bluuebunny/crossref_metadata_2025_split huggingface dataset:
Penggunaan Keong Bakau Telescopium sp (Gastropoda: Potamididae) dan Siput Bakau Cerithidea sp (Gastropoda: Potamididae) Sebagai Biofilter terhadap Limbah Budidaya Ikan Bandeng (Chanos chanos)
Authors: Khalil Munawar , Ezraneti Riri , Jannatiah Jannatiah , Hajar Siti 
Published: January 2017

Mangrove snail Telescopium sp and Cerithidea sp are natural biofilter that able used to manage the changes in water quality caused by the culture sewage. This research aimed to analyze the utilization of Telescopium sp and Cerithidea sp as natural biofilter for re-improving water quality level from culture sewage in the laboratory scale. The outcome of this study was expected to be valuable information that mangrove gastropods not only as pests in mariculture ponds, but also able to use as natural biofilter in pond sewage management for recovering water quality level. This research was conducted from April to July 2016 in Hatchery and Aquaculture Technology Laboratory, Aquaculture Department, Agriculture Faculty, Malikussaleh University. Descriptive and quantitative methods used in this research including two treatment and three replications. Water quality such as turbidity, temperature, ammonia, nitrate, nitrite, orthophosphate, pH and dissolved oxygen measured periodically as research parameters. The result showed that the utilization of mangrove gastropod Telescopium sp and Cerithidea sp as natural biofilter was able to re-improving the water quality value such as pH, ammonia, nitrat, nitrit, orthophosphate and turbidity to the normal level. Meanwhile, the utilization of mangrove gastropods as natural biofilter does not gave any significant changes in the value of temperature, salinity and dissolved oxygen. Cerithidea sp also has better performance to reduce the water nutrient level in culture sewage compared than Telescopium sp. Keyword: mangrove gastropod, biofiltration, water quality, culture sewage
Pilot Tests of New Enhanced-Oil-Recovery Technologies for Heavy-Oil Reservoirs
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 176703, “Pilot Tests of New EOR Technologies for Heavy-Oil Reservoirs,” by L.K. Altunina, V.A. Kuvshinov, and I.V. Kuvshinov, Institute of Petroleum Chemistry, Siberian Branch of the Russian Academy of Sciences; and M.V. Chertenkov, SPE, and S.O. Ursegov, Lukoil, prepared for the 2015 SPE Russian Petroleum Technology Conference, Moscow, 26-28 October. The paper has not been peer reviewed.
Thermal steam stimulation (TSS) is considered the most effective of current methods for heavy-oil production. However, the method has problems with low coverage by steam injection and decreased efficiency at later stages of development. This paper presents the results of solving these problems by combining thermal steam and physicochemical stimulations and using “cold” technologies involving thermotropic gel-forming and oil-displacing systems.
Introduction
In Russia, the amount of oil reserves considered difficult to recover is constantly increasing. Active reserves account for one-third of all prospected reserves, and the difficult-to-recover oil reserves account for 67%. High-viscosity oils are 13% of the difficult-to-recover oils, and low-permeability formations account for 36%. The amount of heavy and high-viscosity oil is several times greater than the amount of light and low-viscosity oil. Therefore, the development of the deposits of heavy and high-viscosity oils is given more attention. To develop heavy- and high-viscosity-oil reservoirs effectively and increase oil production, new, integrated enhanced-oil-recovery (EOR) technologies are necessary. The new technologies addressed here combine basic reservoir stimulation by water or steam injection and physicochemical methods, increasing reservoir coverage and oil-displacement factors and improving the development.
In recent years, thermal methods—oil displacement with steam, cyclic steam injection, and steam-assisted gravity drainage— have been the most widespread EOR methods used in heavy-oil fields. One can improve the efficiency of steam stimulation by combining it with physicochemical methods—in particular, using thermotropic gel-forming and oil- displacing systems—thereby increasing the reservoir coverage by steam injection and providing additional oil displacement.
Integrating Physicochemical Methods and TSS
This approach uses the concept that reservoir energy or energy from an injected heat carrier can generate in-situ “intelligent” chemical systems (i.e., gels, sols, surfactant solutions, and buffer systems with controlled alkalinity). These systems remain for a long time and are self-supporting in reservoirs with complex properties, making them optimal for oil displacement.
Near-Surface Velocity Model To Enhance PSDM Seismic Imaging of Dukhan Field
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18293, “Near-Surface Velocity Model of Dukhan Field From Multiphysics Survey To Enhance PSDM Seismic Imaging,” by K. Setiyono, Qatar Petroleum; S. Gallo, C. Boulanger, F. Bruere, F. Moreau, and B. Rondeleux, CGG; and J. Snow, Qatar Petroleum, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed.
