bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Deepwater Exploration and Production (June 2009)
Authors: Olson Karen 
Published: February 2015

Technology Focus
Even in today's changing times, the challenges of deep water continue to demand new and innovative technologies. Explorers are finding new fields hidden tens of thousands of feet below the mudline, reaching depths that cannot be completed currently. To produce from these depths, companies are developing completion equipment rated to high pressures both in absolute and in differential terms. Successful qualification of new high-yield metal alloys is a key enabler for delivery of high-pressure/high-temperature completion-equipment solutions; specifically in the development of a 20,000-psi-rated surface-controlled subsurface safety valve, 15,000-psi-differential-rated completion equipment, and 30,000-psi-rated downhole-test-tool equipment. The current mechanical-property limits for high-yield metal-alloy materials must be extended with material solutions that provide robust corrosion performance.
Past experiences by many operators have led to a rigorous assurance process to ensure that new equipment will work and work the first time. Equipment statement of requirements, detailed design reviews along with comprehensive qualification plans, system-integration tests, and, potentially, field trials are part of the overall equipment-integrity assurance.
As we continue to explore in deep water, new horizons at depths never before completed demand new ideas and new technologies to enable development. As professionals working in the oil industry, we need to continue working together to find new ways to develop these deeper high-pressure reservoirs and then to develop the equipment to produce them. We need to keep that "can-do" attitude.
Deepwater Exploration and Production additional reading available at the SPE eLibrary: www.spe.org
SPE 113727 • "Optimizing Wireline-Gun-System Design and Perforating Performance for Very Late Changes in a Gulf of Mexico HP/HT Deepwater Well" by L. Sabbagh, SPE, Schlumberger, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 20022 • "Geohazard Assessment in a Deepwater Subsea Development—A Contractor's Perspective" by Roberto Bruschi, Saipem Energy Services, et al.
OTC 20087 • "Early Testing—Jabuti Extended Well Test" by J.R.C. Melo, Petrobras, et al.
Performance Improvement of Viscoelastic Stimulation Fluids With Nanoparticles
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113533, "Performance Enhancements of Viscoelastic- Surfactant Stimulation Fluids With Nanoparticles," by James B. Crews, SPE, and Tianping Huang, SPE, Baker Hughes, originally prepared for the 2008 SPE Europec/EAGE Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed.
The full-length paper introduces newly developed, select nanosized crystals with unique surface charges and explains how nanoparticle technology pseudocrosslinks viscoelastic surfactant (VES) rod-like micelles together to improve the fluid-loss control and proppant transport of VES fluids to a performance level similar to that of a crosslinked-polymer fluid (CPF). The nanoparticle-pseudocrosslinked VES-micelle fluid develops a wall-building pseudofilter cake on the face of porous media to control fluid loss.

Introduction
CPFs are the most common type of fluid used for hydraulic fracturing. These fluids can achieve high viscosities with low leakoff rates for a wide range of reservoir temperatures and permeabilities. With their efficient leakoff control, CPFs can be used to generate excellent fracture geometry in most reservoirs. They also have excellent proppant-suspension and -placement capability. However, one weakness of CPFs is the fracture-conductivity dam-age that occurs as a result of incomplete crosslinked-polymer filter-cake removal from the fracture.
Over the past decade, classical VES-fluid systems have been used for frac packs and conventional hydraulic fracturing. The composition of these fluid systems typically has been fresh water, salt [such as 4% potassium chloride (KCl)], and VES product. The classical VES-fluid systems have viscosity-dependant leakoff control into porous media and do not develop or leave filter cake on a fracture face. The advantage of this type of leakoff control is that no filter-cake damage occurs in the fracture. However, a disadvantage is that a significantly high amount of whole-gel leakoff occurs into the formation during a treatment, and most often insufficient treatment fluid remains in the fracture for generating proper fracture geometry. Additionally, no internal breaker technology has existed for VES systems until recently. The reliance on the external breaking mechanism has resulted in too frequent poor and incomplete VES-fluid cleanup from the treated reservoir.

