bluuebunny/crossref_metadata_2025 huggingface dataset:
Miscible and Immiscible Gas-Injection Pilots in a Middle East Offshore Environment
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18513, “A Case Study on Miscible and Immiscible Gas-Injection Pilots in a Middle East Carbonate Reservoir in an Offshore Environment,” by Jitendra Kumar, Pawan Agrawal, and Elyes Draoui, Abu Dhabi Marine Operating Company, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed.

Hydrocarbon-gas injection improves microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can affect the ultimate recovery negatively because of viscous fingering and gravity override. This paper describes a gas-injection pilot that has been implemented in offshore Middle East carbonate reservoirs (a second pilot is described in the complete paper) to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history.

Introduction

The carbonate field is part of the Lower Cretaceous Lower Lekhwair formation. The field is divided into A, B, and C reservoirs, 20 to 35 ft thick individually. Each reservoir is vertically separated by nonpay tight intervals of similar thickness, composed of argillaceous limestone, isolating each reservoir from the others. Depending on the reservoir, oolitic shoal facies can be more abundant. Near the flank area, the formation is water-wet, and, as one moves toward the crestal area, the formation becomes oil-wet.

The reservoir fluid is undersaturated at initial pressure of 4,200 psig at datum depth and a temperature of 220°F. Oil gravity is 40 °API, and oil contains 1–2 mol% carbon dioxide and an insignificant amount of hydrogen sulfide. All three reservoirs have common contact and similar oil properties, with a strong compositional gradient. Production from the field started in the late 1960s through natural depletion, which indicated weak aquifer support.

Before pilot implementation, laboratory experiments were performed to determine the feasibility of hydrocarbon-gas injection. Pressure/volume/temperature experiments showed that the minimum miscibility pressure (MMP) is approximately 4,500 psia, which is higher than initial reservoir pressure, but the crude oil has a strong swelling effect. Unsteady-state coreflood experiments performed with a 200-cm-long core showed a recovery of 70% for immiscible flood and a recovery of 92% for miscible flood.

Full-field compositional simulation of gas injection incorporating a tuned equation of state indicated significant incremental oil and reasonable pressure support.
Colloidal-Dispersion Gel in a Heterogeneous Reservoir in Argentina
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174704, “CDG in a Heterogeneous Fluvial Reservoir in Argentina: Pilot and Field-Expansion Evaluation,” by D. Diaz and N. Saez, YPF; M. Cabrera, InLab; E. Manrique, Consultant; and J. Romero, M. Kazempour, and N. Aye, Tiorco, prepared for the 2015 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 11–13 August. The paper has not been peer reviewed.

The Loma Alta Sur (LAS) field is a multilayer fluvial sandstone reservoir in the Neuquén basin of Argentina. Reservoir heterogeneities and an adverse mobility ratio (30-cp oil) led to an early water breakthrough soon after water injection started. Colloidal-dispersion- gel (CDG) injection was considered a viable strategy to improve oil recovery in the field.

LAS-58 CDG Pilot Summary

The CDG pilot was implemented in the LAS-58 injector located on the northeastern side of the field. LAS-58 is an irregular pattern that began water injection in 2002, showing an early water breakthrough. The operator estimates that after 3 years of water injection in the LAS-58 pattern, cumulative secondary oil recovery is only 5.48% of original oil in place (OOIP). The LAS-58 pattern includes 10 producers: six first-line producers with well spacing ranging from 138 to 164 m and four second-line producers.

The first tracer-injection program was implemented in March of 2003, 3 months after initial water injection in the LAS-58 injector. The fastest tracer breakthrough was observed in offset producer LAS-18 (50 days). However, the amount of tracer recovered in LAS-18 and LAS-26 was below 1.5% of the total injected. Producer LAS-49 showed the second-fastest breakthrough but with a cumulative tracer recovery of 4%.

Each of the CDG-injection phases was followed by water injection at similar injection rates. The total volume of CDG injected (62 179 m3) represented 3.06% of the pore volume of the LAS-58 pilot area. Phase I consisted of a small injection volume intended to test CDG injectivity and did not affect pilot oil-production response but definitively contributed to adjusting the polymer concentration used in the pilot through Phases II and III of CDG injection.

The main observation after Phase II of CDG injection was a very distinctive change in the injection profile of the LAS-58 injector. The water-injection flow paths were diverted into the middle (Mandrel 2) and bottom (Mandrel 1) zones of the pay zone because of the reduction in injectivity in the thief zones located at the top (Mandrel 3) of the reservoir. In October 2007, the incremental oil production for the 10 offset producers was reported as 133,292 bbl, with a reduction in water production of 406,949 bbl.
E&P Notes (July 2016)
Authors: Jacobs Trent
Published: January 2017

E&P Notes

Small Bubbles, Big Rewards for Separation Technology

Reminiscent of the song made famous by late Hawaiian crooner Don Ho, tiny bubbles are the focal point of a new innovation aimed at transforming produced water from a costly byproduct into a valuable asset.

