bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas-Hydrate Production for Natural-Gas Storage and Transportation
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 93492, “Gas-Hydrate Production Technology for Natural-Gas Storage and Transportation and CO2 Sequestration,” by R. Masoudi, SPE, and B. Tohidi, SPE, Heriot-Watt U., prepared for the 2005 SPE 14th Middle East Oil & Gas Show and Conference, Bahrain, 12–15 March.
Gas hydrates (clathrates) are ice-like crystalline compounds that form under low temperature and elevated pressure conditions. Within the gas-hydrate lattice, water molecules form a network of hydrogen-bonded cage-like structures enclosing the guest molecules that generally comprise low-molecular-diameter gases [e.g., methane, ethane, propane, or carbon dioxide (CO2)]. Although hydrate formation can pose serious flow-assurance problems in the oil and gas industry, gas hydrates present a novel means for gas storage and transportation with potential applications in a wide variety of areas.
Introduction
The need for natural gas at lower costs is the challenge that drives the development of a new process for storing and transporting natural gas in the form of frozen hydrate. An important property of hydrates that makes them attractive for use in gas storage and transportation is their very high gas-to-solid ratio. In addition to the high gas content, gas hydrates are remarkably stable. When the gas hydrate, which is formed at a high pressure and low temperature, is returned to atmospheric pressure, dissociation begins at the surface and an ice film forms over the water that covers the surface and prevents further hydrate dissociation. This “self-preservation” effect causes the gas hydrate to remain stable at atmospheric pressure. These properties make natural-gas-hydrate (NGH) technology very attractive for natural-gas storage and transportation and CO2 sequestration.
Economics
For small- to medium-sized gas fields, hydrate technology is an appropriate alternative to the well-established liquefied-natural-gas (LNG) technology. LNG technology is economically feasible only in large-scale projects. Compared to alternative technologies such as LNG and gas to liquids, NGH technology is relatively simple, low cost, and does not require complex processes or pressure and temperature extremes. Capital cost of NGH technology is approximately 25% lower than the capital cost of LNG technology.
Hydrate Production
There are fundamental interests in continuous production of NGH in a large-scale reactor and effective long-term storage of gas in clathrates. NGH production accounts for more than 60% of the costs of the NGH chain. Development of an efficient technique that is practical and economical for mass production of gas hydrates is vital for realizing NGH technology. There are a number of technical challenges to be addressed in development of a cost-effective NGH production process.
Effect of Formation-Water Salinity on Water-Shutoff Gels
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93005, “Evaluation of the Effect of the Water Formation Salinity on the Performance of Gels for Water Shutoff,” by M.A. Llamedo, SPE, I.J. Fernández, D.L. Pérez, O. Rauseo, E. Valero, and J. Espinoza, PDVSA-Intevep, prepared for the 2005 SPE International Symposium on Oilfield Chemistry, Houston 2–4 February.
An acrylamide-based polymer cross-linked with organic reagents is commonly used in water-conformance treatments. This study tested the gel against water of various salinities. It was found that the gel swelled depending on the difference between the salinities of the water used to prepare the gel and that of the added water. The performance of this gel in porous media was evaluated by coreflood experiments.
Introduction
The aqueous gels prepared from crosslinking reactions of water-soluble polymers are used to reduce the formation permeability in water-conformance treatments. There still are many questions regarding the behavior of gel inside porous media. One question is how the reservoir fluid affects the gel. This work studied the influence of the difference between the salinity of the reservoir water and that of the water with which the gelling system was prepared.
Gel is an intermediate state between liquid and solid. As a result of this dual character, gels can exhibit intermediate properties between cohesion of the solid and transport of the liquid. The polymer network holds the liquid in place, and the liquid pre-vents the networks from collapsing into a compact mass. These gels have the capacity to swell or shrink according to the external media against which they are put in contact. A gel can swell or shrink when there are changes in the external environment (e.g., pH, temperature, and salinity).
Previous studies on gel swelling demonstrated that small changes in the external conditions, such as ionic strength or an external electric field, can induce drastic changes in the state of the swollen network. In particular, under certain conditions, poly-electrolyte gels may undergo a discontinuous volume change. The volume of gel is influenced by osmotic pressure.
Cuttings Transport With Foam Under Simulated Downhole Horizontal Conditions
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 99201, "Experimental Study on Cuttings Transport With Foam Under Simulated Horizontal Downhole Conditions," by Z. Chen, SPE, R.M. Ahmed, SPE, S.Z. Miska, SPE, N.E. Takach, SPE, M. Yu, SPE, and M.B. Pickell, U. of Tulsa, and J. Hallman, SPE, Weatherford Intl. Ltd., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.
The use of drilling foams is increasing because foams exhibit properties that are desirable in many drilling operations. A good knowledge of cuttings-transport efficiency under downhole conditions is essential for safe foam drilling. Previous cuttings-transport studies with foam were limited to low-pressure and ambient-temperature (LPAT) conditions. An experimental study of cuttings transport with foam in a horizontal annulus was performed under simulated downhole conditions.

