bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydrate Inhibition in Headers With No Production Flow
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90127, "Hydrate Inhibition in Headers With No Production Flow," by B. Herrmann, SPE, Independent Consultant; C. Bargas, BP; and S.J. Svedeman and J.C. Buckingham, SPE, Southwest Research Inst., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
When deepwater subsea production is shut in for long periods, measures normally are taken to prevent the formation of hydrate blockages in the flowline net-work. One common inhibition method is to inject methanol into the jumpers, manifold headers, and wellbores. Experiments were conducted to investigate the distribution of inhibitor injected into a static (no production flow) header or bore that contained oil, water, and gas. The test results were used to help develop a more effective header design and to develop operating guidelines for inhibiting after shut-in.
Introduction
Upon shutdown, gravity causes fluid in a subsea header to separate. Free gas migrates to the top portion of the header and water to the lower portion, separated by a layer of oil. If the shutdown is for a prolonged period, normal practice is to pump two volumes of methanol into the header to mix with the water. The assumption is that the alcohol mixes with water, preventing methane from bonding with the water to form hydrates.
How the methanol mixes with water is not obvious. In a static system, gravity distributes the oil, gas, and water as well as the methanol. If the methanol is lighter than the oil, it floats on top of the oil and pools at the oil/gas interface. If the methanol is heavier than the oil, it floats along the top of the water and tends to pool at the oil/water interface. Sometimes the headers are sloped to prevent water from accumulating in the dead end. In this case, when methanol is lighter than oil, the injected fluid will pool at the top of the oil and displace the heavier fluids out of the header until enough methanol has accumulated that it can flow out of the header itself. However, if the methanol is heavier than oil, it will pool at the bottom of the oil layer and displace oil out of the system until enough methanol has amassed that it flows out of the header into the next section.
A high water cut will influence the relative density of the methanol mixture and complicate the dispersal. Some of the methanol mixes with the water, and this “heavy” mixture pools at the oil/water interface. However, after a period of time, pure methanol collects at the top of the mixture and moves to the oil/gas interface.
The only mixing of methanol and water occurs when the methanol comes in contact with the water. The methanol-injection rates are small compared to the volume of the header, so the methanol flow is laminar. Thus, diffusion of methanol into the water is very slow. Moreover, it can occur only where a sufficiently large percentage of water exists that the injection point is inside the water volume or the methanol is heavier than the oil and it pools on top of the water.
Deepwater DST Planning and Operations From a DP Vessel
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90557, "Deepwater DST Planning and Operations From a DP Vessel," by Robert J. Stomp, SPE, ConocoPhillips Co.; Graham J. Fraser, The Expro Group; and Stephen C. Actis, SPE, Luke F. Eaton, SPE, and Kerry C. Freedman, ConocoPhillips Co., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
ConocoPhillips is developing the Magnolia field with a tension-leg platform (TLP) in 4,674 ft of water in the U.S. Gulf of Mexico (GOM). The field was discovered in 1999, and appraisal wells were drilled in 2000 and 2001. The precompletion and drillstem-test (DST) operations overcame several challenges, including frac packing a thick, fine-grained interval and well testing from a dynamically positioned (DP) semisubmersible drilling rig while simultaneously transferring produced hydrocarbons to a transportation barge moored to the rig.
Introduction
The Magnolia asset team was formed in 2001 before drilling the last appraisal well. Front end loading leading up to field sanction in December 2001 included concept selection and field development plans. The Magnolia field would be developed from a TLP to provide direct vertical access for recompletions, future sidetrack drilling, flow assurance, and cost-effective remediation.
The Magnolia development wells were predrilled (i.e., drilled from a mobile offshore drilling unit while the TLP was being built). The advantages of predrilling included minimizing capital exposure risks until shallow water-flow sands were isolated, allowing TLP well operations to be conducted with a lighter, lower-cost completion rig, which would further reduce the size and cost of the TLP hull; additional reservoir characterization before TLP installation; accelerating plateau production; and testing completion techniques in the precompleted well before “batch” completions of the remaining wells.
The B-25 reservoir, the primary pay horizon at the Magnolia field, was the zone selected for a DST. Zone B-25 is characterized throughout the field by its highly laminated sequences and large gross thicknesses. Whole-core data and fluid samples were obtained from the GB783-2ST2 appraisal well. Evaluation of the appraisal-well data classified the reservoir-rock matrix as a coarse siltstone with the average mean grain-size diameter of 41 µm. Overall, the mean grain-size diameters ranged from 25 to 71 µm in Well GB783-2ST2.
Test Objectives
The objective of performing a precompletion DST was to obtain critical information regarding completion design and reservoir issues. This information would be needed before the planned batch-completion program scheduled to begin in the fourth quarter of 2004.
The Prestige Wreck Fuel-Recovery Project
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17534, "The Prestige Wreck Fuel-Recovery Project," by R. Hernan, A. del Corral, C. Berenguer, SPE, R. Paez, J. Sparrowe, and J. Moro, Repsol YPF, originally prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.
This article is an overview of the recovery project to extract the hydrocarbons remaining in the wreck of the Prestige tanker. The ship, carrying approximately 77 000 tonnes of heavy fuel oil, broke up and sank in 3850-m-deep water in November 2002, 240 km off the northwestern coast of Spain. During the sinking, and for a period of several months afterward, a large amount of fuel was spilled, ending up mainly on the shores of Galicia. Repsol YPF, though in no way connected to the vessel or its cargo, was appointed by the Spanish government to recover the fuel remaining inside the wreck. Extraction of the remaining fuel was carried out in 2004 by use of large-volume aluminum shuttles. An innovative core-flow technique was used to extract this extremely viscous fuel (500 kPa·s at the shuttle offloading conditions) from the shuttles and offload it into a floating storage and offloading (FSO) vessel. Finally, bioremediation was used to accelerate the biodegradation of the remaining immobile fuel.
Project Summary
On 19 November 2002, the oil tanker Prestige broke up and sank in two parts. Approximately 37 000 tonnes of heavy fuel was believed to remain in the wreck, which continued leaking. The Spanish government commissioned a permanent solution for stabilizing the wreck and neutralizing its cargo. Potential solutions included the use of shuttle tanks to transport oil from the wreck to a surface container, pumping the oil to the surface by use of a riser system, and enclosing the whole wreck in a sarcophagus.
Fuel viscosity at the wreck conditions was extreme (3 to 4×106 kPa·s), which, at this depth, precluded the use of conventional techniques. Repsol YPF (with technical assistance from BP, Eni, Petrobras, Statoil, and Total) outlined an action plan to be completed in 2003. The plan approved by the Spanish government consisted of the following.
- Develop work-class remotely operated vehicles (ROVs) to operate at 4000 m water depth.
- Seal all remaining leaks.
- Carry out data acquisition on the wreck and its fuel composition and mobility, as well as on the environment and the marine soil, to assist future interventions.
- Test a batch-extraction scheme that used shuttle bags.
- Perform basic engineering studies of confinement solutions as an alternative if the above scheme did not work.
Sonsub was hired as the main contractor, and, in the spring and summer of 2003, it carried out an offshore campaign for the above program to establish the basis for the actual fuel recovery planned for 2004.
Technology Tomorrow: The Chemistry of Carbon Capture and Storage
Authors: Pike Richard 
Published: February 2015

