bluuebunny/crossref_metadata_2025_split huggingface dataset:
Management: Plugging the Knowledge Gap
Authors: Davidson John 
Published: February 2015

There once was an engineer who had an exceptional gift for understanding and fixing any kind of machine. After a long career with the same company, he happily retired. Several years later, the company contacted him regarding a problem with a piece of production equipment that seemed to be impossible to fix. They had tried everything, but nobody could return the equipment to full capacity. After much persuasion, the engineer flew out to the platform and spent a day studying the equipment. At the end of the day, he marked a small "x" on a component and stated that replacing this component would solve the problem. The component was replaced and full production was restored.
Shortly after, a bill for U.K. £50,000 was received. Very unhappy with this, the company asked for an itemization of the bill. The engineer responded briefly:
One chalk mark: £1.
Knowing where to put it: £49,999.1
While this story is fiction, the problems described are real. Organizations that do not make a concerted effort to plug the knowledge gap will find themselves relearning, or renting, old knowledge at a high cost. It is no secret that the demographic profile of the oil industry is heavily weighted toward the baby-boom generation. What is not clear is the impact that this will have on the industry in years to come. Will the demographic time bomb go off and leave the industry in crisis or is this an overly pessimistic viewpoint? There is a real issue here that needs to be tackled, and the tools and techniques for doing so are well established and easily implemented. The key to avoiding critical knowledge loss, however, is a strategic framework that weaves together the ability to learn with the ability to retain key staff and to make a knowledge-sharing culture a reality.

Framework for Knowledge Retention
For a business to avoid knowledge loss, a strategy needs to be in place with the following key objectives for the organization:
The organization must be able and willing to learn, in addition to the individual.Knowledge must be recoverable from staff and contractors.It must be easy to transfer knowledge when required.Human resources (HR) processes and practices must help knowledge retention.Information technology (IT) applications must support retention practices.

Organizational Learning
Kim2 defines individual learning as "increasing one's capacity to take effective action." If we assume that this definition can also apply to organizations, then organizational learning is about increasing the organization's capacity to take effective action—including maintaining aging platforms. The question then is, When we look at organizational learning, who is doing the learning?
Overview: Mature Field Revitalization (January 2006)
Authors: Lagerlef David 
Published: February 2015

The challenge. It has always been before us, but it is now asked of us by family members, neighbors, and total strangers once they find out we work in the petroleum industry: "Can the oil and gas industry meet world demand over the next few years?" I think the answer can be found in the papers selected for this feature and in other quality technical presentations on this subject. Projects around the globe are discussed, which have been implemented to maximize the use of existing infrastructure and improve recovery by revitalizing mature fields.
Paper presentations and displays on the exhibit floor at the SPE 2005 Annual Technical Conference and Exhibition in early October also served as a solid indicator that the industry is poised to meet the challenge successfully. Individual companies continually strive toward ensuring that the energy supply meets demand; replacing reserves is a high-profile key performance indicator. SPE plays a vital role in aiding the effort. The technology, techniques, and talent shared in the various SPE venues are sometimes applied directly in another field, but more often, improvements in these three areas are made with subsequent applications. Innovation flourishes as applications that worked in one mature asset are modified to fit the specific requirements for another mature asset. The specifics cannot always be applied directly, but the process of studying about production improvements, having a service company representative explain details of a tool with the help of a cut-away model, or witnessing the enthusiasm during a well-prepared paper presentation can lead to the derivation of new approaches to revitalizing mature fields. So, when you have finished reading the summaries of the selections, and perhaps downloaded the full-length papers as well as some of the other technical references, I hope you arrive at the same answer to the question that I did. We will meet the challenge.
Mature Field Revitalization additional reading available at the SPE eLibrary: www.spe.org
SPE 93697 "Integration Tools To Streamline Reservoir Management and Field-Development Workflows for Mature Fields in South Oman," by M.A. Naguib, SPE, Petroleum Development Oman, et al. [See JPT (October 2005) 56.]
SPE 94360 "Significant Production Enhancement in Uzen Field, Kazakhstan, Through Surface and Subsurface Optimization," by S.J. Sparke, SPE, Gaffney, Cline & Assocs., et al.
Old Field - New Life
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94669, "New Life to an Old Field," by J.S. Swanson, SPE, and D.C. Swanson, SPE, Grail Quest Corp.; M. Jarvis, Penn Virginia Oil & Gas Corp.; and R. Hall, SPE, Grail Quest Corp., prepared for the 2005 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 3-5 April.
The East Tunstill field is a tight, undersaturated sandstone reservoir with a 9% recovery factor on primary depletion. Marginal production and a previous relatively unsuccessful waterflood did not show the potential value of the field. A detailed analysis revived the field.