Introduction
Foam drilling fluid can provide low density as well as flexibility in equivalent-circulating-density (ECD) control. However, the complexity of foam flows makes it difficult to obtain reliable predictions of ECD for foam drilling. When drill cuttings are in the wellbore, the foam/cuttings mixture affects bottomhole pressure, making the complicated compressible foam flow even more complex. Therefore, cuttings transport with foam should be well understood for accurate bottomhole pressure and ECD estimation.
Studies on cuttings transport by foam fluids are limited. Although cuttings in foam affect hydraulics calculations and ECD predictions, it is generally accepted that foam cuttings transport in vertical wells is very efficient. Foam-flow velocity of 120 ft/min is sufficient for most vertical-well foam drilling; in some cases, flow velocity as low as 70 ft/min has been successful. For foam drilling in horizontal wells, the particle-settling velocity is perpendicular to foam-flow direction and drill cuttings tend to settle to the low side of the wellbore. The density of drill cuttings is much higher than the density of foam. Therefore, the mechanisms that govern cuttings transport are different for horizontal wells. Empirical correlations and models developed for vertical wells may not be valid for horizontal and inclined wellbores. This research project studied cuttings transport with foam in simulated downhole conditions for more-reliable bottomhole pressure and ECD predictions.

Experimental Study
Experiments of cuttings transport in foam were conducted at the Advanced Cuttings Transport Facility at the U. of Tulsa. The facility is designed to investigate cuttings transport and hydraulics of both compressible and incompressible drilling fluids under elevated-temperature and -pressure conditions. The facility can simulate both pipe and annular flow at pressures up to 1,500 psig and temperatures up to 200°F for incompressible Newtonian and non-Newtonian fluids. It also accommodates compressible fluids such as aerated fluid and foams.
Overview: Drilling and Completion Fluids (November 2006)
Authors: Scott Paul D. 
Published: February 2015

In reviewing the fluids-related papers to be featured in this issue, I was struck by the wide range of choices that exists for drilling and completion fluids today. We are no longer constrained to the use of a handful of basic water- or oil-based fluids, clear brines, or simple pneumatic fluids to do our job.
Likewise, we are no longer limited by a few surface measurements and basic concepts to describe and understand the physical behavior of the fluids that are used. Clearly, this increased selection and our ability to test, predict, monitor, and understand the behavior of all wellbore fluids have contributed greatly to the success of our industry in drilling increasingly complex and challenging wells.
Professionals who make decisions about fluids have more challenges than ever before. These challenges include overcoming marketing glitz and information overload to understand when and where true benefits can be derived from use of nonstandard fluids and more-complex-fluid analysis.
Normally, I get on my "plastic-viscosity/yield-point" soapbox here, but what comes to mind is that we are challenged to remember and use the basic engineering science behind what we are doing, most of which was described by the previous generation of SPE professionals in the classic papers with paper numbers below 10000.
I encourage you to read the summaries and review the list of "additional reading" papers that follow. Then I challenge you to take the next step and read the entire paper for the topic that is of greatest interest to you. And once you have done that, review the references and consider the classic SPE papers that laid the foundation for the work being presented—if you have never read them, do yourself a favor and take the time to do so.
Regardless of whether you are evaluating the most-challenging high-cost well to be drilled this year helping to access the next deepwater giant field or a series of assembly-line low-cost wells that help the industry access unconventional resources, knowing your fluids choices and understanding when and where to use them can make the difference between success and failure.
Drilling and Completion Fluids additional reading available at the SPE eLibrary: www.spe.org
SPE 99080 "How To Unify Low-Shear-Rate Rheology and Gel Properties of Drilling Muds: A Transient Rheological and Structural Model for Complex-Well Applications" by B. Herzhaft, Inst. Français du Pétrole, et al.
SPE 96342 "Selection and Evaluation Criteria for High-Performance Drilling Fluids" by K. Morton, Chevron Energy Technology Co., et al.
SPE 97018 "Evaluation of Equivalent Circulating Density of Drilling Fluids Under High-Pressure/High-Temperature Conditions" by O.O. Harris, SPE, U. of Oklahoma, et al.
Fate of Nonaqueous-Drilling-Fluid Cuttings Discharged From a Deepwater Well
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98612, "Fate of Nonaqueous-Drilling-Fluid Cuttings Discharged From a Deepwater Exploration Well," by T.J. Nedwed, J.P. Smith, SPE, and H.R. Melton, SPE, ExxonMobil Upstream Research Co., prepared for the 2006 SPE Eighth International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Abu Dhabi, UAE, 2–4 April.
The full-length paper describes results of a study of the fate of cuttings drilled with nonaqueous drilling fluids (NADFs) and discharged into a deepwater environment. The study characterized effects of discharges from a single-well drilling program and tested the accuracy of a discharge model that predicts seabed cuttings accumulations.

