bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Rigs Evolve Seeking Productivity Gains
Authors: Rassenfoss Stephen 
Published: February 2015

The vision of fully automated drilling rigs driven by big data gathered in real time looks so far off but there are people working on a road map to help the oil and gas industry find its way there some day.
Drilling rigs working onshore are evolving, driven by the need to manage the high cost of mass producing thousands of wells needed for unconventional development. The rate of penetration (ROP) is the most commonly used measure of efficiency, but the location and the quality of the hole can be significant variables.
The number of wells drilled per year is up as the rig count goes down with many older rigs finally being retired. The rig market overall looks soft, but demand remains strong for late-model rigs wired to handle computer controls (AC drive). While they command higher day rates than older rigs, by drilling wells in fewer days they can help oil companies lower the cost per foot drilled.
At a panel discussion at the recent IADC/SPE Drilling Conference and Exhibition in Fort Worth, Texas, Michael Power, manager of unconventional resources for global drilling and completions at Chevron, said the company is seeking to reduce the average cost of drilling onshore wells in unconventional formations by 15% or more a year.
The goal has been regularly reached with a combination of incremental improvements. In addition to the rate of penetration, gains can be made in other ways, such as reducing nonproductive time, or the time and trucks needed to haul a rig to a new site. “A level of automation speeds drilling and movement of rigs,” Power said.
One indication of the pace of change is the growing market share of Helmerich & Payne (H&P), whose rigs now represent 15% of the onshore market in the United States—about twice its share in 2001—and the company is adding at least two rigs a month to its fleet.
Its rise dates back to its decision to be the first in the industry to design and build a new generation of drilling rig called FlexRigs. A critical difference is those rigs were wired to accommodate systems from the company automating certain functions, increasing a driller’s productivity. It has built five generations of the rigs and is working on the next.
Significant drilling time reductions have been a trend in unconventional exploration. H&P has drilled 10,000 ft of hole in 10.5 days from the start of work on a horizontal well to when the rig is released, said Jeff Flaherty, senior vice president of land rig operations at the company.
But gains in the rate of penetration are getting harder to find. “We are moving to the short end of the bell curve on the time to drill,” he said
Ever faster drilling takes its toll. “Unconventional drilling is hard on equipment and hard on people,” said Flaherty, who said the cost is going down per foot drilled, but the wear and tear is squeezing the company’s profit margins.
International HSE Conference Discusses Crisis Leadership
Authors: Wilson Adam 
Published: February 2015

Conference review
More than 1,000 people gathered in Long Beach, California, in March for SPE’s 2014 International Conference on Health, Safety, and Environment (HSE). In addition to the opening and closing sessions, the conference consisted of three plenary sessions, 13 panel sessions, and 44 technical sessions that presented more than 200 papers.
Opening Session
The grand ballroom at the Long Beach Convention and Entertainment Center was nearly full for the opening session on 17 March. Roland Moreau, Conference Committee chairperson, and Kathy Kanocz, Executive Committee chairperson, introduced Jeff Spath, 2014 SPE President, who, in turn, introduced Leonard Marcus and Eric McNulty of the Harvard University National Preparedness Leadership Initiative.
Marcus and McNulty presented the idea of what they call “meta-leadership,” based on their research into the responses to the Boston Marathon bombings of 2013, Hurricane Katrina, and the Macondo oil spill disaster in 2010. Meta-leadership, Marcus said, involves leadership that reaches “beyond the confines of your particular role or position.”
Marcus and McNulty said that, during times of crisis, people’s brains respond by “going to the basement.” This refers to the instinctual responses of freeze, flight, or fight. During those moments, McNulty said, “all your brain is focused on survival. You can’t do any complex problem solving. You’re not very productive in terms of figuring out what’s actually going on.” The key to successful crisis management, he said, is to get out of the basement as quickly as possible in order to make sound decisions.
“You, as a crisis leader, have to be smarter than your brain,” Marcus said. This return to rational decision-making can be made by sending a second signal to the brain. This second signal can be as simple as taking a deep breath or counting to 10. With practice, one can build a second neural pathway to speed one’s return to productive thinking.
Multiple Factors Drive Decisions Toward Wet or Dry Trees in Deepwater Projects
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24517, ’Deepwater Development: Wet or Dry Tree?’ by D. Reid, M. Dekker, SPE, and D. Nunez, Shell, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, Brazil, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
This paper explores the interplay between field development and lifecycle reservoir management and the selection and operation of dry- or wet-tree host systems for the development and production of deepwater oil and gas fields. Drawing on insights from recent deepwater projects, the selection criteria related to development and reservoir management are highlighted to show the advantages and limitation of the two different host concepts.
