best data and control are provided by the openhole logs from 144 wells. Within the field, log correlation is good in general. All of the producing reservoirs in the field are normally pressured, and the field has a normal temperature gradient for the area of approximately 1.05°/100 ft.
The cored interval comprises three main facies types (i.e., sandstones, heterolithic sandstones, and shales). These facies types then were subclassified into nine lithofacies to cover the broad spectrum of sand/shale content, primary sedimentary structures, intensity of bioturbation, and unique sedimentologic character that was identified and described from the core. The ninth lithofacies in the cored intervals represents the presence of carbonates in the form of patchy carbonate cement, broken/intact shell hash layers, dolomite patches, and layered or nodular siderites. This last lithofacies, though negligible in occurrence in the whole cored section (0.4% of the total cored interval), was important as a local vertical-flow baffle.
Following the identification of these lithofacies, geologists used a neural-network procedure to extend the lithofacies to most of the noncored wells. Some of the wells had wellbore problems including missing logs or cork-screwed boreholes, which did not allow their inclusion in this work. But in all cases, there was sufficient well coverage to allow the estimation of lithofacies throughout the reservoir sequences. The final neural-network model involved used the sand, silt, and clay volumes for each individual well as calculated by petrophysical methods.
Redevelopment of the Cardium Formation by Use of Fractured Horizontal Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137737, ’Re development of the Cardium Formation Using Fractured Horizontal Wells: Res er voir-Engineering Perspectives and Early Case Histories,’ by E.N. Omatsone, M.A. Bagheri, SPE, and C.M.F. Galas, SPE, Sproule Associates; B. Curtis, Bonterra Energy; and K. Frankiw, Midway Energy, originally prepared for the 2010 CSUG/SPE Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.
The full-length paper presents a brief review of the historical performance of vertical wells in the low-reservoir-quality areas of the Cardium formation and describes the effect of placing multistage-fractured horizontal producers in these areas. The paper deals with the redevelopment of the Cardium formation from a primary-recovery perspective only, with a focus on the fringe areas around the supergiant Pembina field, as well as the development of the largely untapped resource in the A Lobe of the Cardium in the Garrington/Caroline areas.
Introduction
The Cardium formation is regionally extensive, spanning an area of nearly 150 townships in central/southern Alberta. The formation has been described as a clastic wedge that prograded into the western interior seaway during Turonian-Coniacian time. Many sedimentological responses identified within the formation indicate that the sand accumulation took place in muddy and sandy inner- and outer-shelf, shoreface, lagoonal, tidal, estuarine, and coastal-plain settings.
This wide variety of depositional environments resulted in a diversity of lithofacies, multiple disconformities, paraconformities, and diastems of varying lateral extents. The predominant rock types in the Cardium are mudstone and sandstone with small, but important, conglomerate fractions. The Cardium deposits formed a series of stratigraphic traps, the largest of which is the supergiant Pembina field in central Alberta. Cardium reservoirs and pools have been found at depths ranging between 1200 and 2800 m and typically contain light, sweet oil with varying amounts of dissolved gas. A number of rich-gas pools also can be found in the Cardium formation.
Operators who target the Cardium formation frequently are the beneficiaries of excellent core data, as a result of the standard industry practice of the 1950s through the 1980s. In the broader Pembina area, the Cardium exhibits exceptional log resolution because of its relatively shallow depth of burial. Many of the logs in the Garrington/Caroline area are of an older vintage and of generally poorer resolution. The abundance of core-plug, well-log, and production-performance data from the more than 10,000 vertical wells that have targeted the Cardium allows for high-quality petrophysical analysis and detailed geological mapping. Some operators have begun to use 3D-seismic amplitudes and other geophysical attributes to study the reservoir quality and pore-fluid content in various portions of the Cardium.
Building a "New Normal" on the Bedrock of Risk Management
Authors: Craighead Martin 
Published: February 2015

