bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Multilateral/Extended-Reach Wells (May 2016)
Authors: Aadnøy Bernt 
Published: January 2017

Technology Focus
The development of multilateral wells and long-reach wells has become important to maximizing recovery for many fields. These technologies are often applied in offshore environments, where large reservoir areas are drained from one or more platforms.
In the late 1980s, long-reach wells started to use existing infrastructure better by drilling beyond the design limits of that time. Several major operators were extending their limits, and, in the late 1990s, BP Wytch Farm showed that a horizontal departure exceeding 10 km was feasible. This had a significant effect on the industry because offshore platforms now could be designed for up to 10-km reach, as opposed to the early 1980s when 3-km reach was common. A field could now be developed with one platform instead of three, resulting in enormous savings.
Multilateral-well technology also matured during the past 2 decades. There were many drivers for this development. One of the more important was the desire to increase production in tight reservoirs. Another advantage is directional control. Well stimulation with fracturing has the drawback that the fracture direction is controlled by the in-situ stresses in the rock. Multilateral branches, on the other hand, can be drilled in any direction.
There has been considerable development around these technologies. Those that help clear the challenges, such as those related to wellbore stability, wellbore friction, equipment limitations, and operational aspects, can be considered mature technologies today.
The main benefit from directional drilling is the maximizing of reservoir recovery. From this perspective, multilateral/ extended-reach wells may be considered one of the more important means of improved oil recovery.
Although these directional-well concepts have been used for some years, they were initially costly with a high economic risk. There is a continuous technology development at many levels that leads to improvements. These result in more-efficient processes, with increased field recoveries as a consequence. Therefore, multilaterals and extended-reach wells are now common and will be very important for future cost-effective oil and gas production.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 174035 Technology Qualification and Installation Plan of Efficient and Accurate Multilaterals Drilling Stimulation Technology for Sandstone Oil Application by Kevin Rice, Fishbones, et al.
SPE/IADC 168055 Expanding the Extended-Reach Envelope at Chayvo Field, Sakhlin Island by Vishwas P. Gupta, ExxonMobil, et al.
SPE 168235 CT Extended Reach: Can We Reach Farther? by Ken Newman, KNewman Engineering, et al.
Project Tests High-Performance Cloud Computing for Reservoir Simulations
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 167877, “Reservoir Simulations in a High-Performance Cloud-Computing Environment,” by Morgan Edward Eldred, Asma Aboubakr, Ahmed Abubakr Al-Emadi, Thomas James O’Reilly, Nedal Barghouti, and Abdollah Orangi, Maersk Oil, prepared for the 2014 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 1–3 April. The paper has not been peer reviewed.
In the upstream oil and gas industry, cloud computing is very immature because the industry has always been challenged by storage and computational capability. However, there is recent evidence for considering high-performance cloud computing (HPCC) because of the promise of benefits such as flexibility, accessibility, and cost reduction. HPCC may create an opportunity for small to midsized upstream companies that do not want to invest in the infrastructure needed for evaluating scientific applications.
Project Overview
The target of this project was to prove the concept of running simulation software in a high-performance computing cloud and use the findings to design a framework or methodology enabling companies to pursue business opportunities iteratively while learning along the way. The outcome of the methodology is a dynamic tactical and strategic roadmap that leverages trends in HPCC.
Calculations and Results
The following cases were run on a local cluster at an early stage for the purpose of run validations:
HP_ICLOUD on reference workstation with one central processing unit (CPU)
HP_ICLOUD on the Enterprise Cloud (ECL) server with one CPU
HP_ICLOUD_4 on the ECL server with four CPUs
HP_ICLOUD_8 on the ECL server with eight CPUs
The four cases showed identical results for oil-production rate and cumulative oil for the duration of the field history, as expected.
The case with a single CPU was completed in approximately 20 hours. The run times with four and eight CPUs were 7.7 and 5.7 hours, respectively.
Fig. 1 shows that wall-clock time decreased as more CPUs were added, both for calculations performed internally and for those performed on the cloud servers. It was also observed that internal calculations stagnated at more than four CPUs (i.e., sublinear scaling). On the other hand, close to linear scaling was observed when calculations were run on the cloud servers.