Termed nanobubbles, they are several times smaller than a human red blood cell, which allows them to play with the physics of how dissolved gas interacts with liquids, according to Nano Gas Technologies. The suburban Chicago-based startup says its technology is capable of cheaply producing these nanobubbles to treat produced wastewater that is among the “worst of the worst.”

The technology works by pushing gas, either oxygen or nitrogen, through a nozzle head that shoots the tiny bubbles into a treatment tank. The result is what the company’s chief executive officer, Len Bland, calls “fluffy water” that causes suspended solids to fall and oil to float to the top where it is easily skimmed off.

“If you want to put it in technical terms,” he said, “we change the specific gravity of the liquid so that it enables the oil that is stuck in the water to rise.”

Search for Flight MH 370 Shows Durability of AUVs

The unprecedented search effort for Malaysian Airlines flight 370 has yet to achieve its main goal of locating the vanished aircraft and the 227 persons on board. However, it has served as an endurance test of sorts for offshore surveying systems such as the autonomous underwater vehicle (AUV), which just a couple of years ago was considered an emerging technology with a small track record. Edward Saade, president of the ocean surveying firm Fugro Pelagos, the company contracted by the Australian government to carry out much of the search operation, said he knows of no other commercial project where AUVs have been successfully deployed for such an extensive period of time.

Speaking at the 2016 Offshore Technology Conference in Houston, Saade said that to cover large swaths of subsea terrain as quickly as possible and capture high-resolution data, Fugro first deployed vessels equipped with conventional deep-tow side scanning sonar. Then starting in January of last year, the AUV vessel was deployed from Perth.

“The purpose of the AUV was to try and get into all those areas that turned out to be blocked in the side-scan operation, either by the steep slopes or other types of data anomalies,” Saade said. “We would preprogram the AUV, launch it and it would do its thing for about 24–28 hours and very effectively fill in all the gaps.”
Use of Emulator Methodology for Uncertainty-Reduction Quantification
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169405, “Use of Emulator Methodology for Uncertainty-Reduction Quantification,” by C. Ferreira, Universidade Estadual de Campinas; I. Vernon, Durham University; D.J. Schiozer, SPE, Universidade Estadual de Campinas; and M. Goldstein, Durham University, prepared for the 2014 SPE Latin American and Caribbean Petroleum Engineering Conference, Maracaibo, Venezuela, 21–23 May. The paper has not been peer reviewed.

Most simulation models go through a series of iterations before being judged as giving an adequate representation of the physical system. This can be difficult because the input space to be searched may be high dimensional, the collection of outputs to be matched may be very large, and each single evaluation may take a long time. Because the uncertainty analysis is complex and time consuming, in this paper, a stochastic representation of the computer model, called an emulator, was constructed to quantify the reduction in the parameter input space.

Introduction

Reservoir simulators are important and widely used in reservoir management. They are used in reservoir-performance prediction and for decision making. These simulators are computer implementations of high-dimensional mathematical models for reservoirs, where the model inputs are physical parameters and the outputs are observable characteristics such as well-pressure measurements and fluid production. Uncertainties are always present in the reservoir-characterization process; thus, input parameters are usually uncertain and so is the simulator output.

The procedure to calibrate the reservoir-simulation model is called history matching. On the basis of observed data, a set of possible input choices for the reservoir model is identified. Two different procedures can be used to perform the history matching: deterministic and probabilistic approaches.

The deterministic approach involves running the initial simulation model with different input values to obtain one simulation model between many probable matches to the field data.

In a probabilistic approach, in which several reservoir-model scenarios are considered, the uncertainty analysis procedure is used. Identifying the input parameters for which the simulation outputs match the observed data can be a difficult task because the input space to be searched may be high dimensional, the collection of outputs to be matched may be very large, and each single evaluation may take a long time.
CO2-Based Enhanced Oil Recovery From Unconventional Reservoirs
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168979, “CO2-Based Enhanced Oil Recovery From Unconventional Reservoirs: A Case Study From the Bakken Formation,” by G. Liu, J.A. Sorensen, J.R. Braunberger, R. Klenner, J. Ge, C.D. Gorecki, E.N. Steadman, and J.A. Harju, University of North Dakota, prepared for the 2014 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 1–3 April. The paper has not been peer reviewed.

In this study, detailed petrophysical and geological field models focusing on the middle and lower members of the Bakken Formation were developed on the basis of field characterization, well-log interpretation, and laboratory core analysis by scanning-electron-microscopy, ultraviolet-fluorescence, and standard-optical-microscopy techniques. A fine-scale model with a pair of horizontal wells was extracted from the initial model (Bailey area) to examine the potential effectiveness of oil-recovery techniques based on carbon dioxide (CO2) injection. The results show that CO2 injection may play a significant role in increasing oil production.

