bluuebunny/crossref_metadata_2025_split huggingface dataset:
What Is Next for Intelligent Energy?
Authors: Al-Mulhim Waleed , Mubarak Saeed M. , Bonilla Juan Carlos G. 
Published: February 2015

Guest editorial
In recent years, many companies in the oil and gas industry have been making steady progress employing digital oilfield (DOF) solutions to improve operations through better data capture, visualization, analysis, and automation. As more implementations provide value to particular fields or assets, a question remains of how they can be leveraged as a whole to provide aggregate value at the business portfolio or corporate strategy levels. The large volume and detail of information that DOFs generate, not only in terms of data, but also decision outcomes, interpretations, and knowledge, both tacit and implicit, contribute significantly to a company’s intellectual capital.
Looking at the business case, asset-level business drivers are normally defined by considering short-term benefits in light of immediate challenges. Because of the varied production environments and diverse approaches associated with DOF implementations, determining return on investment and value for an organization’s overall production business is difficult at best; it is analogous to an “apples vs. oranges” comparison of assets. For companies actively pursuing multiple DOF programs, managing commercial uncertainties is, therefore, a key challenge for allocating resources, defining a coherent vision, and ultimately determining the appropriate level of commitment, financial or otherwise.
Applying this perspective, there is a clear opportunity, and corresponding challenge, to scale the DOF value proposition by smoothly integrating independent digital assets into a cohesive system by delivering a smarter, more comprehensive view of a company’s business portfolio. Toward this end, several key concepts and issues should be considered carefully in order to understand the implications of each implementation as the first step toward corporate value realization.
Strategic Business Intelligence
DOF solutions leverage real-time asset awareness, in combination with intelligent analytical tools and collaborative business processes, to continuously optimize production. Data is gathered and manipulated to create information, which in turn develops into knowledge for decision support. Knowledge is the critical piece and having the ability to exploit it to the benefit of the organization should be fundamental. This is the essence of business intelligence and is at the core of the DOF value proposition.
Steerable Liner Trims Nonproductive Time and Boosts Oil Recovery in Problem Well
Authors: Biscaro Enrico 
Published: February 2015

Technology Update
To compete successfully in the global energy market, exploration and production companies must operate efficiently, economically, and safely in increasingly difficult environments. Subsalt applications, unstable coal and shale layers, tar zones, depleted zones, and formations with variable flows and pressures are among the problems routinely encountered that must be overcome.
In these problem zones, nonproductive time (NPT) of 30% in drilling operations has become commonplace in many areas, with 45% reported in some wells. Wellbore instability appears to be the main cause of NPT. Some operators report that it accounts for more than 40% of their NPT and approximately 25% of drilling costs in difficult wells. NPT related to wellbore stability in these applications ranges from several hours to several weeks in just one section, and costs run from thousands to millions of dollars.
Other causes of NPT in these wells include narrow drilling margins and lost circulation. In many situations, operators must compromise ideal well placement to avoid troublesome formations, leaving millions of barrels of oil in the ground.
Baker Hughes recently developed the SureTrak steerable drilling liner (SDL), the industry’s first SDL system that has been used to drill, evaluate, and place a liner to total depth (TD) in complex, 3D directional wells in a single run (Fig. 1). The advent of SDL technology mitigates the risk of drilling through problem zones or formations and creates opportunities to maximize reservoir potential by reaching reservoirs that were previously unreachable. The SDL system was recently used in an innovative openhole patch application that saved drilling time and significantly increased oil recovery in a problematic North Sea well.
Technology Evolution
The concept of drilling with a string of casing rather than conventional drillpipe has existed since Reuben Baker’s original 1907 patent for a casing shoe used in cable tool drilling. In its most basic form, casing is driven into soft formations by circulating and rotating. The addition of basic cutting structures on the casing shoe facilitates the procedure. It also allows harder formations to be drilled and enables the shoe to be drilled out conventionally afterward so that drilling can continue. Various casing drilling technologies and approaches have been used throughout the decades; in general, the main goal was to reduce drilling time by combining the casing and drilling into a single operation.
As the need arose for more power to the bit in high-torque operations, a system was developed with the motor installed inside the casing. However, only minimal steering was possible with this system, which led to the emergence of steerable casing while drilling (CWD).
The Next-Generation Water Filter for the Oil and Gas Industry
Authors: Dejak Michael 
Published: February 2015