Dukhan field affords an opportunity to assess alternative near-surface velocity-modeling work flows that specifically integrate microgravity (MGR) and vertical electrical sounding (VES). A pilot study of the Dukhan seismic data demonstrates that integration of MGR/VES into prestack depth migration (PSDM) improves the fidelity of seismic images and results in an improved depth match. The resultant MGR/VES PSDM pilot model improved the velocity model between the surface and top Simsima formation on the basis of visible impact on the deeper structure obtained from imaging and better fit between the seismic depth horizons and well measured depths.
Introduction
The Dukhan field (Fig. 1) along the southwest coast of Qatar is an elongated anticline that has significant hydrocarbon reservoirs in the Jurassic Arab and deeper formations. In 2007, Qatar Petroleum invested in a new full-field, land and shallow-water 3D-seismic survey of the area.
Despite considerable and continuous progress in seismic technology, obtaining an accurate, quantitative, well-focused seismic depth image at reservoir level remains challenging. In land seismic, a poor characterization of the near-surface geology is detrimental to the depth imaging of underlying structures. The proper knowledge of the near surface to correct for its perturbations onto the seismic wavefield remains one of the main challenges to be addressed. The near surface influences the kinematics as well as the dynamics of the source-generated seismic waves. Knowledge of the near surface to correct for its induced distortions is critical for a reliable use of seismic images, structures, and amplitude at reservoir level. The near-surface lateral and vertical velocity variations often are not accessible with seismic methods, even to the seismic refraction survey, because their depth of investigation is limited to the top of the shallowest hard layer. In addition, rapid lateral changes and large velocity contrasts are unfavorable to seismic refraction.
Broadband Seismic Acquisition: Implications for Interpretation and Reservoir Models
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18075, “The Impact of Broadband Seismic Acquisition and Implications for Interpretation and Reservoir-Model Building,” by Carter Gehman and Andrew Spedding, Hess, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed.
This paper addresses the impact of acquiring a new 3D broadband seismic survey over an amplitude-supported, discovered gas field containing legacy 3D conventional towed-streamer seismic data. The new seismic data were acquired in shallow water depths by use of a dual-level streamer technique and were processed through prestack depth migration (PSDM). Five gas discovery/ appraisal wells existed before broadband acquisition, and two wells were drilled after acquisition was completed. These seven wells serve as control points that provide a valuable link between the seismic and reservoir properties.
Introduction and Background
Seismic imaging of hydrocarbon reservoirs with small impedance contrasts relative to bounding lithologies is challenging. Ideally, an infinite bandwidth wavelet would detect and resolve subsurface geology as observed in the resolution of a typical wireline log. Improvements in seismic acquisition and processing continue to strive toward this ideal condition, and recent advancements in seismic acquisition— namely, the broadband acquisition technique—have attempted an approximation of the infinite bandwidth wavelet through the removal of the receiver or source ghosts. This advancement is of particular interest in oil and gas development areas where known thin or poor-quality reservoirs that are difficult to detect on conventional seismic records have been penetrated by previous wells.
The study area is located in the shallow (less than 200 ft) waters off peninsular Malaysia. Seven exploration and appraisal wells have targeted shallow and deep reservoirs, although only three wells have been drilled to deep targets. Generally speaking, seismic imaging of shallow reservoirs is good, while deep targets are more challenging to image.
The primary motivation for acquiring a new broadband seismic survey stemmed from imaging difficulties of thin (less than 15 ft) deep gas reservoirs on conventional seismic data. Many of these reservoirs are vertically juxtaposed by coals, which tend to mask the acoustic response of the reservoir. Even after later reprocessing of legacy data through anisotropic PSDM, imaging difficulties remained.
Guest Editorial: Changing How We Manage HSE: Getting to Zero
Authors: Hinton Jack 
Published: January 2017

Guest editorial
For the more than 7 billion people on our planet, every measure of quality of life, from gross domestic product per capita and infant mortality, to education levels and access to clean water, is correlated to the consumption of modern fuels, including oil and gas. Now more than ever, our industry faces imperatives: delivering affordable energy more safely, economically, and sustainably—that is, in a way that responsibly meets the needs of today’s populations without jeopardizing the Earth or its future populations. Sustainability will depend on continuing to close gaps, not only in technology, but also in health, safety, and environmental (HSE) performance, to eradicate HSE incidents from our operations. The expectation is a future with an incident-free workplace and where everyone returns home safely each day. Closing the HSE gap will require major shifts in cultural, organizational, and human performance paradigms.