Crosslinked Polymer vs. Pseudocrosslinked Micelles
Two key parameters for crosslinking polymers in an aqueous medium is the molecular weight of the polymer and the degree of polymer overlap. The more polymer overlap there is, the more intrapolymer (polymer-to-polymer) crosslinking that can occur. In almost all cases, crosslinking polymers significantly improves performance properties for hydraulic fracturing, such as much higher fluid viscosity, improved thermal stability, better proppant transport, and lower rate of fluid leakoff.
Enhancing Well Safety and Economics
Authors: Gala Deepak M. , Menard Bill , Nas Steve , Offner Mike 
Published: February 2015

Technology Update
As the “low-hanging fruit” of the world’s oil and gas accumulations are more fully harvested, so the industry has been forced into tackling more complex and challenging projects such as ultradeep prospects, deepwater applications, and high-pressure/high-temperature (HPHT) wells to continue fulfilling the world’s appetite for fossil energy. This has led to more widespread use of nonconventional techniques such as drilling with casing, coiled-tubing drilling, underbalanced drilling (UBD), and managed-pressure drilling (MPD), including pressurized-mud-cap drilling (PMCD), with their attendant well-control and safety challenges. Among these challenges are
Moderate to severe lost circulation
Formation damage as a result of having to kill the well before tripping pipe
Pore-pressure and fracture-gradient similarity, leading to kick/loss cycles and well-control problems
Use of snubbing techniques to trip the pipe in and out of the hole above the “pipe-light” depth, with the associated added cost and risk.
Overall operational safety
Operational economics
As a result, mitigating drilling hazards and reducing operational non-productive time (NPT) has become an extremely important facet of well operations.
Downhole-Isolation-Valve System
The need to address these challenges led to development of the Downhole Deployment Valve in the year 2000. This is an isolation-valve system consisting of a deep-set flapper valve that is run as an integral part of the intermediate casing string and set at a predetermined depth below the pipe-light depth, or deeper as operational requirements dictate, with a full-opening inside diameter equivalent to that of the casing. It is not a safety valve in the accepted sense of the word, in that it is not a fail-safe device, but rather is powered open and closed by the application of hydraulic pressure at the surface to one of two encapsulated control lines attached to the casing outside diameter (OD). The downhole isolation valve (DIV) can be run in two separate configurations, depending on operational requirements (Fig. 1).
Coiled Tubing Used To Fish Coiled Tubing From a Live Gas/Condensate Well
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 129507, ’Fishing Coiled Tubing From a Live Gas- Condensate Well With Coiled Tubing While Under Production,’ by B.I. Kang, B.S. Murugappan, SPE, O.K. Kwon, and G.J. Sinn, Korea National Oil; I. Foster and L. Robinson, Weatherford; and J.B. Elliot, SPE, R. Hampson, and B.L. McKinnon, Halliburton, originally prepared for the 2010 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 23-24 March.
This case study examines the techniques required to recover a coiled-tubing (CT) fish from a live gas/condensate well by use of CT. These procedures recently were implemented offshore Vietnam, where an extremely fluid-sensitive formation prevented killing the well because the formation likely would not have recovered. Using the techniques described in the full-length paper, a 1.50-in., 9,177-ft-long CT fish was recovered from a well while keeping the well on production.
Introduction
CT is used around the world as a common well-intervention technique, and its scope of usefulness extends into many areas, including CT drilling, logging, fishing, milling, debris cleanout, and gas lifting. As technology progresses, so does the usefulness of CT to the industry as a whole, and the physical boundaries of what CT can achieve are being pushed constantly. This can lead to an unplanned failure of the string while in the well.
When a CT string parts in hole, the resulting fishing operation can be dangerous and complex; as such, standard practice dictates that the well be killed as a first step to recovering the parted string. However, killing the well can introduce pressures and foreign fluids to any open formations, which can lead to permanent or long-lasting negative effects on well performance.
Background
While using CT for logging the production of a well offshore Vietnam, an uncontrolled gas breach at surface required a complete emergency shut-in of the well, and as a result, 9,177 ft of 1.50-in. CT was sheared at the blowout preventer (BOP) and dropped 5,489 ft to total depth. The deviation of the well varied between 30 to 57°.
At first, it was feared the fish might have buckled catastrophically after impacting the bottom of the well, in which case recovery would be nearly impossible. However, the top of the fish was later found to be at 5,538 ft from surface (just 49 ft below the expected depth of 5,489 ft); there-fore, only slight damage was expected to the bottom of the fish.
As is the usual first step to retrieve a difficult fish, it was proposed that the well be killed. However, the client company refused, stating that the extremely fluid-sensitive formation would likely not recover from any fluid damage and thus that killing the well would result in the loss of the well itself.
Comments: State of the Gulf
Authors: Donnelly John 
Published: February 2015

