bluuebunny/crossref_metadata_2025_split huggingface dataset:
Operations Excellence Begins in Design
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18566, “Operations Excellence Begins in Design,” by Wesley R. Qualls, ConocoPhillips, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed.
Achieving production and availability targets is paramount to the ultimate success of any liquefied-natural- gas (LNG) project. Both are important factors in any life-cycle economic analysis. The focus on true operational excellence must begin early in the design phase and remain endemic throughout. This paper focuses on common design pitfalls and oversights within the LNG industry and presents several methods or techniques to avoid them. While the techniques and methods presented are not new to the oil and gas industry, they are often not used within the LNG industry.
Introduction
The first and foremost consideration in almost any process design is defining feed conditions and product specifications properly. Ideally, this should occur well before beginning process design, but, unfortunately, this is not always the case. Because most recognize the importance of defining feed pressure, feed temperature, and product specifications, these particular variables are generally well-defined. However, accurately characterizing feed compositions and quantifying feed contaminants remain common industry oversights. The lack of diligence in these areas can and does lead to numerous operating problems, some of which are difficult and costly to address.
Many critical project considerations are involved in the process, equipment, and piping design. Design oversights with this type of work process are common, often resulting in late design changes and rework. To avoid added cost and schedule delays, many smaller design oversights discovered later in design are simply accepted. A question frequently and understandably asked in later project phases is, “Will it work?” Seldom in later project phases is the question asked, “Will it work well?” Naturally, once the perceived cost of correcting a problem becomes greater than the perceived benefit, the focus on operations excellence cannot endure.
Therefore, it is of paramount importance to eliminate as many design oversights as possible early in the project timeline.
Feed Contaminants
While it may be intuitively obvious that it is necessary to identify and quantify feed contaminants, the effort does not always receive sufficient attention. If contaminants (e.g., methanol, glycols, oxygen, corrosion inhibitors, compressor oils, acids, chlorides, salts, aerosols, iron sulfide, and dust and other particulates) are identified and quantified properly from the outset, the processes and equipment to remove them, and in some cases to recover them, may be properly selected and sized early in design. Otherwise, equipment must be added, modified, or replaced late in design or after operation begins.
New Approach Tests Cement-Sheath Integrity During Thermal Cycling
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173871, “Cement-Sheath Integrity During Thermal Cycling: A Novel Approach for Experimental Tests of Cement Systems,” by J. De Andrade, SPE, and S. Sangesland, SPE, Norwegian University of Science and Technology, and J. Todorovic, SPE, and T. Vrålstad, SPE, SINTEF Petroleum Research, prepared for the 2015 SPE Bergen One Day Seminar, Bergen, Norway, 22 April. The paper has not been peer reviewed.
Well cement is placed into the annulus between casing and formation to provide structural support and zonal isolation throughout the well life cycle. Nevertheless, operators in the North Sea have been concerned about the ability of the cement sheath to maintain sealing integrity because of the increasing number of reported failures in mature wells. A new laboratory setup is designed to allow visualization of the development of possible leak paths throughout the cement sheath when exposed to pressure-and temperature-related varying loads.
Experimental Setup
The new laboratory setup presented in this work allows pressurization while maintaining the capability to perform a detailed study of the creation and propagation of cement-sheath failures upon thermal cyclic loads.
The cell is shown in Fig. 1.
The applied formation materials were Saltwash North sandstone and Mancos shale.
Some of the current features of the cell are specified as follows:
Cell is X-ray transparent.
Temperature is controlled (from inside the casing) during cement setting and cyclic tests.
There is independent control of pressure inside casing on cement and confining pressure (around the rock) during cement setting and cyclic tests.
Maximum pressure is set at approximately 35 bar, while the allowable temperature range is set between −1°C and 150°C.
All components of the cell can be reused for several test samples.
In particular, the X-ray transparency is important because it allows for visualization of leak paths without the need to release pressure from the cell, or remove the internal test sample for a computed-tomography (CT) scan, or perform the traditional invasive method of cutting the test sample cross section. This was achieved by constructing the cell from aluminum, which has suitable radiolucent characteristics and allows the radiant energy to pass toward the test sample with little attenuation. The material also provides a lightweight cell to facilitate handling.
Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179690, “Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery,” by Chang Da, Zheng Xue, Andrew J. Worthen, Ali Qajar, Chun Huh, Mascarona Prodanovic, and Keith P. Johnston, The University of Texas at Austin, prepared for the 2016 SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. The paper has not been peer reviewed.
Carbon dioxide (CO2)/water foams are of interest for mobility control in CO2 enhanced oil recovery (EOR) and as energized fracture fluids or as hybrid processes that combine aspects of both processes. It is challenging to stabilize ultradry foams with extremely high internal-phase gas fraction given the high capillary pressure and the rapid drainage rate of the lamellae between the gas bubbles. However, the authors demonstrate that these ultradry CO2- in-water foams may be stabilized with surfactants that form viscoelastic wormlike micelles in the aqueous phase.
Introduction
In this study, the authors extend the study of ultradry CO2/water foams composed of worm-like micelles to higher temperatures by adding an electrolyte, potassium chloride (KCl), and a cationic surfactant, decyldimethylamine (C10DMA), to the primary surfactant, sodium lauryl ether sulfate (SLES). The continuous-phase viscosity and surface shear viscosity of this formulation were found to be approximately two orders of magnitude higher when worm-like micelles were formed at room temperature. The foam morphology was measured at high pressure with microscopy, and a long lifetime of foam bubbles was demonstrated. The morphology of the worm-like micelles was also characterized by cryogenic transmission electron microscopy.
The authors have been able to manipulate foam stability for various specialty applications such as EOR where low water consumption, foam stability and extended life span, and conformance of the foams are crucial. In particular, these high-quality stable foams have been developed and tested at laboratory scale in high-salinity and high-temperature conditions to mimic the actual reservoir condition. These high-quality, highly stable foams have been generated and tested by use of sandpacks at the laboratory scale. In this work, a numerical simulation of foam injection into a layered reservoir is performed.
Drilling Slump in North Dakota Allows Rapid Flaring Reduction
Authors: Rassenfoss Stephen 
Published: January 2017

Natural gas flared in the Bakken has abruptly declined this year, reaching 8% in April, a striking change from the days when more than one-third of the gas from the oil-rich formation was burned.
“In 2014, flared volumes in the state reached 0.35 Bcf/D, equal to almost half of total volumes that were either flared or vented in the United States,” according to a report by the US Energy Information Administration (EIA).
The percentage of gas flared in April was half of what it was at the end of last year, and the volume is the lowest since 2011, according to totals reported by the state.
During the Bakken boom in 2014, nighttime pictures from space served as a sign of the times, showing the light from the many flares in the sparsely populated state that otherwise would look mostly dark. While lights are still visible, they are not as bright.
The EIA reported flaring in the state “has declined sharply since 2014,” based on numbers from the North Dakota Industrial Commission’s Department of Mineral Resources.
The volume of gas flared is down because more is flowing to market via the state’s expanded network of pipeline and processing facilities. The amount burned looks even smaller as a percentage because the total amount of gas produced has been rising in North Dakota, which set a record for output in March.
The accelerated rate of decline was a bit of a surprise. Last fall, North Dakota regulators stretched out the timetable for a reduction in flaring to 10% of the total gas production by 2020, after the industry asked for more time to deal with issues slowing the expansion of pipelines and processing facilities.
North Dakota officials are wary about declaring victory. “In the near term we expect to have a high level of gas capture in North Dakota,” said Justin J. Kringstad, director of the North Dakota Pipeline Authority, who closely follows the business. “But over the long term it is something we are continuing to look at.”
Guest Editorial: Low Prices Trigger Much-Needed Change Through a Holistic Approach
Authors: Jackson Dan 
Published: January 2017

Guest editorial
Change in the oil and gas industry often comes slowly. However, as months of low oil prices turn into years, it is necessary now. Oil producers have taken to cutting billions of dollars in expenditure, which has forced providers and contractors to slash rates and delay and even cancel projects.
The upstream industry in particular needs to fundamentally transform the way it works to survive and thrive. While cost-cutting can be an effective plan in the short term, the industry needs to take a longer-term focus and change the fundamentals of the way it operates. To compound matters, the days of triple-digit oil prices appear well and truly over, with the World Bank estimating that a barrel of oil will only rise to USD 60 by 2020.
