bluuebunny/crossref_metadata_2025_split huggingface dataset:
Management: Moving Project Management to the Next Level of Performance
Authors: Holland Dutch , Skarke Gary 
Published: February 2015

What an extraordinary opportunity to see how conventional management thinking actually plays out in the real world. In 2005, a professional development event "packed the house" with 300 highly experienced senior project managers in the global oil and gas industry. No rookies with outlandish expectations or unrealistic goals while learning their craft occupied these seats. Just the opposite. These were skilled professionals at the hub of projects sometimes costing as much as the gross domestic product of a small developing nation.
If this sounds like a gathering of corporate happy campers engaged in rounds of back-patting, hold that thought. Lean back and digest what they said in a questionnaire about their profession's status within their energy company. Were they in tune with conventional management thinking or not?

Biggest Project-Management Challenges
On its face, the formal-sounding project management (PM) name would seem no more controversial than a business leader saying, "Business is a good thing." However, PM's history has been bumpier than a back country road, especially in the oil industry, which, ironically, thrives on policies, procedures, and protocol.
Consider questionnaire results about the greatest challenge faced by project managers in their oil industry organizations, in order of most frequent response:Getting PM recognized as a core work process. That includes differentiating PM from daily line management. That includes the reality that at most companies, supply chain, accounting, and procurement are typically viewed as formalized work processes that demand strict compliance. Why isn't project management viewed this way, too?Companywide adoption of standardized templates/approaches for conducting PM. More typically, different regions of the same company use different PM approaches, making global projects difficult to manage. These big projects are hard enough without having to squabble over whose template is best.Invest in PM. Commit to PM, then put teeth into the commitment. Hire experienced project managers, hire enough of them, provide comprehensive training and development, provide cross-training for managers outside PM, and encourage certification/support of the PM organization. Significantly, PM tools (such as software) were not an expressed concern.Acute time pressure to make PM work. And these were only the top complaints, with many other noteworthy ones including too many projects but too little time; little or no upper management acceptance; lack of consistency or templates; focus on company earnings forcing shortsightedness in project planning; being expected to perform magic with few or no resources, poor executive understanding, or undercommitment; and the overwhelming need to get the word out that PM is important.
Offshore E&P - Still More To Learn
Authors: Langley Diane 
Published: February 2015

Offshore, shallow or deep, is a realm unto itself in which technology and economics are entwined and constantly evolving. The technical agenda for the 2006 Offshore Technology Conference (OTC) May 1–4 in Houston promises to deliver the next chapter in offshore E&P. Approximately 40 technical sessions and more than 300 technical presentations are planned.
Seven papers chosen by OTC 2006 program organizers emphasize that the one sure thing is that the pressure is on the industry to maintain a healthy balance between high risk, steep cost, and reasonable reward. The technical papers discussed in this article are listed below.

Recent Findings in Anisotropy Estimation
The authors of paper OTC 17866 estimate parameters of depth-variant vertical transverse isotropy (VTI) from the first-arrival times recorded in a 3D vertical seismic profile (VSP) survey over a deepwater Gulf of Mexico (GOM) project. They use both conventional slowness inversion and a recently developed travel-time extrapolation technique. The authors are not aware of any depth-dependent estimates of anisotropy from VSP data done before their study. Their work confirms that 3D VSP acquisition geometry is ideally suited for estimating in-situ seismic anisotropy; however, the locality of anisotropy measurements is achieved only when local quantities are used. This is not the case when the horizontal slowness components are involved in the inversion process because they are influenced by lateral velocity variations in the entire overburden. "Correcting the horizontal slownesses for lateral velocity heterogeneity requires knowing the seismic velocity model with accuracy hardly attainable in practice," the paper states.
A VSP survey was shot in a spiral pattern, with waveforms recorded by 28 geophones placed in 100-ft increments at depths ranging from 17,528 to 20,228 ft. The first-break times were picked from the data. The authors apply both the conventional slowness and novel travel-time extrapolation techniques and obtain comparable estimates of anisotropy. The travel-time extrapolation method, however, better illustrates the accuracy of knowing the lateral velocity variations needed to achieve the locality of anisotropy estimates. "One subsurface feature—a salt body—profoundly influences our ability to estimate anisotropy from the VSP data," say the authors. "Its presence causes a decrease of the first-break times clearly seen in the northern portion of the survey. The salt outline is easily identified in the travel-time data (Fig. 1)." This case study reveals the problem with deriving anisotropy from the slowness surfaces; the presence of salt produces slowness distortions that are impossible to fit with any anisotropic model, forcing the authors to rely only on the data recorded outside the salt. Realistic constraints of parameters are discussed. "Our most interesting finding was the negative sign of the an ellipticity coefficient η," the authors say. "It remains to be understood whether the negative sign of η bears lithologic or any other significance."
Overview: Offshore Drilling and Completion (April 2006)
Authors: Gazaniol Didier 
Published: February 2015