Assuming that this linear scaling persists when adding more than eight CPUs and extrapolating from this observation, it is hypothesized that, for larger jobs, the performance of the cloud servers would increase significantly compared with what can be achieved internally.
A More-Rigorous Development Framework for Unconventional Reservoirs
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171913, “From a Standard to a More-Rigorous Development Framework for Unconventional Reservoirs,” by I. Colombo, E. Spelta, D. Giamminonni, S.D. Russo, F. Rotelli, and M. Rotondi, Eni, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed.
Major oil companies have been struggling as they attempt to make the unconventional business a profitable one. Indeed, the strategy of building an unconventional portfolio by means of mergers and acquisitions is not providing a satisfactory return on investment. This paper describes how seismic reservoir integration, advanced production analysis, and accurate nanoscale and 3D full-field simulations may address profitability issues and help oil companies to be more efficient in developing unconventional portfolios.
Introduction
While, from approximately 2008–2011, independents were building and developing their US unconventional portfolio, majors were trying to enter the same business by means of multibillion-dollar mergers and acquisitions. The majors were not fast enough to be able to repay the premium for this endeavor as a consequence of the combination of a low- margin-profit type of business and hydrocarbon-price evolution. Majors tend to be essentially process- driven organizations; therefore, they are not structured for rapid-decision-making approaches. Furthermore, they quickly align to the general concept of thinking about unconventional plays as if they are statistical ones. Their initial main effort was essentially made for unit cost reduction, whereas technology innovation has become a principal focus currently.
Key plays have experienced an impressive production growth. If, on one hand, the system is improving its efficiency, on the other, the incremental production is also associated with a huge increase in the average number of fracturing stages per well.
Few attempts were made to optimize wells and fracturing-stage placement by applying a more-scientific approach. Indeed, many sources estimate that only 40 to 60% of fracturing stages contribute to well production when they are placed on the basis of an equal-spacing strategy.
A Portfolio of Commercial-Scale Carbon-Capture-and-Storage Demonstration Projects
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18469, “A Portfolio of Commercial-Scale CCS Demonstration Projects,” by W. Maas, M. de Nier, T. Wiwchar, and B. Spence, Shell, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed.
A major oil company is progressing a portfolio of commercial-scale carbon-capture-and-storage (CCS) demonstration projects covering an array of technologies that target applications of relevance to the wider oil and gas industry. A number of key learnings have been obtained on the technology-deployment and the critical-project- development aspects of the different project phases. This paper provides an overview of these learnings, with a specific focus on the issues faced by CCS-project developers.
Introduction
Over the last decade, the company, with its partners, has been helping to advance CCS through a series of CCS demonstration projects. The operator’s CCS commercial and project portfolio includes
The Quest project, which is the first CCS project of commercial scale in the heavy-oil industry
The Peterhead CCS project, which, if realized, could be the world’s first commercial-scale, full-chain project to demonstrate the feasibility of CCS at a gas-fired power station
This paper explores in detail the Quest project and the Peterhead project, the latter being currently in the front-end engineering and design phase.
The Peterhead CCS Project
The company and a UK power provider are developing the Peterhead CCS Project (Fig. 1). The scope of the project includes
Operation of an existing gas turbine (GT 13) at the Peterhead Power Station in Aberdeenshire, Scotland
A new steam turbine dedicated to low-pressure steam generation
Capture of approximately 1 million t/a of carbon dioxide (CO2) emissions, for a period of 10 to 15 years, from the flue gas in a large concrete absorber tower using the operator’s amine-capture technology
Regeneration of the amine in a tower using steam from the power plant
Compression and conditioning (oxygen and water removal) of the CO2
Transport of the dense-phase CO2 by an offshore pipeline approximately 100 km in length
Injection of the CO2 with the adapted Goldeneye platform and wells
Storage in the depleted Goldeneye gas reservoir at a depth of more than 2 km under the floor of the North Sea
The objective is that the power plant, combined with the CCS chain, will operate as one integrated low-carbon power-supply chain.
Time-Resolved Fluorescence for Real-Time Monitoring of Scale and Corrosion Inhibitors
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179867, “Time-Resolved Fluorescence for Real-Time Monitoring of Scale and Corrosion Inhibitors: A Game-Changing Technique,” by A. Marais, M. Martini, F. Lepoivre, M. Ould-Metidji, A. Collet, and O. Tillement, Université de Lyon, and C. Hurtevent and S. Baraka-Lokmane, SPE, Total, prepared for the 2016 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 11–12 May. The paper has not been peer reviewed.
