bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Contract Between Management and the Petrotechnical Professional
Authors: Edmundson Henry , Bamford David 
Published: February 2015

Talent & Technology
The continued search for oil and gas relies in equal measure on good management and superior petrotechnical expertise. The key is ensuring that the two worlds mesh smoothly and create a working environment that motivates both parties to succeed. This is less obviously achieved than might be thought for a number of factors.
First is the scarcity of top-quality petrotechnical professionals (Fig. 1). This used to be blamed on the famous “crew change,” which described the paucity of recruits during the oil price crash of the 1980s. But things have now changed. The past few years have seen abundant recruiting by both operators and the service industry, and the crew change problem has morphed into the challenge of accelerating the development of thousands of young professionals to fill the still prevalent mid-career gap. The result is an industry obsessed with accelerating employee development.
Second is the market force generated by the continued lack of midcareer petrotechnical professionals. These lucky individuals command a price in excess of their equivalent managers, and so even do the young aspirants joining their ranks. With the oil price robust around USD 100/bbl and global upstream activity buoyant, there remains an extraordinary lack of competent geoscientists, drilling engineers, and petroleum engineers. And they know it. Never has it been so easy to jump ship, hoping for a better future.
Third is the meeting point between management and the petrotechnical expert. Both obviously aspire to business success, but beneath broad corporate goals lurk important differences. In companies of any reasonable size, managements must ensure that their machine to find and extract oil and gas is properly assembled, well lubricated, and working to maximum efficiency. Standards and discipline are important; within well-defined limits, employees are expected to conform.
The technical expert, however, marches to a different tune, motivated by quite different criteria. When it comes to creativity and improving technical knowledge, petrotechnical professionals prefer less rather than more management, or even no management. The ideal state is being self-directed; satisfaction comes from solving tough technical problems. When it comes to their career, peer recognition and involvement is as important as management input. In short and at risk of working an analogy beyond breaking point, the square peg that is the technical expert may not always fit the round holes of the smooth-running business machine. How to manage this less-than-exact fit requires some unusual strategies.
Technology Focus: Reservoir Simulation (July 2014)
Authors: Bailey William 
Published: February 2015

Technology Focus
As the development of shale oil and gas becomes increasingly significant, so does the need for modeling tools for their accurate and timely forecasting. The basic question then arises: Are the simulation tools that we have suitable for the job? Can they explain, and ultimately forecast, the contribution to flow from natural or hydraulically induced fractures? Ultimately, we need to be confident that the results from such models are sufficiently reliable for decision-making purposes. As Alexandre Emerick stated in JPT (April 2014), “The goal is to generate models for production forecasting aiding the decision-making process involved in the development and management of petroleum reservoirs.”
The ability to model this increasingly important asset class is one of the primary issues facing reservoir and simulation engineers today. Our existing arsenal of simulation tools is certainly time-tested for conventional assets, but can they deliver reliable forecasts for this emergent class? Recent literature is rich with relevant studies ranging from fundamental laboratory experiments to entirely empirical, data-driven, approaches for predictive reservoir management. These articles raise numerous questions, including the possible oversimplification of a complex problem, the very nature of the production mechanisms, and the role played by any pre-existing discrete fracture networks.
Additional concerns relating to accuracy and reliability of the underlying data used to populate such models have also been raised. Keeping an open mind on this topic is, I feel, appropriate. One needs to balance the very real need for such predictive tools today with the recognition that future evidence may disrupt certain preconceptions. To this end, four articles have been selected that span a spectrum of ideas. One considers practical applications and solutions, while another covers the emerging technique of molecular simulation. Another eloquently probes various notions in our current state of understanding of shale assets and examines issues in interpreting the forecasts furnished by our simulation models. The fourth article demonstrates some creative thinking by representing a planar fracture by use of a proxy comprising a coupled flowing network model, a concept that may prove flexible and warrants further investigation.
Conventional modeling tools used to predict flow in tight, fractured shales (e.g., dual-porosity models, local grid refinements, tartan grids) may, indeed, provide reliable forecasting. Analytic and data-driven approaches are also acceptable in some circumstances. However, as our knowledge in exploiting these assets deepens with new theory, laboratory experiments, and field and operational experience, we should be prepared to reconsider some of today’s axioms in the future.
A Critical View of the Current State of Reservoir Modeling of Shale Assets
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165713, ’A Critical View of Current State of Reservoir Modeling of Shale Assets,’ by Shahab D. Mohaghegh, SPE, Intelligent Solutions and West Virginia University, prepared for the 2013 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 20-22 August. The paper has not been peer reviewed.