Young Technology Showcase
Many segments of the oil and gas production industry need improvements in water filtration over traditional methods. This is true because of the trend toward oil and gas production in tighter, less permeable reservoirs and the greater use of enhanced oil recovery (EOR) techniques, many of which involve injecting water into the oil reservoir. To protect the integrity of such reservoirs, the amount of solids introduced into the reservoir through water injection, even solid particles down to 1 µm in size, must be minimized. Conventional filtration methods generally do not meet this requirement. An enhanced filtration technology known as Spectrum Plus Filtration, which incorporates the use of granular micro media, has been proven in other industrial applications and has been introduced and successfully proven in the treatment of produced water. This technology holds the promise of meeting the new requirements while being economical and robust.
New oil production practices often involve more water treating and more water injected into wells and reservoirs that are tighter and more costly to develop. This means that there is a greater concern about injecting excessive amounts of solids into these wells and reservoirs. The consequences of this can be
Reservoir plugging, which can cause production declines or inadvertent fractures
Greater frequency of well and reservoir plugging requiring workovers, acid treatments, and new wells with the associated production loss
Reduction in production or in the total recoverable potential of the reservoir
Souring of wells through introduction of sulfur-reducing bacteria from water injection
In response to the concerns that solids injected into wells can have, specifications for the water quality being injected into such wells are increasingly being defined by a particle size cutoff at about 2 µm, with many specifications requiring that 95% to 98% of the particles greater than 2 µm are removed.
Some other new production practices involve other water conditioning process equipment, which in turn requires excellent filtration for it to perform properly.
Traditional Water Filtration Methods
Table 1 lists some traditional water filtration technologies and their limitations in meeting the new requirements.
Addressing Gaps in Water Treatment Technology
Authors: Rowland Gina , Walsh John 
Published: February 2015

Management
As demand for energy continues to rise and conventional sources become more scarce, oil and gas companies are under pressure to pursue production through unconventional methods and enhanced oil recovery (EOR) technologies. Nearly all unconventional and enhanced recovery methods involve significant amounts of water and, therefore, specific technical and management challenges related to water.
Not only does this trend have significant implications for the water treatment business, it also calls for a new level of cooperation between the industrial water treatment sector and the oil and gas industry. With the growing and urgent need for better, commercially effective ways to handle produced water from unconventional production, the question of how the oil and gas industry will be able to access the best that the water treatment industry has to offer now shows the beginnings of a possible answer. The water treatment industry has started to appreciate the complexity of water challenges in the oil and gas industry. Likewise, the latter has begun to look to the former for solutions.
This article will review the market drivers and environmental risks behind the rising significance of water treatment in the industry, discuss how some oil and gas producers currently look at the problem of persistent water treatment technology gaps, and point the way forward for better professional collaboration among stakeholders and the development of business opportunities. The time is right for energy companies to see that they have synergies with water companies and for both sectors to recognize that the challenges of water scarcity and environmental protection are, if handled appropriately, opportunities.
Market Drivers
The current growth in the water treatment market is directly linked to oil prices and demand. With Brent crude holding just above USD 100/bbl and long-term projections predicting that oil will remain a significant portion of the energy mix, energy producers are approaching the problem of declining production from older reservoirs by extracting as much oil as possible from existing assets through the application of EOR methods, most of which require the injection of large amounts of water (miscible gas being the main exception). Extracting oil from mature fields also means that oil companies have to handle the problem of an increasing water/oil ratio (WOR) in the production process (Fig 1). Water production estimates were approximately 250 million B/D in 2007 for a WOR of approximately 3:1 (SPE, 2011); WOR is expected to reach an average of 12 for onshore crude oil resources by 2025 (GWI, 2012).
Shale Development Plan Blends Fracture, Reservoir, and Geomechanics Modeling
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164018, ’Integration of Fracture, Reservoir, and Geomechanics Modeling for Shale Gas Reservoir Development,’ by Jugal K. Gupta, SPE, Richard A. Albert, SPE, Matias G. Zielonka, SPE, Yao Yao, SPE, Elizabeth Templeton-Barrett, SPE, Shalawn K. Jackson, SPE, and Wadood El-Rabaa, SPE, ExxonMobil Upstream Research Company, and Heather A. Burnham, SPE, and Nancy H. Choi, SPE, XTO Energy, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed.
A multidisciplinary approach integrates fracture characteristics, reservoir production, and stress-field evolution to design and optimize the development of unconventional assets. In this approach, fracture modeling and advanced rate-transient techniques are used to constrain fracture geometry and depletion characteristics of existing wells. This knowledge is used in finite-element geomechanical modeling to predict fracture orientation in nearby wells. In this paper, an integrated methodology is described and applied to a shale-gas pad as a case study.
Introduction
Although it is generally accepted that geomechanical stresses are important for understanding fracture propagation in shales with low contrast in principal compressive stresses, the absence of precise knowledge of input parameters needed for reliable predictions has limited the broad use and applicability of geomechanical models. Parameters such as permeability, fracture half-length, number of propagated fractures, and geological heterogeneity still carry much uncertainty for shales and can have a significant effect on model predictions. A methodology is presented to address some of these limitations by integrating knowledge derived from production and fracturing data to reduce the uncertainty in key parameters and enable realistic predictions (Fig. 1).
The spatial and temporal evolution of stresses for multiple horizontal fractured shale-gas wells on a pad has been investigated by explicitly modeling each of the hydraulic fractures extending from the wellbore. The models are constructed by use of simplifying assumptions of planar biwing fractures. Both 2D plane-strain and full 3D formulations are used. The results reveal significant reorientation of principal stresses thousands of feet away from a producing well in addition to the anticipated near-fracture stress changes. The reorientation of stresses far from a producing well can have a significant effect on hydraulic-fracture propagation during stimulation of new infill or neighboring wells.
Methodology
A multidisciplinary approach integrating aspects related to completion, reservoir production, and geomechanics was used to optimize development of unconventional gas assets.
En Route: Why Peer Review?
Authors: Labastie Alain 
Published: February 2015