Editor's note: This is the third installment of a yearlong series designed to stimulate discussion in research and development. The oil and gas industry faces the prospect of progressively increasing CO2 production because of the presence of CO2 in produced natural gas and the fact that petroleum production is becoming heavier. However, the industry is uniquely positioned to sequester CO2, no matter the source. This article features the perspective of an expert outside the oil and gas industry regarding the challenges associated with CO2 capture and storage. Comments on articles in the Technology Tomorrow series are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.
Evidence linking anthropogenic carbon emissions with climate change is accepted by many experts, and the key challenge now is to act to avert disaster. Countries signed on to the Kyoto Protocol and those that have set more stringent domestic targets are now defining energy policies that balance energy efficiency and energy technologies alongside measures for energy security. In the U.K., the government is currently reviewing its energy policy and is examining a range of policy and technological measures that will secure clean and affordable energy for the long term while meeting the U.K. target of reducing carbon emissions 60% by 2050 (based on 1990 levels). It is widely expected that the U.K. will continue to rely upon fossil fuels for electricity, transportation, and heating for the foreseeable future, and, therefore, it is important that carbon-abatement technologies are employed when feasible.
The chemical sciences have played a crucial role in optimizing energy output from fossil fuels through developments in areas such as combustion chemistry and fuel additives. The chemical sciences will be critical in providing future energy technologies such as batteries, fuel cells, solar power, microgeneration, energy-efficient lighting, new nuclear power and nuclear waste management, and carbon capture and storage (CCS).
CCS is not a new technology. In fact, there are a number of examples of its application around the globe (e.g., in ammonia production). It has been predicted that CCS technologies could reduce carbon dioxide (CO2) emissions from power plants (and other energy-intensive processes such as oil refining and steel and cement manufacturing) by up to 85%. However, the technology will reduce the energy efficiency of power plants significantly and increase the cost of energy production, according to the Intergovernmental Panel on Climate Change (Table 1).
Management: It's Time for an Industry Initiative on Heavy Oil
Authors: Belani Ashkok 
Published: February 2015