The coupling of hydraulic fractures and natural-fracture networks and their interaction with the shale matrix remains a major challenge in reservoir simulation and modeling of shale formations. This article reviews methods used to understand the complexities associated with production from shale to shed light on the belief that there is much to be learned about this complex resource and that the best days of understanding and modeling how oil and gas are produced from shale are still ahead.
Introduction
Preshale Technology. The phrase “preshale” technology aims to emphasize the combination of technologies that are used to address the reservoir and production modeling of shale assets. In essence, almost all of the technologies used today for modeling and analysis of hydrocarbon production from shale were developed to address issues that originally had nothing to do with shale. As the shale boom began, these technologies were revisited and modified in order to find application in shale.
Conventional Discrete Fracture Network. The most common technique for modeling a discrete natural fracture (DNF) network is to generate it stochastically. The common practice in carbonate and some clastic rocks is to use borehole-image logs to characterize the DNF at the wellbore level. These estimates of DNF characteristics are then used for the stochastic generation of the DNF throughout the reservoir.
The idea of the DNF is not new. It has been around for decades. Carbonate rocks and some clastic rocks are known to have networks of natural fractures. Developing algorithms and techniques to generate DNFs stochastically and then couple them with reservoir-simulation models was common practice before the so-called “shale revolution.”
A New Hypothesis on Natural Fractures in Shale
What are the general shapes and structures of natural fractures in shale? Are they close to those of the stochastically generated set of natural fractures with random shapes that has been used for carbonate (and sometimes clastic) formations? Or are they more like a well-structured and well-behaved network of fractures that have a laminar, plate-like form, examples of which can be seen in outcrops (such as those shown in Fig. 1)?
Shale is defined as a fine-grained sedimentary rock that forms from the compaction of silt and clay-sized mineral particles commonly called mud. This composition places shale in a category of sedimentary rocks known as mudstones. Shale is distinguished from other mudstones because it is fissile and laminated.
Technology Focus: Artificial Lift (July 2014)
Authors: Noonan Shauna 
Published: February 2015

Technology Focus
The digital repository of our valuable SPE papers was first launched as the SPE eLibrary in 1997 and subsequently was updated as OnePetro in 2007. This great collection has become a valuable resource for our global industry. However, several years ago, I noticed that many of the great case studies and technological advancements related to artificial lift were being presented at industry events but not published and captured within OnePetro. I made it a personal mission to change that.
Within SPE today, there are more opportunities for authors to present and publish their work related to artificial lift. For example,
The Progressing Cavity Pump (PCP) Workshop was converted to a conference format, which now offers a call for papers.
The SPE Digital Edition series “Getting Up to Speed” for both electrical-submersible- pump and PCP technology provided an invitation to authors who previously gave presentations only at industry events to document their work as an SPE paper in these editions and in OnePetro.
The Artificial Lift Conference and Exhibition (ALCE) series in the Middle East, South America, and North America was created to bring together the regional artificial-lift experts and document their work as SPE manuscripts. Note that SPE is still working to coordinate these events so that their schedules do not conflict with one another.
The ALCE North America event in 2014 focused on seeking out authors with outstanding presentations at regional events (SPE or not), as well as bodies of work that needed to be documented in OnePetro for the benefit of the global artificial-lift community.
The history of artificial-lift technology and the story of its outstanding contributors and innovators have been missing within the SPE realm; however, this is about to change. At the ALCE North America event to be held 6-8 October in Houston, two special events are taking place. The Artificial Lift Historical Exhibit and the Legends of Artificial Lift Awards will be documented and placed in SPE’s historical archives.
The primary and additional papers selected for this feature, with the exception of one Offshore Technology Conference paper, were presented at international events that did not exist a decade ago. The void of artificial-lift information that existed within OnePetro is beginning to be filled and will disappear if we work collectively to seek out our peers and encourage them to publish their outstanding accomplishments and lessons learned as SPE papers.
Integrating True Valve Performance Into Gas Lift Design and Troubleshooting
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 16656, ’Integrating True Valve Performance Into Production-System- Analysis-Based Gas Lift Design and Troubleshooting for Dukhan Field, Qatar,’ by Sanjay K. Singh, James W. Hall, SPE, Eraky Khalil, Balsam Al-Marri, and Reem Al-Abdulla, Qatar Petroleum, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Production-system-analysis methods have been used and are currently used for gas lift design and troubleshooting. These methods, however, have been found to be inadequate in several cases for achieving optimum design or troubleshooting problems. To make up for the inadequacy, a new approach has been applied that uses the Valve Performance Clearinghouse (VPC) database. The new approach joins well performance from production-system analysis and true valve performance from the VPC database to form an integrated system performance tool.