Introduction

Small improvements in productivity could increase technically recoverable oil in the Bakken by billions of barrels. While the use of CO2 in conventional reservoirs is a widely applied and well-understood practice, its use for enhanced oil recovery (EOR) in tight oil reservoirs is a relatively new concept. The use of CO2 as an injection fluid may reduce the hydrocarbon viscosities in the reservoir and allow additional trapped oil to be produced. Another benefit of CO2 injection is to mitigate climate change by storing CO2 in the reservoir. The Energy & Environmental Research Center has conducted a multidisciplinary research program with the ultimate goal of providing industry with insight regarding the potential to use CO2 for EOR in the Bakken and Three Forks Formations.

The Bakken CO2 Enhanced Recovery and Storage Project began in 2012 and was completed in 2013. The objective of this project was to use reservoir characterization and laboratory analytical data (e.g., core analyses, well logs, and oil analyses) coupled with state-of-the-art modeling to examine the viability of using CO2 for simultaneous CO2 storage and EOR in the Bakken. The ultimate goal of the project was to have a Bakken operator apply the knowledge gained from the laboratory, characterization, and modeling activities to a pilot-scale field test of CO2 injection into a Bakken or Three Forks reservoir. The presentation in this paper comprises a discussion of the initial near-wellbore-modeling aspect of the project.
Upon Further Consideration, US Gas Reserves Look Bigger
Authors: Rassenfoss Stephen
Published: January 2017

A second look at the size of US shale formations is revealing they hold far more natural gas, and pushed a new name up near the top of the list: the Mancos Shale.

A recent reassessment of the formation in western Colorado concluded it holds 66 Tcf of shale gas that could be produced using current technology, making it second only to the prolific Marcellus Formation for unconventional gas in the US.

This elevates the profile of the formation, which the US Geological Survey (USGS) had previously estimated at 1.6 Tcf in 2003. The agency also recently upped its estimate for the Barnett Shale, doubling it to 53 Tcf.

“We reassessed the Mancos Shale in the Piceance Basin as part of a broader effort to reassess priority onshore US continuous oil and gas accumulations,” said Sarah Hawkins, a USGS geologist who was the lead author of the study. “In the last decade, new drilling in the Mancos Shale provided additional geologic data and required a revision of our previous assessment of technically recoverable, undiscovered oil and gas.”

Based on a growing body of data, the USGS is working on assessments of two Texas plays, the Wolfcamp in the Midland Basin, and the Eagle Ford Shale; and one in Colorado, the Niobrara in the Denver Basin.

For those drilling into the Mancos, the USGS evaluation confirms what they have been seeing.

“There has been drilling for the last 20 years and there is decades worth of drilling location left,” said David Ludlam, executive director of the West Slope Colorado Oil and Gas Association, who said the gas potential may well exceed 100 Tcf.

He said operators working there have dozens of successful exploratory wells in shale, but the current gas market does not justify development drilling. The gas sands there are commonly developed using slanted vertical wells from pad sites with multiple wells.

The USGS used data from 2,000 wells drilled since its last evaluation, as well as field work and research core analysis, to divide the formation into units with similar geologic and well production characteristics, Hawkins said. That work led to an estimate of technically recoverable reserves for the Mancos ranging from 34 Tcf to 112 Tcf, with a mean of 66 Tcf.

Glowing assessments of the gas in the ground are not fueling the sort of activity that transformed the Marcellus. Recently there were no rigs drilling in the Barnett, and 12 of the 16 wells working in Colorado were in the DJ Basin in the eastern part of the state, according to data by Energent Group, a provider of shale data.
Creating a Safety Culture: What It Is and How To Get There
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 178251, “Creating a Safety Culture: What It Is and How To Get There,” by Daryl Wake, DEKRA Insight, prepared for the 2016 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Abu Dhabi, 26–28 January. The paper has not been peer reviewed.

Safety culture can be distilled into nine characteristics predictive of safety outcomes. By tracking performance across these characteristics, companies can measure their performance against the world’s most successful safety organizations, both within the industry and without. More importantly, they can identify gaps in their culture and breakdowns in their safety performance, thereby establishing clear goals to overcoming them and achieving safety objectives. To improve safety performance and create lasting change in organizational culture, leaders can focus on developing 10 safety-specific leadership capabilities.

Introduction

A strong safety culture means more than just better injury rates. Organizations good at safety have been shown to do better across all performance areas. With improvements in safety comes greater employee commitment to company goals, more discretionary effort, better team functioning, and a healthier bottom line.

A high-functioning safety culture is defined by a clear vision from leadership that articulates actionable steps and specific behaviors leading to the desired state. When people know the goal and what is required of them to achieve it, they will not get lost in vague mandates that fail to motivate or that fall short of galvanizing individuals around safety improvement.

Culture change requires a leadership team that is committed to the vision and capable of guiding the organization through obstacles and the inevitable pushback that occurs with any initiative. Leaders can learn skills and develop capabilities that will move the organization in the desired direction and build performance across the nine culture characteristics indicative of world-class safety performance. With visible commitment to safety, leaders will gain credibility with the workforce and engage people in the process.