Challenge
To increase the value of this field, within a limited budget, new procedures and methods were necessary. A project workflow had to be designed to analyze the field characteristics, taking into account the high number of wells and many years of production, which provided a large amount of useful data.
The operator believed that an improved reservoir description applied with simulation methods could yield a better understanding of reservoir drainage, fluid movement, and the volume and location of the remaining oil. Additionally, the operator decided to use a volumetric-balancing technology that enabled quick analysis of various waterflood injection/producer patterns to determine the most economical and efficient flood pattern and, thereby, demonstrated the field's potential.

Background
The East Tunstill field is in the Delaware basin in Loving County, Texas. Discovered in 1959, cumulative production is estimated at 2.9 million bbl of oil, 8.2 Bcf of gas, and 5.8 million bbl of water. The field produces from the Delaware Olds formation, in the upper Bell Canyon sand series. An improved reservoir-description study with reservoir parameters yielded estimated original oil in place (OOIP) of 30 million bbl.

Project Workflow and Methodology
The operator initiated the project with two main goals as follows.Confirm existence and volume of remaining recoverable oil and its location.Design a development plan for the most efficient maximum economical oil recovery.

Data Preparation
The first major step in the workflow was the geologic study, including a detailed stratigraphic analysis as well as a review of the depositional facies on the basis of field-core information. The knowledge of the facies supported the biased mapping of the reservoir, which then determined the controlling characteristics and flow paths of the reservoir fluid. To complete the static reservoir description, basic reservoir parameters were applied to calculate the OOIP.

Dynamic Analysis
Once the OOIP was determined, the process determines how fluids were drained or produced over time. The fluid movement (involving both production and injection) was tracked in the reservoir over the life of the field by use of volumetric balancing. This method uses the following data sources.Base map with well locations and completion information.Net sand/facies map depicting the remaining reserves recovery.Original-hydrocarbon-in-place maps.Well-production history.Well-injection history.
Overview: EOR/IOR (January 2006)
Authors: Pitts Malcolm J. 
Published: February 2015