Guest editorial
Historically, our industry has been driven by a series of inflection points to re-examine best practices, technologies, or philosophies on how we conduct our business. The most notable of these have often been associated with tragedies such as the 1988 Piper Alpha disaster in the North Sea and, most recently, the Macondo disaster in the US Gulf of Mexico. Piper Alpha led to a wide-scale focus on health, safety, and the environment (HSE), fundamentally changing the way companies viewed safety, and led to orders of magnitude improvement in HSE practices. While the full impact of Macondo is only now being fully understood, it is clear that we will see a similar effect on the way we handle quality, competency, safety critical systems, and contingency planning.
In both of the incidents, external pressure precipitated the cultural or technical shift to a new operating norm, while the capabilities and technology for bridging the gap were available. Until we consider risk management and operational sustainability as business drivers and an equal part of our mission, we will never make the paradigm shift from a reactive to a proactive business model.
The industry’s goal should be an incident-free environment, but government regulation alone will not help the industry achieve that goal. The reservoirs our industry is targeting are more challenging, the environments are harsher, and the technology required is ever more complex. As an industry we must be willing to go far beyond what is regulated—we must fundamentally change the culture of our business to address risk management in our processes, our technology, our talent management, and our safety programs.
Consistent processes and procedures across our business are the foundation for this change. A common operating system not only ensures that we meet regulations in all areas where we work, but also establishes repeatable performance that takes us far beyond what is required. Generally, there is one best way to perform an activity, whether it is solving problems for our customers or developing new products and technology.
An operating system encompasses critical operation management systems and captures the latest information and best practices. Such systems are widely used in industries such as automobile and fast food. Of course, the challenges facing the oil and gas industry are more diverse and highly complex. However, in general, the companies that pay attention to every aspect of their business and work smarter to capture the true power of their intellectual property win in the market.
The Weight of the Mission
Authors: JPT staff _ 
Published: February 2015

Two things stand out about Expro’s Ax-s technology—it is capable and it is big. The scale of the device, whose name is pronounced “access,” shows the array of tools that may be called on to deal with production problems.
“The seven-year development project, which cost USD 200, produced a device that can be lowered on top of a wellhead with the brains of a remotely operated vehicle (ROV) capable of deploying any one of eight diagnostic and repair tools in minutes with a winch and tanks for glycol or other fluids needed on the job. When fully assembled, it stands at 110 ft high and weighs 237 tons.
Its competitors include companies such as Blue Ocean Technologies, whose Iris system is also certified to work in deep water. It weighs 25 tons, but it can only insert one tool at a time into the well. Change outs require pulling one tool to the surface and lowering another. All subsea wireline systems connect to the subsea trees with a well control package using valves and blowout preventers to contain what is inside the well.
(The term “tree” was coined when the flow control device consisted of a vertical pipe with hardware branching off of the trunk. Subsea wellheads are complex clusters of pipes, valves, and controls surrounded by a stout metal frame the size of a garage.)
The size differences show different design philosophies.
Expro designed its device to speed the work by offering a wider range of options, like a surgeon with an array of tools at hand to deal with the unexpected. Inside the pressure housing is a collection of eight tools, which can be altered to suit the job. An Expro illustration showed a diagnostic water tool, a cutting torch, a perforating gun, a plug, and a tractor to pull the strings through a horizontal well.
“Once it is on the well, it can change out wireline tools in 10 minutes,” said Matthew Law, technical manager of sales and marketing at Expro Ax-s Technology. “There are eight tools on board. It is more efficient than those with limited functions that must be pulled up to the surface to change out functions.”
He said the added speed of the work by the Ax-s, plus a day rate significantly less than drilling rigs, will allow workovers at one third the cost of a drilling rig.
Seeking the Lighter Side of Heavy Duty
Authors: JPT staff _ 
Published: February 2015

The weight of a deepwater riser requires a large vessel to bear the weight of the steel pipe running a mile or more from the surface to the ocean floor.
The Skandi Aker, which is equipped with a relatively small 7⅜-in. high-pressure riser for well maintenance and construction work, is more than 157 m long, about half the length of the largest cruise ships.
Innovators have taken on the challenge of building a riser that will allow smaller boats to do things now only possible with a rig or drillship. More than a decade of work has gone into solving the problem, and no one appears close to getting a product on the market.
Their motivation is the many people in the business who expect the added muscle that coiled tubing can provide when working on wells. “Oil companies want to be able, if they have a problem they have to get rough with, to have the equipment to get rough with it,” said Brian Skeels, emerging technologies director at FMC Technologies.
Several companies are looking for a way to use coiled tubing deployed off a construction vessel to deliver fluids to the well as a riser does. It would offer a conduit to the for jobs requiring fluids such as acid treatments. The challenge is to maintain enough tension on a pipe from a vessel that is rising and falling with the waves.
Baker Hughes is developing what it describes as a riserless coiled tubing intervention system. Unlike the riser, which provides a conduit for coiled tubing, this tubing would act as a pipeline carrying fluids directly into the well, said Lance Portman, vice president of coiled tubing and cementing at Baker Hughes. It could allow smaller vessels to do a greater range of work, for example, by delivering hydraulic fluids to power tools or acid to remove asphaltene.
“You have limited options with wireline. With coiled tubing, you have more options,” Portman said. The company developed a system to maintain the tension on the tubing with two devices: one on the boat to adjust for the heaving caused by the waves, and the other on the seafloor that maintains the tension on the tubing.
The project with Blue Ocean, which is providing the seafloor equipment needed to safely get the pipe into the well, is years away from having a system to sell.