Culture Characteristics Predictive of Safety Outcomes

Procedural Justice. This characteristic reflects the extent to which the individual perceives fairness in the supervisor’s decision-making process. Leaders enhance perceptions of procedural justice when they make decisions characterized by consistency across people and time, lack of bias, accuracy (decisions are based on good information and informed opinion), correctability (decisions can be appealed), representativeness (the procedure reflects the concerns, values, and outlook of those affected), and ethicality.
Contract Concerns Loom Over Iraq’s Upstream Outlook
Authors: Jacobs Trent
Published: January 2017

Middle East Special Section

Iraq is producing oil at record levels this year but low oil prices have cast doubts on the economic feasibility of its licensing contracts, which some analysts and policy advisers say are holding back higher output.

International oil companies (IOCs) in Iraq operate under cost-plus contracts that require them to make upfront investments before seeking government reimbursements and a per-barrel fee for their profit. This model has enabled the country to reach a new production benchmark of 4.8 million B/D—an achievement diminished by the fact that Iraq’s export revenues have plummeted by more than two-thirds in the past 2 years. As a result, reimbursements owed to the IOCs have ballooned from around 10% of the national budget to 25%.

Luay Al-Khatteeb, executive director of the Iraq Energy Institute and a fellow at the Columbia Center on Global Energy Policy, said both the government and the IOCs failed to prepare for the consequences of a possible downturn in the industry when they entered into the contracts in 2009–2010.

“They were signed on the basis of high oil prices and were very much technical service contracts with no risk-sharing aspect to them,” he explained. “So everything is being paid by the government, and because high oil prices helped in accommodating such huge repayments, the IOCs in general accepted that.”

In response to its cash flow problems, which include a costly war, the government has held off on funding major infrastructure projects and ordered IOCs to reduce their spending programs.

These decisions may limit the ability of IOCs to deliver any new supplies of crude while they are still waiting on billions of dollars from the government. Last year, the government paid USD 9 billion in arrears to IOCs for work done in 2014. This year, Iraq must make good on another USD 3.6 billion in arrears, according to the terms of a new loan agreement it secured with the International Monetary Fund.

As an adviser to the Iraqi parliament and the prime minister’s office, Al-Khatteeb is recommending that new licensing rounds be issued with production-sharing agreements or tax royalty contracts to drive higher output from the areas operated by IOCs.
Marcellus Wells: Ultimate Production Accurately Predicted From Initial Production
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180234, “Marcellus Wells: Ultimate Production Accurately Predicted From Initial Production,” by Frank Male, Michael P. Marder, John Browning, and Svetlana Ikonnikova, The University of Texas at Austin, and Tad Patzek, King Abdullah University of Science and Technology, prepared for the 2016 SPE Low- Permeability Symposium, Denver, 5–6 May. The paper has not been peer reviewed.

In this work, the authors perform automatic decline analysis on Marcellus Shale gas wells and predict ultimate recovery for each well. A minimal model is used that captures the basic physics and geometry of the extraction process. A key discovery is that wells can have their estimated ultimate recovery (EUR) predicted early in life with surprising accuracy.

Introduction

There are many challenges to production in the Marcellus, ranging from the regulatory and price environment to the highly variable responses of rock to hydrofracture treatment. The complete paper’s primary goal is to generate scenarios for future gas production from the Marcellus by use of varying gas prices and other assumptions.

The first step in this process is determining technically recoverable reserves, which requires deciding how much each well will produce over its lifetime. To do this, the authors use recovery- factor curves that describe total recovery in terms of two parameters: total gas in the stimulated reservoir volume (SRV) and the characteristic time to boundary-dominated flow (BDF).

Most wells produce following these recovery curves, but not all. Upon examining production data, the authors found that several hundred wells have very slow decline for the first several years, slower than the production decline expected from linear flow. In discussions with multiple operators, the authors found that this is attributable to production choking.

There have been several analytical and numerical models developed to predict production from horizontal, hydrofractured shale gas wells. This paper uses the scaling model developed by Patzek et al. (2013) to build recovery-factor curves to describe production for Marcellus wells. Fitting production of 5,275 wells, 404 wells are found that experience boundary-dominated flow. Among these wells, 175 are horizontally drilled. The original gas inside the SRV for these wells is compared with initial production, and a very high correlation is found. This correlation is used to estimate gas production for the remaining wells. Among the entire set of wells, an average EUR of 3.6 Bscf is estimated, with the middle 60% having EURs between 6.6 and 1.8 Bscf. The model for flow to the wellbore is detailed in the complete paper.
Chemical Analysis of Flowback Water and Downhole Gas-Shale Samples
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 175925, “Chemical Analysis of Flowback Water and Downhole Gas-Shale Samples,” by Ashkan Zolfaghari, SPE, Yingzhe Tang, Jordan Holyk, Mojtaba Binazadeh, and Hassan Dehghanpour, SPE, University of Alberta, and Doug Bearinger, SPE, Nexen Energy, prepared for the 2015 SPE/CSUR Unconventional Resources Conference, Calgary, 20–22 October. The paper has not been peer reviewed.