Papers in this feature discuss the incremental oil production from three field projects that use three different enhancement technologies: biotechnology, or microbial enhanced oil recovery (MEOR); miscible gas; and mobility-control polymer.
Petro-Tech Peruana S.A. reported an impressive improvement after inoculating two pair of production wells in different offshore fields. Both fields contained a paraffinic crude oil that, when treated by conventional wellbore-cleanup technologies, simply maintained oil-production rates. Biotreating the producers resulted in improved oil rates, and subsequent radial inoculation further enhanced oil rates, approximately doubling the pre-MEOR rates.
A peripheral, downdip, high-pressure gas-injection project in the RKF field in Algeria also is impressive. The paper discusses the discovery, development, and operation of a miscible-gas-cycling project in a fluvial complex of carboniferous reservoirs of low-permeability, high-clay-content formation containing asphaltic crude oil and salt-saturated water. During 8 of the 9 years of operation, production was maintained at approximately 20,000 B/D. A tracer study to quantify well conductivity and help identify preferential flow was implemented early in the gas-injection phase. Additional laboratory studies to support continued numerical simulation were performed, with the objective of continued studies being to define and select options that would improve oil recovery as gas injection continues.
Three mobility-control pilot projects in Brazil complete the trio of papers. Four polymer pilot projects were started in 1997, 1999, and 2001 in the Carmopolis, Buracica, and Canto do Amaro fields, respectively. Mobility ratios ranging from 2 to 12 for water displacing crude oil provide a motive to implement the different mobility-control-polymer pilot floods. Injectivity changes and differences in interwell tracer studies are reported. Oil production increased, and declining water/oil ratios are discussed for each pilot and for well patterns within each pilot. These projects emphasize the importance of an ongoing evaluation and study of an EOR flood to maintain oil production and maximize oil recovery. Continual monitoring of project performance and reaction to what is happening in the field, making adjustments as necessary, and learning from performance are essential for successful expansion as well as for continued operation.
EOR/IOR additional reading available at the SPE eLibrary: www.spe.org
SPE 94139 "Application of Tracer Technology for Optimizing RKF Miscible-Gas-Injection Recovery—Field Case," by H. Cubillos, SPE, Cepsa, et al.
SPE 94808 "Twenty Years of Steam Injection in Heavy-Oil Fields" by J.C. de Souza, Petrobras, et al.
SPE 93100 "Sorption of Surfactant Used in CO2 Flooding Onto Five Minerals and Three Porous Media," by R.B. Grigg, SPE, New Mexico Recovery Research Center, et al.
SPE 93241 "Gasflood Flow-Pattern Evaluation: Mesozoic Chiapas-Tabasco Basin Field Revisited," by M. Mercado, Pemex, et al.
Overview: Well Intervention and Control (January 2006)
Authors: Barnett David 
Published: February 2015

This year, we have witnessed the continuation of a general upward trend in the worldwide rig count that started in the second quarter of 2002. The Baker Hughes U.S. rig count published 11 November 2005 stood at 1,479. In the U.S. alone, this increase translates into at least 12,500 people being hired to work on the approximately 750 rigs put to work in the last 3 years. Almost 4,000 of those people were hired to man the 228 rigs placed in operation during the last year alone. One must wonder what effect this growth has on the number of well-control situations encountered.
The first line of defense against well-control events is a knowledgeable rig crew—not just the tool pusher and driller, but each person on the crew. Inexperience shows up in different forms at various levels. There have been many cases in which routine kicks were allowed to escalate into critical situations because someone did not report what should have been an obvious sign of the well flowing. An example: an inexperienced floor hand sees flow over the shale shaker with the pumps off but is not aware of the significance.
The upper-level positions of the rig crew and the drilling supervisor are expected to have the knowledge and experience to deal with influxes effectively when they occur. Inexperience at this level often results in kicks being taken that should have been avoided and routine kicks being allowed to escalate because of improper handling. Inadequate circulation before pulling out of the hole and improper implementation of kick-circulation procedures are often-cited examples that result in these situations.
Keeping experienced personnel on the rigsite during a sustained upswing, such as the one we have experienced over the last few years, is a monumental task. Fortunately, there seems to be an increased awareness of the importance of this experience compared with the last "boom" cycle. This awareness can be seen in the additional focus on rig-crew training and other structured programs designed to minimize well-control incidents. Consequently, the number of serious well-control events is, at least for now, well below the proportionate increase in the rig fleet. Operators and drilling contractors that are driving these efforts should be commended.
Well Intervention and Control additional reading available at the SPE eLibrary: www.spe.org
SPE 92626 "Modeling Ultradeepwater Blowouts and Dynamic Kills and the Resulting Blowout-Control Best-Practices Recommendations," by Samuel F. Noynaert, SPE, BP, et al.
SPE 93956 "High-Pressure/High-Temperature Coiled-Tubing Intervention Operations in the North Sea Within the Past 2 Years," by A. Turner, SPE, Halliburton, et al.
SPE 92594 "Development of a Screening System To Identify Deepwater Wells at Risk for Annular-Pressure Buildup," by U.B. Sathuvalli, SPE, Blade Energy Partners, et al.
Guest Editorial: The Winds of Change: Resource Nationalism Shifts the Balance of Power to National Oil Companies
Authors: Stark Pete 
Published: February 2015