Introduction
In deep water, it is common for approximately one-third of the initial capital investment to be related to the host system. Selection of the host concept is critical and is dependent on a robust understanding of the many upfront development drivers.
The host is ultimately the linchpin in the overall development system and is critical to delivering a solution that maximizes economic value during the life of the project, to providing a degree of mitigation against key reservoir and production uncertainties that are inherent in deepwater developments, and to providing flexibility to capture any potential future production upsides that have been identified in the proximal development location.
One of the more important decisions related to deepwater host selection is whether to adopt a dry- or wet-tree system. Both systems offer distinct advantages and disadvantages, depending on the context of their application. The selection of a dry- or wet-tree system should be made in the context of the overall development system evaluation.
Wet- and Dry-Tree Deepwater Host Systems
At a high level, deepwater host development has evolved into four major options, each with various degrees of flexibility in shape and design:
Tension-leg platforms (TLPs)
Moored semisubmersible platforms
Spar platform concepts (conventional, truss, and single-column floater)
Floating production, storage, and offload (FPSO) vessels
Heavy-Oil Papa-Terra Project Uses Innovative Solutions in Deep Water
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24504, ’Papa-Terra Project: Use of Innovative Solutions for Heavy Oil in Deep Water,’ by D.S. Condessa, G.S. Damno, S.C. Vieira, and W.P. Goncalves, Petrobras, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, Brazil, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
The Papa-Terra field in the Campos basin in Brazil is identified as having an oil interval of 14.6°API in turbidite sandstones. Because of the high-viscosity oil and low-API grade, innovative solutions and technological advances were incorporated into the project. The development uses an integrated production system consisting of a floating production, storage, and offloading (FPSO) vehicle connected to a tension-leg wellhead platform (TLWP) and dry completion wells. This allows the production of ultraheavy oil in deep water and enables rapid intervention for maintenance of electric submersible pumps (ESP).
Introduction
Because of the properties of the oil from the Papa-Terra field (high viscosity at low temperatures and low gas/oil ratio), the whole production development concept of the field was driven by artificial lift and flow-assurance requirements.
This led Petrobras to a field-development concept that uses two production units, an FPSO (P-63) and a TLWP (P-61), 350 m apart.
The P-61 platform will be connected with 13 dry-completion wells, and all production will be exported to P-63, where it will be joined with the production from five wet-completion wells to be processed. The TLWP will not have a process plant to separate oil, gas, and water and will transfer all produced fluids to FPSO P-63 through multiphase pumps.
As a secondary recovery method, 10 injector wells will be placed at the reservoir extremities to maintain pressure in the reservoir (Fig. 1).
As a consequence of this development, and mainly because of the oil properties, the items that needed to be developed to make the project technically viable and economical attractive are
High-power ESP
TLWP as a production unit
Conductor-driven installation
Thermal-insulated TLWP risers
Tender-assisted drilling (TAD) unit
Fluid-transfer lines at midwater
Electrical-heated flexible pipe
Technology Focus: Intelligent Fields Technology (May 2014)
Authors: Hudson John 
Published: February 2015

Technology Focus
What is taking so long? Well, more than a decade into the intelligent-fields initiative, this is a question that remains prominent. That a clear business case supports investments in the area was settled years ago for most; but, within the variety of tactics an operator takes and even greater diversity in the particular products and services providers develop within this space, we have seen a mixture of results. Furthermore, leveraging success from a demonstration project into sustained value delivery and across multiple assets or divisions can be elusive. So, it is understandable and healthy when managers challenge a sustained expense that fails to provide the value that was promised. What then are the markers of an initiative that should be started or sustained?
Are you solving the right problem? Choose a problem that allows your company to learn while delivering incremental value over multiple applications. In my company, we were able to deliver a great return by deploying a relatively simple analytics solution globally to most of our oil production over 5+ years, delivering incremental value while working through the organizational changes.
Is it a good fit for your people? Is your organization able to learn and change to make it work, and do you have the right people who can stay with it until the business owns the change? When key people move after an early declaration of success, fragile changes often falter.
Can you commit to making it work? You can drive value from, and even turn around, a struggling initiative (even one employing a suboptimal solution) when you give the right people the space to learn and deliver against the right problem. There will be bumps, so count the costs up front and ensure that the organization is ready for the challenges. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 167821 A Smart Flow for Smart Wells: Reactive and Proactive Modes by G.A. Carvajal, Halliburton, et al.
SPE 164348 Smart Well With Autonomous Inflow-Control-Valve Technology by Haavard Aakre, InflowControl/Telemark University, et al.