Recently, flowback chemical analysis has been considered to be a complementary approach for evaluating fracturing operations and characterizing reservoir properties. Understanding the source of flowback salts and the mechanisms controlling the water chemistry is essential but also challenging because of the complexity of water/shale interactions. In this study, samples of flowback water and downhole shales are analyzed to investigate the mechanisms controlling the chemistry of flowback water.

Introduction

Field data show that chemistry of flowback water is substantially different from that of the injected water. For instance, in the Horn River Basin (HRB), slick water (with salinity levels similar to those of fresh water) is injected into the reservoir to create fractures, while the recovered flowback water is highly saline (40,000–70,000 ppm).

Analysis of flowback data from the HRB wells indicates that the shape of the salt-concentration profiles is related to the fracture-network complexity. Knowledge of flowback-water composition is also required for water environmental assessment and selection of appropriate remediation strategies.

Although flowback chemical analysis has been used widely to assess fracturing operations, the source of the ions in the flowback water is still a matter of debate. This study analyzes the flowback water and the shale samples to investigate the source of the ions and factors controlling flowback-water chemistry. Intact flowback- water samples are digested in acid to dissolve the precipitated salts and possible colloidal particles. A comparative analysis of the intact and acid- digested flowback-water samples is performed for better understanding of the mechanisms affecting flowback- water chemistry. The intact flowback-water samples are evaporated, and the remaining salts are investigated with X-ray diffraction (XRD) and scanning electron microscopy with energy- dispersive X-ray spectroscopy (SEM-EDXS). Furthermore, a sequential-ion-extraction method is developed to identify the loosely, moderately, and strongly attached ions.
Risk and Reward: Mitigating Risks To Improve Project Results
Authors: Judah Janeen
Published: January 2017

President's column

I am honored to serve the Society of Petroleum Engineers as president this year. Each president chooses a theme, and for me, my theme was obvious: risk and reward.

Ours is a risky business, and that is what makes it fun and challenging. Risk also drives the big rewards when what we do pays off. Mitigating risk is the very core of what we do on a daily basis: drilling risk, subsurface risk, cost/schedule risk, performance risk, safety risk, geopolitical risk, and price risk. Projects are a constant juggle to find the sweet spot where we produce oil and gas safely, responsibly, and profitably. But as an industry, we make decisions to eliminate risk through analysis rather than manage the risk that will always be there. The petroleum industry is fundamentally a commodity business. Commodity prices change, but combine that with a capital-intensive business with big upfront investments and long payouts, and commodity price swings hit us hard.

Engineers are paid to predict the future, especially production, reserves, cost, and schedule. We cannot control price risk, but we can improve performance. I have always been interested in the intersection of engineering and risk evaluation with oil and gas economics. I wrote my master’s thesis on what we would now call “decision analysis.” I was intrigued by deterministic project and economic evaluation and how data are interpreted within the bands of possibility to get a project over economic hurdles. Even with today’s sophisticated probabilistic economic analysis, results still fall short of expectations and promises to stakeholders.

Too Many Projects Fail

The stakes are incredibly high. Independent analysis of large capital projects has shown that as an industry, we are not very good at delivering on our promises. In its spotlight article on oil and gas megaprojects, Ernst & Young estimates that 64% of major capital projects overrun on cost, and 74% face schedule delays. Cost and schedules are overrun in every region of the world. Independent Project Analysis (IPA) comes to very similar conclusions in its subscription benchmarking service, estimating that 60% of projects overrun costs by more than 20% while only 18% of projects meet both cost and schedule targets. IPA also estimates that projects deliver 35% less of their planned overall net present value from financial investment decision to lookback. Some estimate that more than 75% of projects deliver more than 25% less value than promised.

On the production and reserves side, the story is not any better. Ernst & Young’s 2015 US Oil and Gas Reserves study shows that integrated companies failed to replace US production for 2010–2014, despite more than USD 2 billion in capital investment. Independents fared much better at production and reserve replacement during this time period due to high activity in the US shale plays, but shale production will decline rapidly with diminished development programs.
Re-Evaluation of Gravel-Pack-Sizing Criteria
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179023, “Gravel-Pack-Sizing Criteria: It’s Time To Re-Evaluate,” by Christine Fischer, Vernon Constien, and Carla Vining, Constien and Associates, 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.

In this paper, gravel-pack pore size is evaluated further by use of the permeability of the gravel pack and other methods. A new sizing method is proposed that is based on the effective formation size and the gravel-pack pore size. In this manner, the gravel pack is effectively treated like a screen and the selection of gravel-pack size becomes similar to the selection of screen size.

Introduction

Use of a coarser-grained material to stop the production of a finer-sized formation sand in oil wells has been practiced for decades. The selection of the coarser-grained sand has usually been performed on the basis of a multiple of one or more of the smaller particle sizes in the formation material, with the goal being that the formation material will bridge on the larger gravel-pack particles without reducing flow capacity or allowing excessive solids production.