Introduction
Drilling programs increasingly use NADFs to drill more-challenging wells, such as those in deep water or those requiring highly deviated wellbores. Recent field studies have addressed the environmental effects of the discharge of cuttings drilled with NADF. Similar physical, chemical, and biological phenomena control the fate and effects of drilling discharges in all water depths. However, greater water depth could influence discharge fate and effects by providing increased opportunities for dispersion or other changes in cuttings properties during settling to the seafloor. The full-length paper details a study that used novel deepwater sediment traps to sample drill cuttings as they arrived at the seabed.

Method
Drilling Program. An exploration well was drilled to a total depth of 2430 m below the seabed in 950 m of water in the south Atlantic. Over a 9-day period, NADF was used to drill the bottom 1790-m section of the hole with a 12 1/4-in. drill bit. To separate cuttings from drilling fluid, drilling-fluid returns were processed with a conventional solids-control system comprising two shale shakers operated in series. The cuttings removed from these shakers were discharged 13 m below the sea surface.
Discharge Monitoring. The volume of NADF cuttings discharged was estimated by use of the wellbore volume of the NADF-drilled length plus a 7.5% washout. Drilling records of the length of hole drilled each day were used to correlate discharge volumes and times with ocean-current measurements.
Discharged Material. Drill-cuttings samples were collected at five depth ranges during drilling to determine base-fluid content and particle fall velocity. Base-fluid content was determined by dichloromethane extraction followed by total-petroleum-hydrocarbon (TPH) concentration measurement by a gas-chromatography/flame-ionization detection (GC/FID) method. GC/FID results indicated that the detected hydrocarbons in cuttings were identical to those in the NADFs. As a result, TPH concentration can be considered equivalent to base-fluid concentrations for cuttings samples. Measured cuttings-settling times in a laboratory settling column filled with seawater provided data on cuttings-particle fall-velocity distributions for use in modeling.
Techbits: ATW Leads to Formation of Group To Promote In-well and Subsea-Based Fiber-Optic Monitoring Systems
Authors: JPT staff _ 
Published: February 2015

After the first in-well optical-sensing-system installation in 1993, the oil and gas industry has been pursuing optical sensing as a means of improving reliability and developing new capabilities for in-well reservoir-monitoring applications. Since that first installation, the industry has built a track record with more than 100 installations of permanent pressure and temperature gauges, optical flowmeters, and seismic arrays and hundreds of distributed-temperature-sensing (DTS) installations. But virtually all of these installations have been in dry-tree and land wells.
In 2005, discussions began on soliciting SPE's help in organizing an Applied Technology Workshop (ATW) that would increase awareness in the upstream industry of the potential for widened application of in-well optical-sensing systems in subsea applications and help identify the challenges and barriers facing widespread market acceptance—and then possibly lead to a plan that addresses these obstacles.
After a full year of preparation, an SPE ATW titled "In-Well Optical Sensing—Subsea Well Applications: Are We Ready?" was held in February 2006 in Galveston, Texas. Cochairing the event were Brian Drakeley (Weatherford International) and Brock Williams (BP), and they were joined on the Technical Program Committee by Lars Vinje (Statoil), Herbert Lescanne (Total), Brian Llewellyn (Chevron), Rod Fors (Shell), Garth Naldrett (now of FloDynamic), Ted Drell (FMC Technologies), and Matthew Smith (Deutsch), representing a cross section of companies involved with this emerging technology. The workshop was attended by approximately 130 people from Brazil, Canada, France, Germany, Indonesia, Japan, Norway, the United Kingdom, and the US.
Informative educational sessions were held, starting with presentations covering the types of in-well optical-sensing systems currently available and those under development. These includedPressure and temperature sensorsFlow and fraction metersOptical accelerometers for seismic sensingDistributed temperature sensingDistributed pressure sensing
A number of case histories for these systems were also presented, which varied from the good to the bad to the downright ugly! The openness and honesty of a number of the presentations and the ensuing discussions were very much appreciated by those present and set the ATW off to an excellent start.
Management: The Challenge of Lessons Learned: Overcoming Barriers to Successful Application
Authors: Dressler Don , Palen Walt 
Published: February 2015