Editor's column
The mood at last month’s Offshore Technology Conference in Houston was decidedly upbeat compared with 2010, when the Deepwater Horizon accident had taken place in the US Gulf of Mexico only days before the conference. But the explosion and its consequences dominated discussion at this year’s conference, from improvements in blowout preventers to panel discussions involving company and government officials. One certainty arising from the accident appears to be more government oversight of the oil and gas industry.
Michael Bromwich, director of the US Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), announced that regulators will have authority over contractors involved in deepwater leases in addition to operators. “I am convinced that we can fully preserve the principle of holding operators fully responsible, and in most cases solely responsible, without sacrificing the ability to pursue regulatory actions against contractors for serious violations of agency rules and regulations,” he said.
The BOEMRE’s report on the accident will be released before the 27 July deadline, Bromwich said. That report will examine all aspects of the disaster, including the steps that operators and contractors took leading up to and after the accident as well as the effectiveness of the blowout preventer. It is still too early to say what new regulations governing blowout preventers might be forthcoming, he added. After the conference, Bromwich toured several industry remote monitoring centers to observe their operation up close. Many conference attendees said they were braced for a new climate in the Gulf, one that may include even more new regulations than have been implemented in the past year.
The Gulf will be slow to recover from the disaster, according to one new industry report. The study by consultancy Wood Mackenzie said that Gulf production fell 80,000 BOED in 2010 and will decline another 375,000 BOED this year because of the moratorium issued by the US government after the accident. Exploration drilling then will strengthen in 2012 and return to healthy activity in 2013. New projects will eventually allow Gulf production to rise beyond pre-accident levels in 2016, according to the report.
Last month, the US government approved Shell’s plan to drill in several deep-water locations in the Gulf. It was only the second deepwater plan approved by the government since the lifting of the deepwater drilling moratorium in October, both involving Shell discoveries. The Shell Appomattox field plan includes drilling eight wells in 7,200 ft. of water approximately 70 miles off the Louisiana coast. In the past year, the US government has approved plans for the drilling of 58 new offshore wells in the Gulf.
Drillable Mud Motor System Brings Step Change for Running Tubulars
Authors: Davis Lance , Al-Othman Abdulaziz 
Published: February 2015