Regardless of the oil price, the sector needs to rethink established ways of working in order to better handle increasingly complex projects. The high crude price in recent years helped the industry gloss over inefficiencies and enjoy success in the short term. But the recent slump has fully exposed shortcomings, and shone a spotlight on the fact that the offshore industry was on an unsustainable path and in need of guidance to standardize processes to lead the industry through a turbulent time.
Taking a Holistic Approach
A reason why projects are not completed on time and on budget is the disconnect between operators and contractors. A recent report from Ernst & Young on oil and gas megaprojects showed that 21% of project failures came down to management processes and contracting and procurement strategies; 65% were due to people, organization, and governance; and 14% of failures were due to external factors such as government intervention and environment-related mandates.
The existing model of contracting is piecemeal with specialist designers, contractors, and projects managers coming on board one at a time, with no one group bringing the whole project together at the front end to deliver efficiencies and control that should be standard in the offshore sector.
Oil companies and contractors, therefore, need to work together better to understand the drivers and develop the best blueprint to take the project forward into execution with a common purpose. The benefits of a holistic approach mean that all aspects of a project are taken into consideration from the beginning to ensure that it can be delivered on time, on budget, and with certainty.
Understanding Completion Performance: Software-Guided Work Flows and Models
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179172, “Understanding Completion Performance in Niobrara-Codell Reservoirs Through the Use of Innovative Software-Guided Work Flows and Models,” by K.J. Wallace, Encana Oil and Gas; P. Reyes Aguirre, Schlumberger; E. Jinks and T.H. Yotter, Encana Oil and Gas; and Raj Malpani and Felipe Silva, Schlumberger, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed.
This paper describes a comprehensive field study of eight horizontal wells deployed in the stacked Niobrara and Codell reservoirs in the Wattenberg Field (Denver-Julesburg Basin). The overall goal was to understand the geometry of the hydraulic fractures (propped) and the producing volume with respect to completions design, target reservoirs, and well spacing. Through this understanding, the asset can be developed more effectively and economically.
Field Description
The Wattenberg Field is a basin-center petroleum accumulation located northeast of Denver, from which hydrocarbons have been extracted over the last 50 years. Development in the Wattenberg Field began in 1970 from vertical J-Sandstone wells, with production of the Niobrara following in 1976. In 2009, horizontal development began in the Niobrara formation. The Upper Cretaceous sequence from Codell to Niobrara is the current focus of horizontal development in the Wattenberg Field.
Petrophysical Model
A robust 3D mechanical Earth model (MEM) provides the framework for data integration and physical simulations. In this work flow, the MEM calculates or approximates a number of input parameters. Each of these variables is defined both spatially and stratigraphically and is housed in a 3D geocellular model. Because many of the input calculations are dependent on other variables, a set of variable relationship definitions keeps the model dynamic so that, during the tuning process, all initially established data relationships are honored.
Shift Toward Permian Drives Rising Rig Count
Authors: Parshall Joel 
Published: January 2017

Don’t look now, but the United States rig count has inched up in recent months, and the driver has been the old reliable of onshore oil production, the Permian Basin of west Texas and New Mexico.
While some observers might see the scenario as a simple case of drillers responding to the recovery of oil prices over the spring and summer, the fact that rig growth occurred chiefly in the Permian indicates there is more to the story. And along with a similar, smaller shift of gas rig activity toward the Marcellus and Utica basins in Pennsylvania and Ohio, the statistics suggest what the geographic footprint of an eventual, long-term recovery may look like in the US.
The number of active oil rigs nationwide rose to 407 for the week ending on 2 September, according to Baker Hughes, up from 316 for the week of 27 May. Of the additional 91 rigs, 65 were activated in the Permian Basin. Beginning from a low point of 132 rigs operating in the week of 29 April, the basin has added 70 rigs, and it currently has more than 50% of the horizontal oil rigs operating in the US, up from 15% in 2011.
A smaller growth trend has emerged in Oklahoma, where 10 rigs were added between 13 May and 2 September to bring the statewide total to 66. The increase has centered on the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend, Anadarko [Basin], Canadian [County], and Kingfisher [County]) plays.