This paper presents an alternative approach to testing and selecting gravel sizes in which the size of the formation material is addressed by using an effective size of the formation grains defined as the median grain size (d50) divided by the uniformity coefficient (d40/d90) and the gravel pack is described by the apparent pore size of the gravel. This approach allows laboratory performance testing for solids production, size of solids, and retained permeability to be compared directly for gravel-pack completions and for screen-only completion. These data are especially useful in the selection of the completion method for horizontal wellbores. Testing methods have been modified so that gravel-pack tests can be performed by both constant-drawdown and constant-rate methods.

A summary of previous important studies investigating gravel-size-selection methods is provided in the complete paper.
Guest Editorial: Incentivizing Energy and Climate Innovation
Authors: Extavour Marcius , Bunje Paul
Published: January 2017

Guest editorial

In a quiet industrial park in suburban Toronto, there is a machine that eats carbon dioxide (CO2) and spits out fuel. This place, typically associated with its strip malls, ethnic and cultural diversity, and peaceful middle class life, might also soon be known as a hotbed of energy innovation. The project’s code name is “Pond.”

A world away, at a world-class research institute in Bangalore, India, engineers have developed a completely different technology to convert CO2 into industrial chemicals. They are motivated by the desire to begin tackling rising global CO2 emissions. Their project code name is “Breathe.”

Aside from a healthy obsession with carbon, what these two efforts have in common might surprise you. Rather than collaborating on an international science project or with a company’s industrial research and development, both are competing to win a global competition to transform CO2 from a liability into an asset and, in so doing, create a paradigm shift in the energy space. Both are competitors in the NRG COSIA Carbon XPRIZE. And the competition is just getting started.

The XPRIZE Foundation relies on the growing power of exponential technologies and revolutionary science to catalyze radical breakthroughs. This means developments in science and technology such as robotics, artificial intelligence, nanotechnology, big data, and other disruptive forces have the potential to show exponential impact on grand challenges such as sustainable energy and climate change. By offering a suite of incentives in a prize competition, XPRIZE seeks to inspire the world’s scientists, technologists, and innovators to tackle seemingly intractable challenges.

Transforming our energy systems may be the 21st century’s greatest challenge. Articulating a grand challenge does not solve any problems, but a clear and deep articulation of the problem demands an understanding of the complexity and nuance involved in the problem itself and in a vision for defining characteristics of a solution. In our approach to energy innovation, XPRIZE recognizes that the technological, sociopolitical, and economic changes occurring globally present innovators with a rare opportunity to apply truly groundbreaking research to challenges of worldwide importance. We operate at the intersection of audacious and achievable.

The Carbon XPRIZE is a USD 20 million global competition to incentivize technologies that convert CO2 emissions into valuable products. The winning teams will convert the largest quantity of CO2 from actual flue gas from coal or natural gas power plants into one or more products with the highest net value. The 10 teams that survive the first two elimination rounds (proposal evaluation was in summer of 2016, and lab-scale demonstration from late 2016 through 2017) will use two brand new test centers adjacent to operating power plants in western Canada and the US state of Wyoming to demonstrate their solutions at industrial scale.
A STUDY OF THE FLOCCULS STRENGTH OF POLYDISPERSE COAL SUSPENSIONS TO MECHANICAL INFLUENCES
Authors: Shkop Andrii , Tseitlin Musii , Shestopalov Oleksіi , Raiko Valentina
Published: January 2017

The effect of the concentration and disperse composition on the flocculation strength to mechanical influence is investigated. It is found that the residual rate of floccules sedimentation after the mechanical influence at a constant rate of flocculant has a maximum value at a concentration of solids in the slime in the range of 7-30 g/dm3. The best results are obtained in all the experiments at a solids concentration of 10 g/l. It is found that at a concentration up to 7 g/l and more than 30 g/l, the floccules is formed. They have the lowest residual rate after mechanical influences. With increasing content of the solid fraction of 40-100 microns over 15%, the strength of floccules increases. They retain their shape and relatively high sedimentation rate even after mechanical influence. The obtained data allow to recommend correction of the slime composition before flocculant injection both the concentration close to the optimum, and the content of size fraction of 40-100 mm more than 15 %.
SOCIAL ENTREPRENEURS IN LEBANON: AN EXPLORATORY STUDY OF WOMEN ENTREPRENEURS ENGAGED IN THE PROFESSIONAL INTEGRATION OF LOW-SKILLED WOMEN
Authors: Wahidi Inaya , Lebegue Typhaine
Published: January 2017