SPE 166507 Prototype Test of an All- Electric Intelligent-Completion System for Extreme-Reservoir-Contact Wells by Brett Bouldin, Saudi Aramco, et al.
Innovative Geosteering Technology in Multilateral Wells
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24002, ’Innovative Geosteering Technology Used in Drilling Smart Multilateral Wells, Kuwait,’ by T. El Gezeery, A. Aziz Ismael, K. Al-Anezi, G.S. Padhy, Fawaz Al Saqran, A. Abdul-Latif, and J. Silambuchelvan, Kuwait Oil Company, and J. Estarabadi and G. Ferroni, Geolog International, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
The Burgan reservoir in Kuwait has the potential for premature water breakthrough, leaving behind bypassed zones of oil. The placement and completion of horizontal wells in such reservoirs is a challenge necessitating a collaborative approach from petroleum geoscience, reservoir engineering, and petroleum engineering. This paper describes placement of horizontal wells in this kind of heterogeneous reservoir through an integrated approach.
Introduction
The Minagish field was discovered in 1959 and is located in the southwestern part of Kuwait. It contains several reservoir intervals in its stratigraphic column, varying from Early Jurassic to Late Cretaceous. The field is situated 12 km northwest from the West Umm Gudair field (Fig. 1). The field has been penetrated by more than 180 wells. The field structure of the Burgan formation is a closed elongated asymmetrical anticline oriented in a north/south direction. The top of the Burgan structure is located at approximately 5,500-ft true vertical depth (TVD) minus the elevation above mean sea level of the depth reference point of the well.
Regional Geology. The Burgan formation consists of a lower braided river system with stacked sand bodies. The sediment ranges from fine to medium grain sizes, and the porosities are high enough for lateral migration. On top of the upper Burgan channels, the sediments are generally finer but still retain a fluvial character. The amount of shale is higher. The marsh and tidal sediments, which consist of fine sands, silty sands, and sandy silts, seem to be of lower connectivity for vertical migration. The porosity is relatively low (between 15 and 18%), and the minimum of the measured permeability is close to 1 md for these layers. It seems that these shaly sediments can act as permeability barriers for vertical migration, but oil is observed in all channels and has been able to reach the reservoirs. This complex channel geometry makes these reservoirs the most challenging clastic reservoirs in the Minagish field.
Conversations: The Pond in Which We Live
Authors: Fattahi Behrooz 
Published: February 2015

President's column
The balance between the global supply and demand for crude oil is becoming progressively tighter. Recent projections show that the gap between the oil supply and demand will grow dramatically, to perhaps as much as 20 million B/D by 2030, even with painful conservation measures in place. To keep up with the increasing demand, the petroleum industry is facing a variety of challenges, including development of an adequate supply of a skilled workforce, collaboration on the development and rapid deployment of leading-edge technologies needed to access unconventional resources, and communication to the public at large about our role as an industry and the noble causes that we pursue.
As we face these global and complex challenges, we must increasingly incorporate the concept of sustainability in our operational framework. At first glance, the term sustainability may seem intimidating to some. However, our industry has been focusing on the concept or its components for a long time, but under different descriptive terms—optimizing production, maximizing reserves, reducing cost, cutting waste, increasing efficiency, optimizing processes, minimizing footprint, maximizing safety, reducing environmental impact, and increasing corporate social responsibility. We have spent considerable efforts—heavy investments of time and capital or human resources—in achieving these goals. Thus, for our industry, the gap between what we have been doing and what we need to do is much narrower than what it is perceived to be.
The notion of “sustainability” was more clearly defined through the work of the United Nations’ Brundtland Commission, whose report on sustainable development “Our Common Future” was published in 1987.1 Sustainability was summarized as “Meeting the needs of the present without compromising the ability of future generations to meet their own needs.”
Sustainability is an essential ingredient of our industry’s activities, a diverse concept of many elements that are embedded into the fabric of our daily operation. We practice it, and we create value by integrating sustainability into our strategies and business models. In pursuing better performance, we master sustainability. Yet, we may not have been too mindful of its true meaning in the past. It is only in recent years that the concept of sustainability has moved from the background into the limelight. Sustainability has become the cornerstone of our operation from the upstream to downstream.
Many companies have developed measures and key performance indicators to satisfy their corporate social responsibility, and to ensure that they remain sustainable in many aspects of their operation. While these are important, taken individually, such undertakings are too fragmented; a more collective approach will need to become the subject of discussion in more global conferences and technical meetings, and topics for best-practices workshops. SPE can play a significant role by facilitating such opportunities.