And now, what? We have been experiencing high oil prices for several months, which quickly translated into high rig rates. Of course, rig market is one obvious direct consequence of the current economic context, but this might not be the only one.
During the past months, we have seen operators drilling deeper to look for (and find) reservoirs in places where geologists did not see reservoirs 10 years ago because of limitations of seismic technology or of geological concepts. These wells cost tens of millions of dollars, and even if the learning curve improves, they will remain expensive. This trend has started in the Gulf of Mexico, but this simple idea of drilling deeper could soon apply in the North Sea, west Africa, Middle East, or Far East—in fact, probably all over the world.
The established energy-demand growth also has the oil industry focusing on maximizing recovery from each reservoir. Of course, people may try enhanced oil recovery in the end to recover the residual oil, but the first answer is to drill for reservoirs that were bypassed or which previously were too small to be economical. In this respect, minimizing well costs will still remain a major objective. In the meantime, and even if costs increase, use of complex completions may increase: sound monitoring and remotely controlled multizone completions will be implemented more often to optimize reservoir management.
Once again, technology will allow us to face these new challenges. But this technology will not be enough if new generations of drilling and completion engineers are not attracted by our profession and well trained. This issue may be at least as challenging as the technical one. In both areas, SPE has a role to play, and it will.
Offshore Drilling and Completion additional reading available at the SPE eLibrary: www.spe.org
SPE 96154 "10K Dual-Splitter Wellheads: 1st Worldwide Application on the Development of an Offshore Gas Field," by J.B. Faget, Total E&P, et al.
SPE 99135 "Integrating Emerging Drilling Methods From Floating Drilling Rigs—Enabling Drilling Solutions for the Future" by J.R. Kozicz, Transocean, et al.
SPE 93866 "Deepwater Subsea Well Intervention—The Future Solution" by A.J. Dick, Expro Group
Available at the OTC Library: www.otcnet.org
OTC 17279 "Drilling Observations of Possible Hydrate-Related Annular Flow in the Deepwater Gulf of Mexico and Implications on Well Planning," by S.C. Williamson, BHP Billiton Petroleum Inc., et al.
Experiment Observations of Miscible Displacement of Heavy Oil With Hydrocarbon Solvents
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97854, "Experimental Observations of Miscible Displacement of Heavy Oils With Hydrocarbon Solvents," by D. Salama and A. Kantzas, U. of Calgary, prepared for the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 1–3 November.
The increased interest in secondary production (or post-cold production) of heavy oil and the rise of oil prices have renewed interest in solvent-based methods for heavy-oil recovery. Although the vapor-extraction (vapex) process is favored, other methods are worth investigating. Also, the relative merit of mass-transfer and viscous mechanisms in the overall recovery efficiency remains a topic of debate. This study of mass-transfer phenomena in heavy-oil/ and bitumen/solvent systems was performed in an effort to determine dispersion coefficients.

Introduction
Heavy oil and oil sands will be an important part of Canada's oil supply. One-third of the world's oil is in Canada in the form of heavy oil and bitumen. The world's heavy-oil resources total approximately 10 trillion bbl, nearly three times the conventional oil in place in the world. Alberta contains nearly 2 trillion bbl of oil. Approximately one-fourth of the oil production of Canada is from oil sands.
Here, in-situ recovery processes are thermal or nonthermal. Thermal processes use heat to reduce the viscosity of the heavy oil in situ, thus mobilizing the heavy oil. Examples include cyclic-steam stimulation, steam-assisted gravity drainage, and steamflooding. Nonthermal processes rely on dilution of the oil to reduce the heavy-oil viscosity. Examples include CO2 injection, miscible floods, and vapex.
Displacement in the case of immiscible floods, such as waterflooding, generally is not complete, but a fluid can be displaced completely from the pores by a miscible fluid. In the case of miscible fluids, there are no residual saturations. Hence, sol-vent floods present an attractive in-situ process for the recovery of the heavy oil. However, the major challenge in miscible floods is for the miscible phase to access a significant fraction of the resident oil.
In solvent-based enhanced-oil-recovery techniques, several mechanisms affect the rate of oil recovery, given that accessibility is provided. These mechanisms include mass transfer, viscous forces, and gravity drainage. The solvent diffuses and/or disperses into the heavy oil, reducing its viscosity. The solvent/oil mixture then drains and is recovered from the production well. This study focused on the mass-transfer process in miscible sol-vent floods by experimentally observing the miscible displacement of heavy oils by hydrocarbon solvents.
Q&A with W. John Lee
Authors: Lee W. John , Donnelly John 
Published: February 2015