In a country like Lebanon, where the participation rate of women in the labor force is low, around 24 % in 2014 [1], women social entrepreneurs try to alleviate this problem by targeting Low-skilled women. Our exploratory study aims to identify the motivations of six women social entrepreneurs. These entrepreneurs perceive that low-skilled women need to be reintegrated into society and suffer from gender discrimination at hiring in Lebanon. They also have personal experience that has sparked their interest in the employment of low-skilled women. Interactions with marginalized women and gender discrimination lived throughout their personal and professional lives are also considered as important motivators. Finally, women social entrepreneurs point out that working for the professional integration of low-skilled women gives them personal satisfaction while taking a limited risk. Our qualitative exploratory study was supplemented by a quantitative study among fifty-seven low-skilled women to ascertain the motivations of the women social entrepreneurs who employ them. The results seem to confirm the majority of motivations reported by social women entrepreneurs especially in term of personal satisfaction.
Plant Secondary Metabolites in Alfalfa, Birdsfoot Trefoil, Reed Canarygrass, and Tall Fescue Unaffected by Two Different Nitrogen Sources
Authors: Clemensen Andrea K. , Provenza Fredrick D. , Lee Stephen T. , Gardner Dale R. , Rottinghaus George E. , Villalba Juan J.
Published: January 2017

Plant secondary metabolites (PSM) may increase the sustainability of agriculture systems by reducing inputs, as PSM protect plants against herbivores and pathogens, act as pesticides, insecticides, and anthelmintics while also attracting pollinators and seed dispersers. Therefore, it is important to understand what affects PSM fluctuation in plant tissues. Limited research has investigated how different nitrogen (N) sources affect PSM concentration in alfalfa (Medicago sativa L., Alf), birdsfoot trefoil (Lotus corniculatus L., BFT), reed canarygrass (Phalaris arundinacea L., RCG), and endophyte‐infected tall fescue (Festuca arundinacea Schreb., E+TF). We investigated how fecal manure (feces) and synthetic N fertilizer (urea, 46% H2NCONH2) influence N concentrations and the PSM ergovaline, gramine, saponins, and extractable condensed tannins (CT) in E+TF, RCG, Alf, and BFT, respectively. Ergovaline, saponins, and CT were not affected by fertilization. Gramine tended (P = 0.06) to be greater in control plots than in fertilized plots. Total N in E+TF and RCG was greater (P < 0.05) and tended to be greater for Alf (P = 0.08) in synthetically fertilized plots than in unfertilized plots. Seasonal variation in PSM and N was significant (P < 0.003) across all species and was species specific. Total N in E+TF was greatest in June (41.4 g kg−1), while ergovaline contents were at the lowest values recorded (117.2 μg kg−1), with subsequent increases to the greatest ergovaline values observed in July (680.0 μg kg−1). Our results reveal the variability in PSM production by plants and highlight the complexities of predicting fluctuations of PSM in forages. As environments where plants grow vary through space and time, we recommend studies on a case‐by‐case basis, depending on land management objectives.
"Any Search for an Origin is Hysterical": Summoning the Ghost of J.L. Austin
Authors: Andersen Tawny
Published: January 2017

As the father of the concept of the “performative utterance”, British philosopher of language J.L. Austin is regularly cast as the point of origin in a genealogy tracing the influence of linguistic theory on performance theory. Based on extensive research into Austin’s writing praxis, this paper demonstrates that the philosopher produced and disseminated his research orally, dialogically, and pedagogically through contexts that privileged the inter-subjective exchange. It frames Austin’s self-described practice of “linguistic phenomenology” as a pragmatic one in which philosophy is context. I demonstrate that this mode of “doing” or “performing” philosophy is also at play within the dramaturgy of Austin’s texts, which restage his thought processes and invite his readers to become spectators to the dramatization of his ideas. My analysis offers up a portrait of a J.L. Austin who enacted his philosophy about the performative utterance in a performative manner. In so doing, it exposes the inaugural texts about performativity as hybrid objects that trouble the concepts of “authorship” and “origin”. It also shows that these texts are infected, at their inception, by parasites, by literature, by the Other, and by the ghosts that Austin tried so hard to exorcise, yet that—on some level of consciousness—he simultaneously allowed to haunt his philosophical voice.
Running, Resistance, and Recollection: A conversation with ourselves through time
Authors: Coe Katye , Blades Hetty
Published: January 2017

(to) constantly vent is a performance work by Katye Coe. A solo or group of runners travel in continuous loops, venting through events, exhibitions, meetings, and the surrounding spaces. The work was commissioned for What_Now (2013) in London and re-commissioned for the Dancer As Agent conference (2013) at DOCH in Stockholm where it was a constant or persistent intervention through a conference all about the agency of the dancer. This outing bought with it wider conversations and meetings that have changed its (and Coe’s) practice and thinking. Continuing its journey, the work was then enacted at Performing Process: Sharing Practice symposium (2014) at Coventry University, and was later re-situated in the Hayward Gallery (2014-15), where the work occurred for 12-weeks as part of Volumes Project in the exhibition, MIRRORCITY.Reflecting on the experience of venting in the Hayward Gallery, in this writing Coe and Hetty Blades, who also performed the work, recall their experiences, and respond to their questions about the practice through their fragmented memories and writing from others about running and memory.
Ośrodki protonoterapii w Polsce i na świecie.
Authors: Nowak Agata
Published: January 2017