Changing the Culture
For years, HSE was seen as a regulatory obligation to meet government requirements. It was governed by, and managed in reaction to, rules and regulations. Control and discipline were prevalent. An incident-free workplace was generally not considered possible, and when it was considered, it was only as a vision, at best.
Over time, industry HSE culture began to shift from dependent to independent as the process and complexity of operations became better understood, and commitment to safety became more personal and individual. An incident-free workplace began to be seen as a possibility, but still as a target to achieve rather than a realistic goal.
A further evolution from an independent to an interdependent safety culture took place over the first decade of the 21st century, with a stronger focus on cooperation within and across teams. Employees and well and asset team members began to see themselves as their peers’ keepers. HSE became recognized as “the right thing to do” for two very important reasons.
1. It is part of our moral and ethical responsibility to our employees, customers, contractors, and the communities in which we work, and to the future of our planet.
2. It is good for business. There is no downside to good HSE practices. Conversely, the cost of poor practices can drive companies out of business.
Bayesian-Style History Matching: Another Way To Underestimate Forecast Uncertainty?
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175121, “Bayesian-Style History Matching: Another Way To Underestimate Forecast Uncertainty?” by Jeroen C. Vink, Guohua Gao, and Chaohui Chen, Shell, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
Current theoretical formulations of assisted-history-matching (AHM) problems within the Bayesian framework [e.g., ensemble-Kalmanfilter (EnKF) and randomized-maximum- likelihood (RML) problems] are typically based on the assumption that simulation models can reproduce field data accurately within the measurement error. However, this assumption does not hold for AHM problems of real assets. This paper critically investigates the impact of using realistic, inaccurate simulation models. In particular, it demonstrates the risk of underestimating uncertainty when conditioning real-life models to large numbers of field data.
Introduction
Improved simulation and history-matching techniques have still not cured the chronic ailment of systematically underestimating uncertainty in forecast results. This is because it is very easy to forget or ignore uncertain factors or model assumptions; also, the method used to constrain a model to historical data may excessively reduce uncertainties.
In this paper, the authors highlight the fact that stochastic, Bayesian-style history-matching methods can very easily lead to unrealistically reduced uncertainty ranges in forecast results. The complete paper discusses Bayesian-style history matching and uncertainty quantification in detail.
Large-Data Danger
Stochastic history matching has two contrasting stages. First, one identifies a large number of uncertain model parameters in order to be confident that future field-production results will be contained within the range of forecast results associated with the prior model uncertainty. Second, when actual field data have become available, one uses large quantities of data to reduce this prior uncertainty. The reservoir engineer must decide not only which model parameters and field data to use, but also how many. The effect of increasing the number of uncertain model parameters is intuitively clear: Every parameter that has an impact on a specific forecast result will add to the uncertainty of this result.
Guest Editorial: Creating Value From Flared Natural Gas
Authors: Layfield Martin 
Published: January 2017

Guest editorial
Approximately 5% of world annual gas production is being flared or vented. This is equivalent to approximately 110–140 billion m3 (Bcm) of gas, and equates to the combined gas consumption of Central and South America in 2013.
The World Bank estimates that flaring 140 Bcm would cause more than 350 million tonnes of CO2 release into the atmosphere. If this could be harnessed for power, for example, it could produce 750 billion kW-hr/year, more than Africa’s entire annual consumption.
Capturing the flared or vented gas presents an opportunity for operators to reduce the environmental impact as well as provide an economic opportunity to generate an additional revenue stream. The World Bank’s “Zero Routine Flaring by 2030” initiative is calling on governments and companies to achieve this target within the next 15 years. To address both the need to end routine gas flaring and tackle climate change concerns, DNV GL has conducted research titled “Natural Gas Capture - Clean and Economic,” which examines the viability of alternative solutions and their revenue potential.
The conceptual study looked at four existing oil and gas facilities, onshore in North Dakota, Algeria, and Russia, and offshore Vietnam, which provided a variety of volumes and rates of gas being flared. This enabled the modeling of a range of diverse technologies on real locations and field conditions as most flaring occurs at either aging and/ or remote locations.
Understanding the Challenges
A number of factors can affect the drive and desire to undertake a reduction in gas flaring. Existing solutions are mature for large-scale applications, but fewer technologies have been used commercially at a small scale. This is perhaps due to uncertainty in the industry about the technical and economic viability of capturing the gas at these levels.
Retrofits and transportation of recovered gas to processing facilities can be costly. Without a global cost penalty for emitted carbon there is seen to be little benefit to capture the flared gas, particularly in countries with developing economies. Similarly, different geographies conjure various technical, regulatory, and economic drivers and limitations. Access to funding to develop projects and the implementation of technologies is also a major factor.