Editor's Note: In recognition of SPE's 50th anniversary this year, JPT is conducting interviews with several Society luminaries about their careers, their relationship with SPE, and the changes they have seen in the oil and gas industry and the Society over the past several decades.

What SPE experience has been the most valuable to you professionally?
The SPE experience most valuable to me professionally has been writing all or part of three textbooks published by SPE. Regardless of whether I deserved a favorable image in the industry or not because of these books, I have found that they have opened doors for me all over the world ever since the first book was published in the early 1980s. For example, as a direct result of my books, I have been invited to speak to and consult with groups—such as SPE local sections, operating companies, and government agencies—all over the world. I continue to be amazed when engineers who have been practicing from one year to 30 years bring copies of one or more of my books for me to autograph when we meet for the first time in places like Billings, Montana; Moscow; Bogota, Colombia; or Bandung, Indonesia.

What SPE experience or honor has been the most valuable to you personally?
The DeGolyer Distinguished Service Medal. To me, providing service to other professionals, especially to students and young engineers, is our single most important task. To have been recognized by my peers as having succeeded, at least in part, is worth far more to me than all the technical recognition that SPE provides.

What are the most significant changes that have occurred in SPE since you joined?
The changes I regard as most significant include internationalization and the development of the electronic SPE. The Society's primary objectives have been to collect, store, and disseminate information. We do this so much more effectively now, and make it available to so many more people, than when I joined SPE that there is simply no comparison between then and now.

Do you see major differences in petroleum engineering graduates today vs. a decade or two ago?
Today's petroleum engineering graduates are fundamentally the same as a decade or two ago. Today's graduates have much stronger skills in information technology and they are much better at multitasking than earlier generations were, although sometimes at the expense of depth of knowledge about the information or methodology they use. However, at the core, I have always found a majority of students to be creative, motivated, and interested in making things around them better.
Drilling for Water and Life - The Human Side of Petroleum Engineering
Authors: Arscott Lyn 
Published: February 2015

In the 40 years or so that I have worked in the oil and gas industry, I have witnessed an impressive transformation in our industry's performance in protecting people and the environment. There are obvious business and legal drivers, but the success would not have happened without appealing to employees in our industry to be good stewards of the environment and to help others.
It is understood that our industry operates by permission of the public: no permission, no permits. Many companies have excellent programs for partnerships with the communities where they operate. Every year, SPE recognizes exceptional service to the public with its Public Service Award. SPE also has an active energy education program with the objective of improving the industry's public image. The Society encourages section members to get involved with local civic groups and to serve as speakers on energy issues. SPE also sponsors speakers to attend teachers' conventions and is starting a fund to help teachers buy teaching materials on energy education for classroom use and to help pay for education events and trips. The vision statement in the Industry Image section of the recently approved SPE Long Range Plan states: "Petroleum professionals are widely regarded as ethical, competent, environmentally sensitive, and providing a vital service to society." It is in keeping with SPE's tradition of community service that I share an opportunity for humanitarian service that requires the special skills of petroleum engineers.
In 2002, at the World Summit on Sustainable Development, the Johannesburg Declaration committed the 189 nations who signed it to develop concrete action to reverse the poverty, hunger, and disease affecting billions of people. The declaration endorsed a previous set of goals formulated by world leaders at the U.N. Millennium Summit in September 2000. One of the goals is to "reduce by half the proportion of people without access to safe and affordable drinking water and sanitation by the year 2015." A few years ago, a group of nongovernmental organizations combined to form the Millennium Water Alliance to coordinate efforts to save lives by providing clean water and sanitation to the world's poorest countries, where approximately 1.1 billion people lack access to safe drinking water and adequate sanitation.
Overview: Natural Gas Technology/Monetization (April 2007)
Authors: Vitucci John 
Published: February 2015