Protonoterapia, jako jedna z form leczenia nowotworów gwarantuje dostarczenie wysokiej dawki do zadanej objętości, przy dokładnej ochronie tkanek zdrowych. W związku z tym, iż następuje ciągły rozwój tej metody leczenia, powstaje również coraz więcej placówek oferujących pacjentom leczenie nowotworów przy użyciu protonów. Zastosowanie kliniczne obejmuje coraz większe spektrum  dotyczy leczenia  przede wszystkim takich lokalizacji jak: gałka oczna czy mózg. Protonoterapia jest wyjątkowo dobra metodą leczenia zmian nowotworowych u dzieci, ze względu na maksymalną ochronę tkanek zdrowych. W pracy opisano wybrane ośrodki protonoterapii w Polsce i na Świecie. W naszym kraju obecnie działa jeden ośrodek – Centrum Cyklotronowe w Bronowicach, który zajmuje się przede wszystkim leczeniem zmian zlokalizowanych w gałce ocznej. Rozpoczęto również działania w ramach projektu INPRONKO, który w dużej mierze przyczyni się do znacznego rozwoju protnoterapii w Polsce. W pracy opisano również takie placówki jak Paul Scherrer Institute, gdzie poraz pierwszy zastosowano dynamiczną wiązkę skanującą,  Zjednoczony Instytut Badań w Dubnej, prywatny ośrodek Rinecer Proton Therapy Center, gdzie do leczenia wykorzystuje się trójwymiarową wiązkę protnów. Kolejną opisaną w pracy placówką jest MD Anderson Cancer Center specjalizujący się w leczeniu zmian nowotworowych przy pomocy techniki IMPT. Proton Medical Research Center w Tsukuba to ośrodek, w którym oprócz gałki ocznej naprmieniania się takie lokalizacje jak wątroba, gruczoł krokowy czy przełyk.
Towards a research agenda for water, sanitation and antimicrobial resistance
Authors: Wuijts Susanne , van den Berg Harold H. J. L. , Miller Jennifer , Abebe Lydia , Sobsey Mark , Andremont Antoine , Medlicott Kate O. , van Passel Mark W. J. , de Roda Husman Ana Maria
Published: January 2017

Clinically relevant antimicrobial resistant bacteria, genetic resistance elements, and antibiotic residues (so-called AMR) from human and animal waste are abundantly present in environmental samples. This presence could lead to human exposure to AMR. In 2015, the World Health Organization (WHO) developed a Global Action Plan for Antimicrobial Resistance with one of its strategic objectives being to strengthen knowledge through surveillance and research. With respect to a strategic research agenda on water, sanitation and hygiene and AMR, WHO organized a workshop to solicit input by scientists and other stakeholders. The workshop resulted in three main conclusions. The first conclusion was that guidance is needed on how to reduce the spread of AMR to humans via the environment and to introduce effective intervention measures. Second, human exposure to AMR via water and its health impact should be investigated and quantified, in order to compare with other human exposure routes, such as direct transmission or via food consumption. Finally, a uniform and global surveillance strategy that complements existing strategies and includes analytical methods that can be used in low-income countries too, is needed to monitor the magnitude and dissemination of AMR.
Reproductive outcomes of fertility sparing surgeries in germ cell tumours
Authors: Wakpaijan Ujwala Prakash
Published: January 2017

The main aim of the study is to observe the reproductive outcome in patient of germ cell tumour after fertility preserving surgery. In which retrospective records of patients diagnosed with malignant GCT in young patients treated with fertility sparing surgery and chemotherapy for ten years from 2000 to 2009. From the careful observations concluded the overall survival with the patients treated with fertility sparing surgery is excellent and the reproductive outcome is more or less equivalent to the general population of same age group.
Designing Experiments that Control for Spatial and Temporal Variation
Authors:   Department of Biology, University of Pennsylvania, Philadelphia, PA 19104-6018, USAe-mail: ppetrait@sas.upenn.edu, Petraitis Peter
Published: January 2017

Spatial and temporal variation can cause problems in designing and conducting experiments. Anintroduction to methods for controlling spatial and temporal variation in ecological experiments is providedin this article. Failure to consider spatial and temporal variation often causes researchers to lay outexperiments incorrectly. The challenge is to design experiments that not only reflect the natural variationseen in the field but also control for the variation so that statistical tests have sufficient power.Spatial variation is usually controlled by grouping observations and treatments into blocks. Blockscan be laid out in a number of ways and Analysis of Variance (ANOVA) approaches to control for blockeffects are discussed.The control of temporal variation presents special difficulties because data are often serially correlatedand so observations are not independent. Use of intervention analysis and repeated measures analysis ofvariance to control for temporal variation are discussed. Ecologists have also used experimental designswhich are known as BACI designs (i.e., Before-After-Control-Impact design) and can be extended toinclude multiple control and/or impact sites. Intervention analysis, BACI designs, and their extensionshave subtle differences because of different assumptions about not only temporal variation but alsospatial variation.Several recommendations are given. These include: 1) the need to have good statistical advice beforestarting an experiment, 2) the need to have a sufficient number of replicates that are spread over the rangeof spatial and temporal variation, and 3) the need to correctly control for serial correlation