Inhibitors have been widely used to reduce steel corrosion and scale deposition in critical offshore sites. However, the large use of such additives has not been followed by the development of any efficient technique of dosage that considers the strict requirements of an offshore platform. This paper describes a novel method of chemical dosage based on time-resolved fluorescence (TRF) that allows a simple, accurate, and efficient quantification of chemicals below parts-per-million ranges, even for double (scale/scale, scale/ corrosion) quantification.
Why TRF Should Be Considered a Game-Changing Technique
The prevention of scale formation and corrosion damage in petroleum pipelines and facilities remains an important challenge (Fig. 1). Several interconnected factors, such as the composition of seawater used for secondary- and enhanced-recovery waterflooding operations, the composition of the formation water, and the gradients of temperature and pressure within pipelines, are the origin of pipeline damage and decrease in extraction efficiency.
The current techniques used for chemicals management often display some limitations (e.g., setup and running costs, size, and real-time monitoring). Some of them also require laborious pretreatment/ purification stages for the separation of inhibitor chemicals from the interfering brine salts.
Here, the TRF method may represent a break from past technologies not only because it displays sub-parts-per-million accuracy and multidetection (scale or corrosion chemicals), but also because it can be set up at offshore sites.
Analytics Firms Explore Oil and Gas Market
Authors: Jacobs Trent 
Published: January 2017

The oil and gas industry is facing an invasion of data analytics startups who saw a wide-open gap in the market a few years ago when talk of big data first began.
Many of these young companies vying for attention from producers are focused on alleviating the headaches associated with artificial lift systems. There are also a number of software products designed to handle difficult computations such as production forecasting and reserve estimation.
Some are selling analytics as a way to combat the growing threat of cyber attacks. Other programs interpret human semantics to extract valuable information out of the entirety of a company’s document library.
Below is a closer look at what several of these analytics startups are offering to the industry—only there will be no deep dive into the layer cake of terminology that dominates this emerging software arena, e.g., artificial intelligence, machine learning, edge computing, etc.
Power of Integration
A sign of the industry’s accelerating uptake of analytics came in May when a number of the world’s largest producers made a USD-26 million investment in an industrial-focused analytics startup from Silicon Valley called Maana. The list of financiers includes the venture arms of Saudi Aramco, Chevron, Shell, and GE.
This may be a leading indicator of things to come because rather than focusing on any particular niche solution, Maana is a big-picture analytics platform. Able to reach between different silos within an organization, the program analyzes seemingly disparate sets of operational data and ties them all together.
Donald Thompson, cofounder and president of Maana, said such data integration is able to generate “new knowledge” that oil and gas producers can leverage to drive performance in the field.
“Most projects involve going and tackling a single isolated problem, but everything in a business tends to be highly interrelated,” he explained. “So the failure of an individual pump is very interesting to understand, but its impact on production schedules is also interesting … if one pump fails, how should you adjust all the other pumps in order to still meet your production requirements?”
Thompson, who pioneered knowledge- and semantic-based search engine tools during his 15 years at Microsoft, gave another example of an oil and gas project involving malfunctioning field sensors.
The Role of Induced Unpropped Fractures in Unconventional Oil and Gas Wells
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174946, “The Role of Induced Unpropped Fractures in Unconventional Oil and Gas Wells,” by M.M. Sharma and R. Manchanda, The University of Texas at Austin, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
The term induced unpropped (IU) fractures refers to fractures created around the main propped fracture that are too small to accommodate any proppant. These could include natural fractures and microfractures induced along bedding planes or along other planes of weakness. On the basis of production data, diagnostic methods, and field observations, it is becoming increasingly clear that IU fractures created during the hydraulic-fracturing operation play a critical role in determining the success of fracture treatments.
Introduction
There has been a debate about whether certain shales are naturally fractured. The classic example of this is the Barnett Shale. Many authors have suggested that the Barnett Shale is highly naturally fractured, whereas others have argued that field observations in the Barnett can be explained on the basis of geologic lithofacies and heterogeneity. Observations made on cores clearly indicate the presence of fractures. Mineralization on the faces of these fractures indicates that they are not drilling-induced fractures but are instead native to the Barnett. Similar questions and discussions have arisen about the role of natural and induced fractures in other shale plays.