The oil and gas industry is in the midst of a critical transition driven by a series of factors, including the Asian energy-demand crunch of 2004, the 2005 hurricanes in the Gulf of Mexico, and recent low discovery rates. These factors, coupled with political uncertainties, threats to petroleum infrastructure, production disruption resulting from civil unrest, and limited access by international oil companies (IOCs) to giant resources in the Middle East and the former Soviet Union, have ushered in what has been referred to as the "Age of Energy Supply Anxiety."
In addition, higher oil prices and mounting political pressures, combined with a bit of anti-Americanism and rapidly growing demand for energy in the Asian market (particularly in China), are stimulating producing countries to increase control of their oil and gas resources and move toward resource nationalism. The resulting global scramble by both IOCs and national oil companies (NOCs) to secure hydrocarbon resources has altered the industry's competitive landscape significantly, which in turn has caused a major shift in the balance of power favoring the NOCs, mandating new perspectives on negotiations and partnerships.
No longer are NOCs managing only state-owned hydrocarbon resources to their nation's long-term benefit, they are also expanding internationally to secure the additional energy resources necessary for sustainable economic growth for their countries. In other words, NOCs are becoming international exploration companies, competing with IOCs at home and in the world marketplace.

The Effect of a Paradigm Shift
Considering that governments and NOCs control more than 80% of the world's remaining oil reserves, are expanding and upgrading refineries and infrastructure, and are developing gas resources, the effect is considerable. But that has not always been the case. In the past, when oil prices were low, investments in exploration dropped, and governments were eager to create incentives to attract investments—including reducing tax rates and state participation, or providing royalty relief.
All that changed in 2003 when oil prices began to soar. Many countries—primarily those with immense resources such as Russia, Nigeria, Libya, Angola, and Venezuela—reversed gears and raised taxes and/or increased state participation in hydrocarbon licenses. In Latin America, where the public's perception was that oil and gas companies made excessive profits at their expense, energy policies have become highly regulated.
Increases in state-take range from 2% in Angola to 24% in Nigeria and 43% in Argentina. In Algeria—formerly known for being one of the most welcoming countries for foreign energy investors—a new government decree was enacted at the beginning of September 2006. Arguing that this decree safeguards the role of Sonatrach, Algeria's NOC, it specifies that Sonatrach will be given a 51% stake in all upstream development projects as well as midstream pipeline and refinery projects.
Overview: EOR/IOR (January 2007)
Authors: Pitts Malcolm J. 
Published: February 2015

