bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 The paper has not been peer reviewed.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.