Where there are carbon emissions regulations in place, there is obviously more incentive to capture the waste from gas flaring. In the US, there are limits in place for gas flaring that penalize operators through the curtailment of production for missing targets. As a result, new technologies are emerging with a variety of solutions. Since issuing its research, DNV GL has had a number of companies approach for assistance with the qualification process to help establish technologies in the market. The North Dakota Petroleum Council has set targets to reduce flaring. These were set to 26% by the fourth quarter of 2014, 23% by the first quarter of 2015, 15% by the first quarter of 2016, and 10% with the potential for 5% by the fourth quarter of 2020.
Improving People’s Lives: #SPECares
Authors: Meehan Nathan 
Published: January 2017

President's column
Wealth is not new. Neither is charity. But the idea of using private wealth imaginatively, constructively, and systematically to attack the fundamental problems of mankind is new.—John Gardner
Historical philanthropy was primarily driven by religious convictions or the desire to remain in power. Around the time of John D. Rockefeller, something remarkable occurred as the great wealth created by industrialization ushered in a different sort of giving, targeted at improving people’s lives. Rockefeller started as an office clerk at age 16, creating his own firm 4 years later. His success in building Standard Oil was unprecedented—the firm would eventually be broken up into more than 30 individual companies that would grow to become Exxon, Mobil, Amoco, Sohio, and others. He gave away most of his wealth, founding the University of Chicago and Rockefeller University, but much of the giving was targeted at achieving specific goals. One example was focusing on eradicating hookworm disease across the southern US. Oil industry leaders have a long tradition of philanthropy, just one more way our industry serves the public good.
SPE has set aside a modest amount of money for disaster relief in areas where our members reside. To date, we have contributed more than USD 100,000 to various efforts including USD 10,000 each to relief efforts following this year’s 7.8 magnitude earthquake in Ecuador and the Fort McMurray wildfires in Alberta and Saskatchewan, Canada.
Most of us donate to charities according both to our abilities to do so and our convictions. One of the things I have been most pleased to see is not the donation of money, but the time and energy SPE members have contributed to charitable causes. I joined SPE in 1975 and one of the first activities I participated in was a section activity to raise money for scholarships, one of the most common areas for giving. SPE members have often been ready to volunteer for many efforts designed to benefit the public or deserving individuals or groups. I am thrilled to see sections and chapters around the world contributing their time and efforts to a wide variety of activities.
In June, the SPE Board of Directors adopted “SPE Cares” as the name for global SPE volunteer initiatives, thereby promoting community service worldwide while bringing together students and young and experienced professionals. We can shed a positive light in the oil and gas industry and make a difference in our community outside our careers.
Interview with 2017 SPE President Janeen Judah
Authors: Judah Janeen 
Published: January 2017

What will be your main goals as SPE president?
I have four goals in mind.
Guiding SPE through rough seas. My No. 1 goal is to keep SPE on an even keel. It sounds boring and un-ambitious, but we are sailing through rough seas right now. I’ve had people laugh and tell me I picked a great year to be president. I didn’t exactly pick it, but I am one of the best qualified to lead SPE in hard times because I have been so involved in leadership for such a long time. I was vice president of finance on the SPE Board of Directors, director representative of the Gulf Coast North America Region, and chaired both the Gulf Coast and Permian Basin sections. That experience brings a lot to the table when it comes time to make difficult decisions. For a steady hand on the wheel, I am a good person for managing in difficult times.
Developing engineers. During my term, you will see an emphasis on people capabilities as part of the Big Crew Change, particularly in developing countries. There is a significant push from governments for operators to develop local staff, and SPE can be part of the solution. I also have a personal soft spot for Latin America, and I am going to try to spend quality time there.
Reaching out to women. Another obvious outreach will be to women. I am the first female SPE president in more than a decade, so the latest generation has not seen a woman at the top. Young women in SPE look to me to be an example, so I will make myself accessible and visible to them. I realized years ago that I am an example whether I want to be or not, so I might as well step into those shoes. There are still very few women engineers in the industry—most women in leadership have a geoscience background.
Protecting the environment. I also want to emphasize environmental protection through responsible operations. I previously ran Chevron’s Environmental Management Company. We did offshore decommissioning, pipeline removal, handled all the Superfund sites for the company, orphan gas stations, any kind of end-of-life reclamation and dealing with regulators. The issue is doing things right as you operate and setting up your operation with the knowledge that someday you may have to leave there. I have a JPT column already planned for environmental stewardship, so look forward to more on that.