Introduction
Qatar Petroleum’s Dukhan field is onshore Qatar approximately 80 km west of Doha. The number of wells in this field requiring artificial-lift assistance has increased over the past few years, and the trend is likely to continue because of reservoir-pressure decline and rising water cut. The availability of gas coupled with compression and distribution-facility availability has made gas lift a natural choice among various artificial-lift methods. The increasing number of wells using gas lift makes gas lift design and troubleshooting key factors in achieving crude-oil-production targets.
Production-System-Analysis-Based Procedure
Production-system analysis determines a well’s inflow and outflow performance and combines them at a solution node to obtain the well’s system performance. The purpose of gas lift is to lighten the flowing production gradient by injecting gas into the production string of a well. Gas injection into the production string improves the well’s outflow performance by increasing the gas/liquid ratio (GLR) of the production stream from the formation GLR to an objective GLR (OGLR). There are two phases to gas lift operation: unloading and production.
High-Power ESP Tubing-Hanger Connector for Deepwater Downhole Applications
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24138, ’Reliable High-Power ESP Tubing-Hanger Connector Systems for Deepwater Downhole Applications,’ by Sami Spahi, Teledyne Oil and Gas, and Pamela Parsley, Chevron Energy Technology Company, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
Reliability of subsea equipment is an indispensable requirement in deepwater applications. Tubing-hanger (TH) -connector systems can be a critical failure mode for electrical submersible pumps (ESPs) in high-pressure/high-temperature (HP/HT) environments. Through use of reliability tools such as fault-tree analysis (FTA), failure-mode effect and criticality analysis (FMECA), and systems reliability block diagrams (RBD), it was established that improving the reliability of the TH-connector system has a direct effect on the unintervened life of the ESP electrical system.
Project Basis of Design
A joint development project between the operator and the connector-system supplier focused on the design, installation, and intervention of downhole ESPs in deepwater subsea wells in the Lower Wilcox developments in the Gulf of Mexico. The system design encompasses the ESP completion, subsea wellhead, tree, TH, and power and control system. The system design criteria are for 8,000-ft water depth and a 14-mile tieback (Fig. 1).
Connector-System Reliability Overview
At the start of the project, the operator, the connector-system supplier, and other equipment vendors met and agreed to align their reliability plans. Common reliability tools, including FTA, FMECA, and systems RBD, help all collaborators to have a better understanding of the relationship and sensitivity between subsystem reliability and the unintervened life of the ESP electrical system.
FMECA. The FMECA process is typically performed by the present multiple teams to capture different backgrounds and benefits for a wider range of feedback. In this process, each component and subsystem is considered and its corresponding functions are identified. The purpose is to consider the conceivable failure modes associated with each component and function on the basis of prior art, knowledge, and industry experience and then develop plans to mitigate such failure modes in a hierarchy that is based on the criticality.
Gelled Emulsions of CO2, Water, and Nanoparticles
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166072, ’Gelled Emulsions of CO2/Water/Nanoparticles,’ by Fawaz M. Al-Otaibi, Sunil L. Kokal, Yun C. Chang, Jassi F. Al-Qahtani, and Amin M. Al-Abdulwahab, Saudi Aramco, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
Enhanced oil recovery (EOR) by carbon dioxide (CO2) injection is an effective method for recovering additional oil beyond waterflooding. However, the CO2-EOR process is handicapped, especially in thick reservoirs, by CO2 gravity override. Because of density differences between the injected CO2 and resident fluids in the reservoir, the lighter CO2 tends to rise to the top of the reservoir, thereby bypassing some of the remaining oil. This paper investigates the use of gelling CO2/water emulsions, stabilized by silica nanoparticles, to control the mobility of CO2.
Introduction
The CO2-EOR process, while increasingly important, is handicapped by several challenges. The first challenge is the gravity override of the injected CO2 because of density differences between the injected CO2 and resident fluids in the reservoir. The second is viscous fingering caused by the lower viscosity of the injected CO2. Typical dense CO2 viscosity at reservoir conditions is in the range of 0.05–0.1 cp, which is much lower than the viscosity of resident oil and brine. The resulting unfavorable mobility ratio leads to viscous fingering, causing early CO2 breakthrough, high CO2-usage factors, poor sweep efficiency, and low overall oil recovery. The third challenge associated with CO2 EOR is reservoir geology and heterogeneities, including high-permeability streaks and fractures that can impact the sweep efficiency of a CO2-EOR flood. Most of these challenges have been countered by use of water-alternating-gas (WAG) processes. Although the WAG process improves the mobility of CO2, it loses its effectiveness in controlling CO2 mobility deep into the reservoir and beyond a certain distance from the wellbore.