Our industry prides itself on the development of innovative and cost-effective technologies to address the world's ever-growing demand for energy. Technology is being developed and applied at an unprecedented pace to all parts of the natural gas supply chain, from production to distribution, as we continue to develop this resource into a leading global energy supply. Over the past year, industry news has highlighted technology developments in many of the downstream areas, including liquefied natural gas, international gas-pipeline projects, gas-to-wire applications, and clean fuels derived from natural gas.
In reviewing papers for this feature, I found that development of upstream technology to address production of the world's gas reserves is moving ahead at a pace that rivals downstream-technology developments. New gas resources are becoming more challenging to develop because of geological and reservoir complexities. Sustaining well productivity continues to challenge our production methods as more reservoirs tap unconventional gas, deep-horizon gas, and condensate reservoirs. The upstream sector is responding with an increased focus in developing new technologies to address these challenges. And it is being done in all sectors of the industry, from the national and major energy companies to service and equipment companies to research institutions.
The selected papers highlight just a few of the technologies that are being investigated, are under development, or are being applied to recovery and production issues. The papers describe newly developed methods to monitor and optimize production, address near-wellbore problems through optimization of methods in practice today, and discuss potential future applications in near-wellbore conditioning. Our choice in making natural gas a leading source of energy for the world will be driven by technology and by an industry investing in that technology today and tomorrow. I encourage readers to review the additional-reading list to gain a full appreciation for the wide spectrum of technology development under way throughout the natural gas supply chain.
Natural Gas Technology/Monetization additional reading available at the SPE eLibrary: www.spe.org
SPE 102100 "Phase Behavior Study of Hydrocarbon/Water/Methanol Mixtures at Reservoir Conditions" by V. Bang, SPE, U. of Texas at Austin, et al.
SPE 102773 "Effect of Wettability on High-Velocity Coefficient in Two-Phase Gas/Liquid Flow" by M. Noh, SPE, Reservoir Engineering Research Inst., et al.
SPE 102160 "Onshore LNG Production Process Selection" by S. Mokhatab, SPE, U. of Wyoming, et al.
Production of Heavy Crude Oil: Topside Experiences on Grane
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18240, "Production of Heavy Crude Oil - Topside Experiences on Grane," by S. Husoy and S. Hatlem, Norsk Hydro A/S, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.
Grane field production started in September 2003. Oil is exported to the onshore terminal at Sture in a 28-in. 212-km-long pipeline. Gas for injection is imported in an 18-in. 50-km-long pipeline from the Heimdal field center. Grane is the first oil field on the Norwegian continental shelf producing heavy crude. Close cooperation between Norsk Hydro's operations department, project-development team, contractors, and partners forms the basis for completing the Grane facilities on schedule, below budget, and without any serious incidents.

Introduction
Grane is the tenth field put into production by Norsk Hydro and is the first heavy-crude-oil (19°API) field on the Norwegian Continental Shelf. The full-length paper presents some of the challenges and experiences that Norsk Hydro as an operator has faced during field development and the production ramp-up period. Most of the challenges were well known beforehand, and the facility and organization were prepared accordingly. However, some of these challenges were underestimated. The production facility, including the organization, has been able to use the flexibility present to adjust directly or prepare temporary solutions while permanent solutions were developed and implemented.

Environmental Focus
The platform was designed to meet the zero-discharge philosophy of the operator. A disposal well was drilled as part of the predrilling campaign. This well was completed with 13 3/8-in. casing to an Oligocene sand reservoir 500 m true vertical depth above the oil reservoir. A drill-cutting slurrification unit in the drilling module grinds all drill cuttings and creates a seawater-based slurry. This slurry is injected into the disposal well.
A disposal well for produced water was drilled as the first platform-drilled well and delivers produced water to the same formation as the drill cuttings. No produced water is discharged to the sea under normal operation. Water treatment includes degassing and hydrocyclones. Grane is allowed to direct 10% of yearly produced water to sea; however, the water-injection system uptime was more than 95% in 2005.
The energy requirement for heating the oil is met by use of a waste-heat recovery unit that recovers energy from the exhaust of the turbines. This energy is transferred into the separation process by use of compact heaters. Heat transfer also is achieved from produced water before injection and from the crude before it enters the export pumps. The wellstream has a 70°C temperature entering the first-stage separator. Because sufficient separation of the crude is not achieved at this low temperature, heat is supplied upstream of the second-stage separator where inlet temperature is increased to 90 to 110°C.