Techbits: Mumbai Workshop Explores Deepwater Strategies
Authors: JPT staff _ 
Published: February 2015

Techbits
Recognizing the growing potential of deepwater developments off the coast of India, SPE hosted its second deepwater-focused applied technology workshop (ATW) in Mumbai in less than 2 years. The ATW, “Unlocking Deepwater Potential: Strategies and Technologies,” brought together 131 delegates from 11 countries and 40 companies to share information and help Indian companies assimilate the knowledge they will need to monetize India’s deepwater assets.
Sudhir Vasudeva, director (Offshore)-ONGC and ATW Steering Committee chair, opened the ATW with an address describing India’s deepwater potential. The country’s deepwater regions hold approximately 51 billion bbl of oil and gas equivalent in a sedimentary area spanning 1.35 million km2. Thus far 31 hydrocarbon discoveries have been made—26 gas discoveries and the remaining 5 oil and gas discoveries. The discoveries are spread over Mahanadi, Krishna-Godavari, and Cauvery basins off the east coast of India, which is poised to be a gas hub of Asia.
Vasudeva projected that given India’s gross-domestic-product growth rate of 8–9%, hydrocarbon requirements will increase from the current level of 125 million tonnes of oil equivalent (toe) to 435 million toe in the next 25 years. Global energy consumption is expected to grow by 50% over the same period, putting the onus on the oil and gas industry to find more reserves and curb production declines in existing assets. After 2012, deep water is the only sector which is expected to grow continuously to meet burgeoning global demand.
R.S. Sharma of ONGC next stressed that because 43% of India’s sedimentary basins lie in deep and ultradeep water, the E&P industry has ample exploration opportunities here. However, he acknowledged that the pace of technological progress is sometimes too rapid for operators, who need to have a great deal of confidence and assurance in technologies prior to bidding for deepwater blocks. He stated that critical areas for study going forward include drilling and completions; subsea facilities; and health, safety, and environmental factors.
Pushing Boundaries
The first technical session provided case histories highlighting two recent deepwater developments from different parts of the world. K.V.K. Prasad of Shell Technology India first presented the development strategy for Shell’s Perdido oil field in the US Gulf of Mexico (GOM). Operational and subsurface challenges included extreme water depth (8,000 ft at the platform), extreme metocean conditions, rugged sea floor, flow assurance, a high-risk reservoir (the first Paleogene production in the GOM), low pressure, and high gas-to-oil ratio.
Deepwater-Development Production and Export Options
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123415, ’Deepwater-Development Production and Export Options,’ by W.D. Hartell, SPE, and J.R. Greenwald, Hess Corporation, prepared for the 2009 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 4-6 August.
Deepwater discovery and development activities can be far from existing infra-structure, such as other facilities and pipelines. The choice of production and export options for hydrocarbon liquid and gas is important and is affected by distance to other infrastructure and by water depth, geohazards, reservoir-fluid characteristics, production rates, and reserves. In Southeast Asia, deepwater developments often are hundreds of kilometers from onshore markets, so the development production and export options must be wide to obtain economic and timely choices.
Introduction
As deepwater developments move into more-remote locations in Southeast Asia, options to develop these “stranded” resources are becoming more challenging. Industry advancements for developing these resources provide multiple options for production and export. Prospective deepwater locations in eastern Indonesia, Papua New Guinea, Philippines, South China Sea, and Australia are gas prone and are long distances from market. Technical and commercial foundations for floating gas production and nonpipeline-export options in Southeast Asia are examined.
Production and Export Options
Given the assumptions of a remote, deepwater hydrocarbon development with hydrocarbon liquids and gas, it is likely that a development scenario would be as follows. Subsea wells would be spread over the field, either as distributed single wells or grouped into drill-center clusters. Production would move from the seabed manifolds in some number of production risers, steel catenary risers, buoyant riser towers, flexible risers, or some combination of these. On the surface of the ocean, there would be a floating production host [i.e., spar, tension-leg platform (TLP), semisubmersible, or a floating production, storage, and offloading (FPSO) vessel].
Conventional gas-export options for remote deepwater locations, such as long-distance gas pipelines requiring compression facilities along the route to markets, are likely to be very expensive. They may be technically too challenging if combined with sea-bed geohazard challenges such as deep trenches, unstable slopes, or areas of seismic activity. These challenges and high costs lead to consideration of floating production options such as processing the gas into more-transportable products.
Gas-Market Options. Compressed Natural Gas (CNG). CNG can be an attractive option (or partial solution) where distance to markets is not too great. It is an attractive option with lower investment needs (i.e., cheaper production facilities, transport vessels, and discharge facilities).