President's column
“Peer review” is a term that is not always fully understood, so let’s talk about peer review and related issues for SPE.
Papers presented at SPE conferences are selected on the basis of an abstract (roughly 300 words) submitted by the author. The meeting program committees are selecting abstracts that presumably will be transformed into good papers. A “good paper” is one that addresses a relevant topic, with adequate technical content. Although this selection process provides a screening, and many of these papers are quite interesting, they have not been peer reviewed.
After he/she sends the manuscript for inclusion in the meeting’s proceedings, the author may choose to also submit his/her paper for publication in one of SPE’s seven peer-reviewed periodicals. Peer review is the process by which those papers are evaluated. For SPE, this means that the paper will be critiqued by two or more industry or scientific experts (the peers), who will consider such questions as
Is the problem well defined, and is it a real one?
Is the problem solved in a sound way?
Do the conclusions make sense?
In case of a field case description, are there enough data to understand and from which to learn?
Sometimes, in a technical or scientific demonstration, the author has to make choices. The author should clearly explain those choices, and the reviewer should not criticize those choices even if they are different from his/her personal views, provided they are technically sound. The reviewers often specify improvements (minor or major) to be made to the paper before it can be published in a journal, and sometimes more than one round of review and revision are necessary before the paper is accepted.
So the answer to the question “why peer review?” is clear: the process provides a good guarantee of quality for the papers published. In the scientific domain, peer review has proven to be a very efficient and successful tool for the progress of science in general. I believe that the same is true in the domain of engineering. And papers that are peer approved, like those published in SPE journals, offer a much higher guarantee of quality as compared to papers available in commercial publications, which are published without such rigorous evaluation.
Peer review is also very important for the academic world; for a career in academia, it is necessary to regularly have papers published in a peer-reviewed journal. It is right for SPE to offer a home for the petroleum engineering domain.
Gorgon To Drive Australian LNG Asia-Export Surge
Authors: Parshall Joel 
Published: February 2015