Last year, five of the 10 largest development projects in the world were going after heavy oil. When oil experts assure outsiders that there are significant petroleum reserves yet to be developed, they are talking about the class of crude that is so difficult to produce, transport, and refine that many companies have stayed away, until now.
What has changed, of course, is supply and demand. Asset managers know they cannot ignore it any longer; if they want to book new reserves, they have to look at heavy oil. There is also some urgency to produce the heavy oil associated with lighter reserves. The reason is transportation. Heavy oil is often blended with conventional crude to make it light enough to flow through a pipeline. If operators wait until the lighter crude is gone, their heavy oil assets may become stranded.
The good news is that heavy oil reservoirs can be huge. What is more, the wells tend to produce at a steady rate and for much longer than conventional wells. Some heavy oil operators producing 100, 000 BOPD expect to maintain that rate for 15 or 20 years. Total recovery of the oil in place can be as great as 70% for certain processes, which is much better than the rate for lighter crudes. While a handful of companies have been producing heavy oil for decades, many more are just entering the game. The knowledge gap between those two groups is large, but even the most experienced players face new challenges.

The Nature of Heavy Oil
Tip a beaker of heavy oil and chances are it will not run out, at least not right away. One definition of heavy oil is any hydrocarbon with a gravity of 22.3° API or below. On the lighter end, that includes oil with the consistency of honey. At room temperature, ultra heavy oil can be as thick as peanut butter. Motor oil has a gravity of approximately 35° API.
Refiners often use API gravity to describe and set the price of heavy oil. For reservoir engineers, however, the more important number is viscosity, because that tells them how well the heavy oil is likely to migrate through the reservoir. Although there is a correlation between gravity and viscosity, the distinction is misleading. Heavy oils with the same gravity can have very different viscosities.
Historically, heavy oil has come from relatively shallow reservoirs. Most are less than 500 m (1,650 ft) deep, but some new plays are as deep as 2700 m (9,000 ft). Even that is not a limit. At greater depths, temperature plays a big role in the ease of production because any oil flows better when it is hot. Keeping heavy oil flowing is the trick. That is a particular challenge in cold climates, or when producing heavy oil from subsea wells.
Overview: Deepwater Exploration and Production (June 2006)
Authors: Barnes John 
Published: February 2015

Deepwater oil and gas projects are some of the most challenging of human endeavors. The sheer size of many of these efforts—and the impressive new technologies used—is truly amazing. Deepwater projects also entail great risk, however, and things sometimes do go wrong. Of course, things go wrong on all types of projects, but the deepwater environment itself and the large-scale nature of many projects exacerbate the severity of any problem. Costs can increase to many times the budget, the details associated with implementing new technology can be overwhelming, and schedules easily can slip enough to jeopardize the commercial success of the project.
Some problems are related to project decisions that are made to maintain schedule before all of the needed facts are available. On a complex project, decisions are made that, in retrospect, are clearly wrong. Other problems arise simply as a result of mistakes made by the project management or technical teams. To be successful, the project team must be willing to recognize mistakes as early as possible and take corrective action. Knowledge of how mistakes were addressed on previous projects, both successfully and unsuccessfully, can be invaluable in selecting an appropriate corrective action.
Examining lessons learned from previous projects provides one of the most important methods for improving project execution. Barry LePatner, an attorney testifying before a U.S. House of Representatives Science and Technology Committee on disclosure of information from building failures, made the following observation:
"Good judgment is usually the result of experience. And experience is frequently the result of bad judgment. But to learn from the experience of others requires those who have the experience to share the knowledge with those who follow."
The sharing of project-management lessons learned on deepwater projects, however, is a relatively recent development. Project management is as important to the success of deepwater projects as technology. The continued sharing of project-management lessons learned would help project teams meet the myriad nontechnical challenges associated with deepwater projects.
Deepwater Exploration and Production additional reading available at the OTC Library: www.otcnet.org
OTC 17971 "Albacora Leste Deepwater Field: Improvements on Well Construction," by E. de Melo Sanches, Petrobras, et al.
OTC 17806 "Combined Effect of Flowline Walking and Riser Dynamic Loads on HP/HT Flowline Design," by M.S. Brunner, Technip U.S.A., et al.
OTC 18311 "K2 Topside Facilities—Design Challenges," by F. Colbert, OFD Engineering LLC, et al.
OTC 17655 "The Significance of Gas Hydrate as a Geohazard in Gulf of Mexico Exploration and Production," by M.A. Smith, U.S. Dept. of the Interior, Minerals Management Service, et al.
Characterization of Defects in Coiled Tubing From Magnetic-Flux-Leakage Data
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100121, "Observations on Characterization of Defects in Coiled Tubing From Magnetic-Flux-Leakage Data," by T.R. McJunkin, K.S. Miller, and C.R. Tolle, Idaho Natl. Laboratory, prepared for the 2006 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 4-5 April.
The full-length paper presents observations on use of magnetic-flux-leakage (MFL) data to detect flaws in coiled-tubing (CT) strings. Sixty-six flaws of various shapes and types, ranging from 0.3-mm-deep pits to 9.5-mm-long slots, artificially created in 44.45-mm-outside-diameter pipe, were analyzed. The detection algorithm and the information extracted from the data are described.