Technology Update
Oil and gas well construction requires the installation of tubulars at a specific depth, prescribed for reasons of mechanics, formation pressure and wellbore integrity, or accessing reserves. Deepwater construction has an additional need to land all strings in the subsea wellhead with precision. The industry recognizes this as a most significant operation. There have many instances of failed well programs where critical depths have not been secured. A step change technology for this purpose has been created to reduce well construction risk, applicable to all casing strings, liners, and completion strings.
Introduction: Solving an Important Industry Problem
Adverse wellbore conditions, instability, irregularity, doglegs, and fill, among other factors, often result in inefficient, incomplete casing running operations in terms of nonproductive time and potentially lost production. If the rig is equipped to do so, it may be possible to overcome such problems by reaming. However, as casing strings get longer and heavier, and for rigs without a top drive or where other factors lead to a limited ability to rotate the casing, there has been little option but to accept that casing placement problems are just a “cost of doing business.”
The industry problem is clear, but there do not appear to be key performance indicators on the percentage of casings run to 100% of target depth. Well construction creates well integrity, ensured in part by following the plan, landing casing on depth, and obtaining a well cemented tubular. Cost of failure to run the casing to design depth can reflect many factors, including the costs of drilling unused hole; running, pulling, and rerunning casing; and any subsequent casing plan revision. There is also the potential cost to reputation for failing to deliver to plan.
In developing a new technology to address the problem, it is of primary importance to add no risk to the existing well control or casing running process. Ideally, for reasons of safety, operation of new equipment should not require additional personnel.
Q&A with Norman Gilsdorf, President, High Growth Regions for Russia, Central Asia, and Middle East, Honeywell International
Authors: Gilsdorf Norman 
Published: February 2015

Q&A
You were appointed to your new position last year. Can you tell us about your new role?
Honeywell recently made the decision to place more focus and emphasis on the Russian, Central Asia, and Middle Eastern markets. In order to do this, we wanted to employ a similar strategy to what we did in China 6 years ago—putting in place a leader who would be able to integrate all of our businesses and help with positioning Honey well with customers and partners in these markets.
What are Honeywell’s recent offerings for the oil and gas industry? Honeywell and its various subsidiaries offer a variety of products and solutions. UOP, a Honeywell subsidiary, recently acquired the US company Thomas Russell. This acquisition allows us to offer solutions to enable companies to deploy modular-packaged equipment units to remove gas contaminants and capture higher valued natural gas liquids such as liquefied petroleum gas (LPG). This is very interesting technology for stranded gas or gas that is in dispersed reservoirs such as shale gas and shale oil, which can be challenging to monetize otherwise. UOP also recently launched a new heavy oil technology for upgrading residue and the UOP methanol-to-olefins technology is seeing a lot of demand in areas with methane, particularly in places such as China. Overall, UOP continues to have technologies for gas processing, including membranes to remove CO2 and other contaminants.
On the automation advancement side, process solution developers such as Honeywell Process Solutions, in collaboration with oil companies, have made significant efforts to develop oil fields of the future, or smart fields. This will allow companies to be able to gather data from different wells and resources, allowing for more efficient management. For example, our software platform sits above the plant level and connects the plant through the enterprise resource planning system, allowing for safer operations and lower costs. It can also help the operator work smarter and more effectively.
Do you think that the recent shale revolution in the US will affect the Middle East?
I think it has already had an effect in the Middle East through its impact on the US market. Five years ago, several major US downstream players were in the process of backing down on production facilities in the US and were considering joint ventures and partnerships to build facilities in the Middle East or China. What is happening as a result of the shift toward shale is that several of these players have revived their operations the US, not just restarting their facilities, but also building new facilities.
Technology Focus: Coiled Tubing Applications (June 2013)
Authors: Misselbrook John 
Published: February 2015