Gorgon project
One of the world’s largest natural-gas projects, involving one of the largest, most advanced carbon-dioxide-sequestration initiatives, is moving ahead in Coastal Western Australia. The Chevron-operated Gorgon project will develop offshore reservoirs for liquefied-natural-gas (LNG) export and domestic gas-market supply, centered around LNG and gas-plant facilities to be built on Barrow Island. Sanctioned in 2009, Gorgon is in its construction phase and is slated to begin operations in 2014.
Not far behind is another huge Chevron-led natural-gas/LNG project, Wheatstone, in which company and third-party fields off Western Australia will be developed and tied into a planned coastal LNG-export and domestic-gas processing hub. Front-end engineering and design are under way, with a final investment decision expected in 2011.
LNG exports to Asia Pacific customers are at the heart of both projects, which together point to a surging importance of Australian LNG in the world market. Australia is the world’s sixth largest exporter of LNG, and some market observers believe that anticipated projects could elevate Australia to No. 1 in world LNG exports within about a decade.
‘An Energy Sweet Spot’
“In every sense, the biggest game in town is the development of megaprojects for the export of LNG,” Western Australia Premier Colin Barnett said earlier this year.
In a recent talk to the Australian Petroleum Production & Exploration Association, Roy Krzywosinski, managing director, Chevron Australia, said, “Our industry finds itself in an energy sweet spot, surrounded by natural-gas resources on the doorstep of the world’s biggest and fastest-growing market, the Asia Pacific region.”
Gorgon’s reserves lie within the Greater-Gorgon-Area gas fields in the Carnarvon basin off the northwest coast of Western Australia. The initial phase of development includes 18 subsea wells to be drilled in two separate fields: Gorgon, approximately 80 miles offshore in 660 ft of water; and Jansz-Io, approximately 125 miles offshore in 4,300 ft of water. It is anticipated that up to 30 wells will be drilled in the Gorgon-area fields over approximately 30 years.
From the wellheads, gas will flow to one of several cluster manifolds to be installed nearby on the seafloor, at which production from multiple wells will be combined and routed in a single flow path from each manifold to pipeline-termination structures. A system of flowlines will connect these termination points with each other. Produced gas will flow through lines leading from the termination structures and eventually traveling up a steep, 5/8-mile-high underwater escarpment en route to the Barrow Island processing facilities.
All subsea equipment will be monitored and controlled from the onshore LNG plant by means of an electrohydraulic multiplexed system with primary fiber-optic communications, which will incorporate a system of subsea control umbilicals to tie in the seafloor infrastructure with the plant.
Technology Focus: Drilling and Completion Fluids (November 2010)
Authors: Estes Brent 
Published: February 2015

Technology Focus
Last year, I wrote about the science-based approach to fluids and the increased level of knowledge required of drilling-fluids-related professionals. This year, I want to emphasize the importance of drilling and completion fluids in well control, lost-circulation mitigation, and wellbore stability.
One of the first things you learn as a drilling engineer or rig supervisor is that the most important aspect in drilling is the drilling fluid (this may be a little biased coming from a fluids specialist). It is like the blood in our circulatory system! It serves many functions and can be either friend or foe, depending upon how it is maintained.
The primary function of drilling or completion fluids is to control subsurface pressures. With the challenge of drilling in ever-increasing water depths and into higher-pressure and temperature reservoirs in the pursuit of hydrocarbons, this becomes even more important and more difficult to accomplish. Additionally, the fluid density required to control formation pressures often is very close to the fracture gradient, so that there is a delicate balance between well control and lost returns. Another issue to consider is the effect that fluids have on wellbore stability. With the increased complexity of the wells being drilled, higher fluid densities are needed to prevent the hole from becoming mechanically unstable, thus narrowing the “safe drilling window” between borehole stability and lost returns. Various techniques are used to address this issue. Factors such as formation type and characteristics, type of loss, and others should be considered when selecting the most appropriate solution. There is no “one size fits all” approach that works.
The papers in this feature address issues in the preceding discussion. Please take time to read them along with the papers listed for additional reading.
Drilling and Completion Fluids additional reading available at OnePetro: www.onepetro.org
SPE 130413 • “Vital Role of Nanopolymers in Drilling- and Stimulation-Fluid Applications” by Subodh Singh, University of Oklahoma, et al.
SPE 125708 • “Remote Real-Time Monitoring of Particle-Size Distribution in Drilling Fluids During Drilling of a Depleted HP/HT Reservoir” by Egil Ronaes, SPE, M-I Swaco, et al.
SPE 130421 • “Utility-Calculation Method of New Four-Parameter Rheological Model for Drilling Hydraulics” by Guo Wang, China University of Petroleum, Beijing, et al.
SPE 128405 • “Salinity-Based Pump-and-Dump Strategy for Drilling Salt With Supersaturated Fluids” by T.J. Akers, SPE, ExxonMobil