One reason that it is often difficult to resolve questions about natural fractures in shales is the extreme level of heterogeneity commonly observed in many types of shale. Differences in lithology and the highly laminated nature of many types of shale are apparent when viewing cores from source rocks such as the Eagle Ford Shale. In some instances, the boundary between the lithologically distinct layers is sharp and well-defined, but, in other instances, it is diffuse and displays its own characteristic lithologic gradation. Boundaries between lithologically distinct layers can often act as planes of weakness along which fractures can develop under stress.
Factors Governing the Performance of Multilayered Metal-Mesh Screens
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178955, “Factors Governing the Performance of Multilayered Metal- Mesh Screens,” by Chu-Hsiang Wu, SPE, and Mukul M. Sharma, SPE, The University of Texas at Austin, and Rajesh Chanpura, SPE, Mehmet Parlar, SPE, and Joseph Ayoub, SPE, Schlumberger, prepared for the 2016 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 24–26 February. The paper has not been peer reviewed.
Multilayered metal-mesh screens (MMSs) are widely used as standalone screens for sand control in unconsolidated formations. The nominal rating of such screens is usually based on the specifications of the filter layer. It is often found that screens with the same filter-layer nominal rating perform differently. It is shown in this study that the primary reason for this is that the sand-retention performance of multilayered MMSs is a strong function of not only the filter layer but also the protection layer and the support layer.
Introduction
The sand-retention ability of a multilayered MMS is evaluated by examining the pore-size distribution (PSD) of the screen as well as its slurry-test sand production [the sand-production evaluation is for plain-square-mesh (PSM) screens only]. Three major steps are involved in the evaluation process:
Generate a multilayered virtual mesh assembly (an example is provided in Fig. 1) based on the mesh specification and different layer-overlap, layer-alignment, and relative pore-size-ratio conditions.
Evaluate the PSD of the virtual screen with a specialized filtration model.
Enter the PSD information into the analytical slurry-test model to quantify the sand-retention performance of the target screen. The model incorporated in this study uses the entire PSD of a PSM screen to predict sand production.
Results
Three types of multilayered MMSs— 175-Μm PSM, 250-Μm PSM, and 115-Μm plain Dutch weave (PDW)—are studied. The name of each type corresponds to the nominal rating and the design of the filter layer. All of the MMSs have the same three-layered structure, with one protection layer above and one support layer below the filter layer. The protection and support layers are PSMs with nominal ratings of 542 and 864 Μm, respectively.
Standardization May Hold Key to Future of Major Offshore Projects
Authors: Parshall Joel 
Published: January 2017

Reducing the complexity and controlling the cost of major offshore projects are together one of the biggest challenges facing the oil and gas industry. The collapse of oil prices has only accentuated the issue, which was already evident when prices were still at USD 100/bbl. To combat the problem, operators are looking at ways to standardize and simplify projects globally as a means of expediting design, construction, installation, and startup; reducing costs throughout the process; and creating safer, more predictable, reliable facility operations.
The scale and complexity of many deepwater projects have driven costs out of control, despite the cyclical pullback of the past 2 years that has reduced the number of active projects and caused equipment and service providers to cut prices.
An analysis of 400 major projects executed in the last 5 to 10 years, cited by Jim Nyquist of Emerson Process Management in a presentation at the IHS CERAWeek conference in Houston, showed a 65% failure rate based on cost overruns of at least 25% or schedule overruns of at least 50%.
Focus on Capital Efficiency
Many of the projects analyzed were launched before the breadth of the shale revolution was apparent. In a future offshore market recovery, in contrast to prior upturns, potential major projects will likely be evaluated against highly competitive shale development plays in the quest for investment funding. The focus on capital efficiency will be even greater, which is why increasing standardization across global projects is likely to become an essential competitive strategy for major offshore operators irrespective of market conditions.
Probably the broadest initiative so far to push for global standardization in upstream development activity is Joint Industry Project 33 (JIP33), facilitated by the International Association of Oil & Gas Producers (IOGP) and supported by the World Economic Forum (WEF), whose “Capital Project Complexity” workstream is being used throughout the project.