Technology Focus
In the two previous JPT coiled-tubing features, I commented on the remarkable growth the coiled-tubing industry has seen in North America, resulting largely from the shale revolution. This growth attracted numerous new players into the industry, in addition to the capacity additions made by the existing service providers. Regrettably, such unrestrained growth is rarely accompanied by a matching level of service quality. This concern about performance prompted the selection of the first paper in this feature. Although this is just one service provider’s history of stuck pipe, it likely mirrors the performance of the industry at large and serves as a reminder to all operators of the risks inherent in being too rigorous in adopting a cookie-cutter approach to certain coiled-tubing operations. The authors are to be commended for their frank reporting of the issues.
In fact, the gallop toward ever-larger coiled-tubing strings has not been mirrored by increasing the size of the reels on which they are spooled. The result is that, in addition to increasing the hoop stress resulting from ever-increasing injection pressures, coiled tubing is being subjected to levels of strain that have not been encountered previously. This places strenuous demands on the bias welds in the strings and requires more-rigorous attention to string-fatigue management. This continues to be a focus of the industry, as does the slightly greater susceptibility of bias welds to pitting corrosion from recirculated formation water of varying origins.
While I am still on the subject of large-diameter coiled tubing, the second paper focuses on another aspect of the industry and highlights the level of engineering detail required of many coiled-tubing activities and is especially typical of large multiwell offshore projects. It serves as an example of the level of planning and professionalism required for multidisciplinary operations but also reminds us that many superficially basic well-intervention operations are never as simple as they might appear.
Finally, I could not resist a paper of a more theoretical nature because it addresses an activity of increasing importance to the industry—namely, extended reach—which, in turn, is the primary driver behind the use of larger sizes of coiled tubing. We need technology and the science behind it if we are ever going to come close to approaching the lateral reach available to the drillers.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 162797 New Coiled-Tubing-Deployed Multizone Stimulation Method Increases Reservoir Access by Tyson Dunlop, Halliburton, et al.
SPE 163910 Coiled-Tubing-Jet-Cutting Multiple-Stage Fracture Treating Improves Fracture-Treatment Techniques To Unlock Bypassed Reserves in Cotton Valley Sands, Dorcheat Macedonia Field, Magnolia, Arkansas by R.W. Pomrenke, Bonanza Creek Energy, et al.
SPE 163884 Development of a New Coiled-Tubing Life-Tracking Process by Kenneth R. Newman, KNewman Engineering
Comments: Capital Spending Declines
Authors: Donnelly John 
Published: February 2015

Editor's column
Both international and national oil and gas companies are putting tighter reins on capital spending this year, which is not only affecting merger and acquisition activity but could also impact expensive deepwater projects and total global oil supply growth.
The industry often must maneuver between the long-term view of financing complex, costly projects and appeasing short-term shareholder demands. This year is no different. After hearing repeated complaints from the investment community on what it sees as lackluster performance amid historically high oil prices, several large firms cut back spending this year. Most notable to cut were the largest Western majors ExxonMobil, Chevron, Total, Shell, and BP, according to investment banker Morgan Stanley. These integrated majors are cutting capital spending by 10% this year compared with 2013 to a total of USD 33 billion, according to Energy Intelligence Research and Advisory. Morgan Stanley now predicts that global oil supply growth will rise to just under 6 million BOPD before falling to 4.7 million BOPD during 2016–18.
Carbon Capture: Harnessing Carbon Dioxide in the Middle East
Authors: Henni Abdelghani 
Published: February 2015

Carbon Capture
The migration to ultra-mature production and concern about rising greenhouse gas emissions mean that the implementation of carbon capture and storage projects are coming into sharper focus than ever before in the Middle East.
Capturing carbon dioxide (CO2) and using it in enhanced oil recovery (EOR) is one strategy being widely adopted. Studies showing the region having one of the world’s highest per capita environmental footprints have led governments to look for ways to improve their rankings in greenhouse gas emissions.
So far, Oman is the only country in the region to have launched EOR programs on a large commercial, rather than pilot, scale in a bid to stem and reverse years of declining crude production. In Abu Dhabi, tertiary gas injection has been under way for decades at the Total-operated Abu Al Bukhoosh field with great success. As production in the region matures, more countries are expected to implement EOR programs.
The application of CO2 EOR provides two advantages for companies in the Middle East. It allows natural gas that would otherwise be used for injection into oil fields for secondary recovery to be freed up to meet domestic requirements, such as power generation and industrial use, or to limit the costly import of liquefied natural gas. Moreover, it helps limit emissions in the region.