Reserves are a key factor for any oil company. This year's EOR issue highlights field projects that increased reserves by use of enhanced oil recovery. Economic incremental-oil production from field projects that used three different technologies [CO2 huff ‘n’ puff, mobility-control polymer, and steam-assisted gravity-drainage (SAGD)] is discussed.
Daqing Oilfield Co. Ltd., People's Republic of China, has several papers discussing its commercial polymer flood. An SPE Advanced Technology Workshop on chemical flooding in Daqing concluded with Daqing stating that 25% of its production results from polymer injection—250,000 B/D. One paper stated, "Unquestionably, the application is successful, and the accumulated output has exceeded 70 million tonnes" (more than 500 million bbl of oil). Of interest is a closely spaced pilot to expand the polymer flood to marginal reservoirs. The strategy was injection of different-molecular-weight polymers in a staged manner, from low to high molecular weight, into zones with permeabilities appropriate for the injected polymer. Reported oil rates increased 1.8 times in confined production wells. Ultimate oil recovery beyond waterflood was 11.7%, of which 5.2% resulted from polymer flooding.
Sixteen CO2 huff ‘n’ puff projects were conducted on different wells in the Forest Reserve oil field in Trinidad and Tobago over the last 20 years. CO2 from an ammonia plant was injected into either inactive or poor oil producers. Average slug size was 1 MMscf of CO2 per foot of sand, with a 3- to 5-day soak period. Multiple huff ‘n’ puff cycles were effective in more than half the wells, with the second to fourth cycle being the most productive for the majority of wells. Oil-rate improvements from nothing to up to 60 times pre-CO2-injection values were observed.
During the startup and early operation of horizontal SAGD wells, it is important to understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood, the distribution of steam, injected either at the heel or toe of the steam injector, can be adjusted to optimize the startup and early operation of the SAGD pair. Total E&P Canada permanently installed optical fiber along its first Joslyn SAGD production well to monitor the temperature profile continuously during startup and production.
Thus, good engineering, technology, and a willingness to try different approaches can increase reserves in very large as well as smaller applications.
EOR/IOR additional reading available at the SPE eLibrary: www.spe.org
SPE 101202 "Study of High-Concentration Polymer Flooding To Further Enhance Oil Recovery" by Yang Fulin, Daqing Oilfield Co. Ltd., et al.
SPE 100117 "Application of Smart-Well Technology to the SACROC CO2 EOR Project: A Case Study" by J. Brnak, Kinder Morgan Production Co. LP, et al.
SPE 100346 "Suplacu de Barcau Field—A Case History of a Successful In-Situ Combustion Exploitation" by A. Panait-Patica, Petrom S.A., et al.
Screening Criteria for Carbon Dioxide Huff 'n' Puff Operations
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100044, "Screening Criteria for Carbon Dioxide Huff ‘n’ Puff Operations," by L. Mohammed- Singh, SPE, Petrotrin, and A.K. Singhal, SPE, and S. Sim, SPE, Alberta Research Council, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April.
The full-length paper reviews design and performance data on 16 CO2 huff ‘n’ puff projects in the Forest Reserve oil field of Trinidad and Tobago from the past 20 years. Huff ‘n’ puff operations essentially are near-wellbore stimulation techniques that can lead to increased oil recovery by removal of productivity damage, reduced oil viscosity, increased dissolved-gas content, oil swelling, and vaporization of lighter oil components.

Introduction
The first huff ‘n’ puff experimental project in Trinidad and Tobago was conducted in 1984 in the Forest Reserve oil field. For the Forest Reserve reservoirs with medium-to-heavy crude oils, viscosity reduction and oil swelling aided by gravity drainage and water encroachment are believed to be the most significant mechanisms contributing to increases in oil recovery.
The literature contains many screening criteria for enhanced-oil-recovery processes. However, for CO2 huff ‘n’ puff operations, these are generally included in those for immiscible gas-flooding applications. The full-length paper proposes screening criteria for huff ‘n’ puff operations on the basis of results from the Forest Reserve oil field and other published field tests.

Reservoir Description
The Forest Reserve oil field contains multiple, stacked, complex deltaic reservoirs. The rock and fluid properties of the four reservoirs (targets for huff ‘n’ puff operations) are listed in Table 1 in the full-length paper. Oil gravity ranges from 14 to 25°API, with in-situ viscosities of 12 to 3,000 cp. Reservoirs are solution-gas drive with contributions from water influx.

Operations and Production Response
CO2 was compressed to 1,000 psi and injected until desired slug volumes were achieved. Wells were shut in, left to soak for 3 to 5 days, and back flowed. Wells were subjected to several cycles (5 cycles maximum). A total of 2,092 MMcf of CO2 was injected and 101,635 bbl of oil recovered from the 16 wells tested.
Responses varied from none to a maximum of 12,000 bbl in one cycle. The production cycle generally lasted more than 6 months and as much as several years in some wells. An average of 6,300 bbl per well was recovered, with one well achieving 31,000 bbl.
Some of the wells that showed good responses were in downdip locations and possibly benefited from water influx and gravity drainage during the puff phase. Updip wells that yielded good recoveries also were near faults, which may have helped in providing containment and efficient capture of the mobilized oil.
Five wells experienced mechanical difficulties and were excluded from the following analyses.