Introduction
CT defects reduce CT life and must be detected to prevent costly failures in the field. One method commonly used for CT nondestructive inspection is MFL, where a magnetic field is generated with a coil or permanent magnets and Hall-effect sensors positioned around the CT measure the variation in the field near the CT surface. Flaw characterization is important for failure-prediction models. The size and shape of a flaw influence MFL-signal amplitude and duration and are directly related to expected CT-string life. The full-length paper describes an effective method of detecting flaw signatures in an MFL signal.

Equipment and Processes
A laboratory-scale experimental CT MFL-sensor head was constructed. The coil used to create the field in and around the CT was an 89-mm-long solenoid with a 102-mm inside diameter. One-thousand four-hundred turns of 18-gauge copper wire were wound evenly along the length of the coil. Data presented in the full-length paper were acquired by use of a 5-A direct current in the coil. This current was sufficient to saturate the pipe and permit flaw detection on the inner surface of the CT. Plastic frames, or "shoes," were populated with three ratiometric linear Hall-effect sensors oriented orthogonally in cylindrical coordinates (i.e., radial, longitudinal, and circumferential). Five shoes were distributed circumferentially around approximately one-fourth of the circumference of the CT samples. Artificially created defects were moved past the sensors, with the defect centered approximately on the middle of the five shoes.
Data from the Hall-effect sensors were acquired at a 2000-samples/s rate. A first-order low-pass Butterworth filter with a 100-Hz cutoff frequency was used as a digital filter. The time-series signal was converted into distance vs. amplitude by adjusting for scan velocity and sample rate.
Guest Editorial: What Big Oil Can Learn From Big Blue
Authors: Perrons Robert K. 
Published: February 2015

Let's face it: everyone likes to feel special. It is therefore somewhat understandable that decision makers in the energy industry often believe that trends and patterns that have emerged elsewhere in the business world do not apply to the oil patch. "The oil business is different!" they proclaim. "That could never happen to us!"
But sometimes we are not exempt from the immutable forces that shape the rest of the business community. Decidedly unoriginal concepts such as supply and demand do tend to be reliable predictors of oil and gas prices, and prospective investors scrutinize energy companies' profit and loss statements as closely as those from any other industry. It therefore follows that we might be able to learn from other sectors from time to time. The evolutionary history of IBM—frequently referred to as "Big Blue" in the business press—may offer just such an opportunity.
The oil and gas sector historically has been very slow to develop and adopt new technologies, and relative investment in R&D by Big Oil traditionally has been only a fraction of that spent in other industries. But the industry is being forced to change. Future hydrocarbon resources—particularly in non-OPEC countries—will tend to be deeper, harder to find, and in environments that are significantly more difficult to access. There can, therefore, be little doubt that technology will play a pivotal role in the success or failure of tomorrow's oil and gas firms.
This sharper focus on technology is shaking up the strategic fundamentals of our industry. Many years ago, when innovation was less critical, much of the oil and gas sector's technology came in the form of know-how and experience that was often uncoded, nonverbalized, and embedded in organizational routines. A country with hydrocarbon reserves usually enlisted the assistance of international oil companies (IOCs) to gain access to engineers who collectively held the knowledge required to turn the country's energy resources into revenue. The know-how required to achieve this end was both difficult to reproduce and hard to get from any source other than a handful of firms.

A Shift to Science
As the industry has been forced to reach for more technically ambitious reserves, however, this uncoded knowledge is giving way to technologies that are based less on experience and more on hard science. While decisions might have been made a generation ago with rules of thumb and gut instinct, data now reign supreme. Reservoirs are modeled in three or four dimensions with high-end computers not unlike those used by NASA, and the entire production system can be monitored by "smart" sensors that allow engineers to observe various aspects of its performance. Rules of thumb will probably always be handy for engineers, but today's oil and gas technologies are frequently too complex for unaided human judgment.