On the US natural gas side, the 88 rigs operating at the beginning of September reflected little change since spring. However, a shift in deployment had added six rigs to the Marcellus since 5 August and four rigs to the Utica since 20 May. The total number of rigs operating in the two basins were 27 and 14, respectively.
Model for a Shale-Gas Formation With Salt-Sealed Natural Fractures
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175061, “Model for a Shale-Gas Formation With Salt-Sealed Natural Fractures,” by Hoagie Merry and C.A. Ehlig-Economides, University of Houston, and Pang Wei, Sinopec Research Institute of Petroleum Engineering, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
Most multiple-transverse-fracture horizontal wells in shale-gas formations remain in transient bilinear or linear flow for very long periods. However, there are often reported cases of shale wells that exhibit boundary-dominated flow in a very short period, which implies a stimulated rock volume (SRV) much smaller than would be expected. This paper offers an alternative explanation for the early boundary-dominated flow related to dissolution of salt-sealed natural fractures in the shale.
Introduction
Operators producing gas from the Haynesville, Marcellus, and Horn River shale formations have observed that produced water is more saline than the injected fracturing fluid. Additionally, the fraction of injected water that flows back when the well is put on production— termed load recovery—is low.
This study investigates the possibility that salts removed by flowing back injected low-salinity water-based fracturing fluid may be a mechanism for increasing the effective permeability in shale-gas wells within a limited volume surrounding the created hydraulic fractures. The study offers strong evidence that salt may be a key factor in productivity and ultimate gas recovery from shale-gas wells.
Interactions Between Fluids, Salt, and Shale
Several fracturing-fluid/formation interactive phenomena relate strongly to the material-balance model that the authors have developed. These phenomena include the imbibition and entrapment of injected fracturing fluid, the increase in salinity of the fluid in contact with the shale, and the deterioration of shale samples.
Several researchers have studied the relationship between the low load recovery of hydraulic-fracturing fluid and the elevated salinity of the fluid that does return. Many authors have proposed relationships between the surface area of the formation exposed to fracturing fluid, the characteristics of the fluid, the wettability of the rock, and the distribution or characteristics of the natural-fracture system. These findings are examined in detail in the complete paper.
Positron-Emission Tomography Offers New Insight Into Wormhole Formation
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180051, “New Insight Into Wormhole Formation in Polymer Gel During Water Chase Floods Using Positron-Emission Tomography,” by B. Brattekås, University of Stavanger; M. Steinsbø, A. Graue, M.A. Fernø, and H. Espedal, University of Bergen; and R.S. Seright, New Mexico Petroleum Recovery Research Center, prepared for the 2016 SPE Bergen One-Day Seminar, Bergen, Norway, 20 April. The paper has not been peer reviewed.
Polymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. Polymer-gel behavior is often studied in corefloods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chase floods. The work presented in this paper uses complementary positron-emission-tomography (PET)/computed-tomography (CT) imaging to quantify the behavior and blocking capacity of gel during chase waterflooding.
Introduction
Channeling of injected fluids through a highly permeable fracture network, and the following early fluid breakthrough, may be mitigated by placing a highly viscous polymer gel in the fracture. With polymer gel in place, higher differential pressures may be achieved during chase floods, which can contribute to increased sweep efficiency in the porous matrix adjacent to the fracture network.
A polymer gel is formed when a gelant solution is exposed to elevated temperature for a given time, known as the gelation time. Previous work has investigated how the gel state during placement (gel or gelant) influenced the gel behavior during chase floods. The complete paper provides a detailed discussion of previous models for fluid leakoff. In this work, the authors study the extrusion of formed polymer gel through fractures, and its resistance to pressure during subsequent waterfloods.
PET imaging is based on the decay of positron-emitting radionuclides. In this work, PET was used to visualize flow of radioactive water through a gel-filled fracture, to augment global measurements, and to increase the understanding of filter-cake formation during formed-gel placement and wormhole formation during chase floods.
A discussion of the experimental setup, including limestone- and sandstone-core-plug preparation, polymer-gel placement, the chase-flood procedure, and the PET-imaging process, is provided in the complete paper.