This paper discusses another technique that provides an excellent alternative to WAG to control CO2 mobility: the CO2/foam emulsion. The main purpose of using CO2 foams is to increase the viscosity of the CO2 and therefore reduce its mobility through the reservoir. This emulsion is generated with water-soluble surfactants, CO2-soluble surfactants, or nanoparticles. This paper investigates the use of gelling CO2/water emulsions, stabilized by silica nanoparticles, to control the mobility of CO2.
Mapping CO2 in Real Time With Downhole Fluid Analysis in the East Irish Sea
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166497, ’Mapping CO2 in Real Time in Hydrocarbon Reservoirs With Downhole Fluid Analysis: First Successful Experience in the East Irish Sea, UK Continental Shelf,’ by B. Quayle, S. James, and M. Quine, Centrica Energy, and I. De Santo, P. Jeffreys, and J.Y. Zuo, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
This paper describes the first successful attempt on the continental shelf offshore UK to map carbon dioxide (CO2) in real time while logging during a drilling campaign in the East Irish Sea. Reservoirs in this sea’s basin contain varying proportions of CO2, nitrogen (N2), and hydrogen sulfide (H2S), in addition to oil and methane. Two of these wells develop the Rhyl gas field. Downhole-fluid-analysis (DFA) technologies were deployed with a wireline-formation-testing (WFT) tool to measure CO2 content accurately downhole.
Introduction
The Rhyl field was discovered in 2009 and received development approval in 2012. It is located 11 km north of the North Morecambe field. The North and South Morecambe fields were discovered in the 1970s, with some 7 Tcf of gas initially in place. Production from the Rhyl field extends the longevity of these assets.
Vertical and horizontal variations in CO2 content in the Rhyl field were assessed across the Triassic Ormskirk sandstone, the upper member of the Sherwood sandstone group. The Ormskirk sandstone formation represents the principal reservoir target in the East Irish Sea, comprising high-porosity aeolian and fluvial sandstones with variable grain size and playa mudstones.
Gas Composition in the Rhyl Field
The composition of the gas found in Rhyl includes both hydrocarbon and nonhydrocarbon components such as N2 and CO2. The N2 is derived from late-stage hydrocarbon generation, while isotope data indicate that the CO2 has a magmatic origin. It is believed to have been exsolved from the magma of a series of Tertiary dolerite intrusions into the Ormskirk sandstones in close proximity to the Rhyl field. The samples collected during the drillstem test conducted on exploration Well 113/27b-6 provided several qualitative indications of a higher CO2 content than was originally expected from the correlation with the nearby North Morecambe field: a high gas density measured at the separator and difficulty in sustaining a flare.
Conversations: Not the Beginning of the End, But the End of the Beginning
Authors: Fattahi Behrooz 
Published: February 2015

President's column
This is my last JPT column as SPE president, and I am writing it with mixed feelings. I am grateful for having the opportunity to serve, to visit with many of you around the globe and make so many friends, and to have our monthly conversation through this column. But I am also sad that this grand experience is coming to an end.
As I have met with members across the globe this past year, I have focused our conversations on the new and unique challenges posed by the fast-paced changes in our lives.
These challenges are global, and complex. Some of the most critical of these are clearly impacting us today. They include management of human assets, and its associated issues of an aging workforce; recruiting young talent, and developing their skills; intensifying effort for technology development, and speeding deployment in the field; incorporating process optimization, and promoting collaborative efforts to reduce waste, needless duplication, and cost; and the equally important issue of the industry’s public image. These are not new issues, but they have risen to the top and become, in my view, the most critical to the future of oil supply. I have urged our members not to be threatened by these challenges. Challenges create opportunities, and our industry has to constantly show the ability to redefine itself and meet the adversities.
At the end of my term, I believe more strongly than ever that as the largest, most global, and most prestigious professional society supporting our industry, SPE is well positioned to help the industry address many of these challenges. However, to play our role effectively, SPE must continue to face its own challenges. We must maintain the alignment of the vision and the purpose of the organization. We will have to maintain or improve the quality and integrity of our services, and to deliver them to all members wherever they may be. We will have to continue our globalization effort.
We also must continue to initiate and facilitate industry’s discussions of critical technical and professional issues of the future. I initiated creation of an SPE committee that brings together experts on the topics of sustainability to advise SPE on how we can support the industry. I have also formed a task force to examine issues surrounding our industry’s engagement of women in the workforce. SPE will play an important role in providing a forum for a renewed emphasis on safety and environmental protection, and to addressing what changes are needed in operations, equipment, technology, and training in light of the Deepwater Horizon incident.