We have all seen this before: A project team realizes too late that the approach taken or the operational equipment deployed has failed—and it is not the first team to come to that conclusion. If only the lessons learned by others had been sought and applied early in the project.
Look at another scenario: A team learns a valuable lesson during the project but manages to repeat the same mistake again. Perhaps the blame lies in a personnel change or the lack of a systematic way of incorporating the lessons learned earlier. The bottom line is that the team pays the price twice for not learning from experience.
The above examples illustrate the challenge of effectively applying lessons to improve individual, team, and company-wide performance. Industry surveys confirm the spotty track record of effectively benefiting from lessons learned. A 2007 Ernst & Young survey found that 91% of respondents believe that lessons-learned reviews yield valuable results, yet only 13% perform reviews on all programs. The findings from a LogicaCMG survey in 2006 concur, with 51% of the respondents believing that knowledge is poorly managed.

The Nature of Lessons Learned
So what do we mean by a "lesson learned"? It is important to establish an operational definition because the term can mean many things to many people. A lesson learned describes the knowledge gained when results of a project or activity differ from expectations. The difference can be quite dramatic—such as understanding what led to a spectacular success vs. an abysmal failure. The bigger the gap, the greater the potential there is for learning. A smaller gap also has value in highlighting opportunities for continuous improvement.
A lesson can be very simple and explicit, or it can be complex, and the capture or recording of each differs. An example of a simple, explicit lesson involves the proper use of a piece of equipment. These often can be captured straightforwardly and accurately. Complex lessons, on the other hand, often involve much more subtle concepts; the proper interpretation and application of such lessons hinge upon understanding the context or situation. Capturing complex lessons also requires careful judgment and experience because improper application can be disastrous. Application of complex lessons requires "tacit" knowledge that is difficult to write down and often is best shared through a face-to-face dialogue with those who have the experience and knowledge.
Overview: Drilling and Completion Fluids (November 2007)
Authors: Scott Paul D. 
Published: February 2015

Drilling and completion fluids are the lifeblood of each well drilled. The effective use of fluids technology and an under-standing of fluid behavior can mean the difference between success and failure. Fluids have a significant influence on rate of penetration; amount of trouble time; cementing success; health, safety, and environment issues; time to drill and complete; and the ultimate reservoir performance for many wells.
There you have it—know what you are doing with regard to drilling and completion fluids, and you will easily outperform your peers. For those of you who do not take the time to sort fact from fiction and insist on rigorous engineering evaluation of the fluids you use, good luck. Take a look at the industry statistics, and crunch the numbers. The value lost to fluids-related problems is an enormous economic drain on the industry and a huge opportunity lost.
Last year, I wrote about today's increased understanding in fluid behavior and the increased number of fluid options we have today; that trend continues—but pick your tools carefully. If you could have read between the lines last year, you would have noticed that I indicate that there are fewer classic papers these days, too little rigorous science applied to drilling and completions fluids, and too much commercial publishing. Those trends also continue.
The Editorial Committee members who write these overviews also pick the technical papers summarized and highlighted in each issue. To those whose papers were selected, congratulations. To those who did not make the short list, thank you for the contribution. For those of you who are business associates and friends, please understand that I raise the bar for those closest to me.
Take time to read the summaries, and note the suggested additional reading; all seven papers are keepers.
Drilling and Completion Fluids additional reading available at the SPE eLibrary: www.spe.org
SPE 103336 "Drilling Fluids in an HP/HT Reservoir: Experiences With Three Different Systems on the Kristin Field Development" by S.A. Hansen, SPE, Statoil, et al.
SPE 103934 "Successful Drilling of Oil and Gas Wells by Optimal Drilling-Fluid Solids Control—A Practical and Theoretical Evaluation" by B. Dahl, Statoil, et al.
SPE 103731 "HP/HT Drilling-Fluids Challenges" by Ron Bland, SPE, Baker Hughes Drilling Fluids, et al.
SPE 103088 "Apparatus for Measuring the Dynamic Solids-Settling Rates in Drilling Fluids" by R. Murphy, SPE, Halliburton, et al.