bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coalbed Methane Development in China: Challenges and Opportunities
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186289, “Coalbed Methane Development in China: Engineering Challenges and Opportunities,” by Hangyu Li, Shell; Hon Chung Lau, National University of Singapore; and Shan Huang, Shell, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.
For more than a decade, coalbed methane (CBM) has been developed commercially in China, but results have not met expectations. For instance, in 2015, annual CBM production in China totaled less than 5 billion m3 (Bcm) and lagged far behind that of the US (35 Bcm) and Australia (18 Bcm). This paper presents a literature review to determine the engineering challenges and opportunities presented by CBM production in China.
Introduction
China holds the world’s third-largest CBM resources after Russia and Canada. China has multiple basins that contain CBM resources, though the majority of CBM activities are found in the Qinshui and Ordos basins. Together, these two basins contain more than 30% of China’s total CBM resource volume and 93% of discovered geological reserves.
Commercial-scale CBM production in China began in 2004 but did not see a significant increase until 2008. Since then, production has increased approximately threefold but remains significantly lower than that of the US and Australia, as well as the target set by the Chinese government.
China’s lower CBM production is not the result of a smaller development scale compared with those of the US and Australia. In fact, the Qinshui basin alone contains more CBM-producing wells than does the entire state of Queensland. The lower production is, instead, the result of very low single-well gas rates. US and Australian basins have much higher single-well rates than do the Qinshui and Ordos basins. Understanding and identifying additional factors contributing to the unsatisfactory performance of CBM production, however, also is of critical importance.
Coal Characteristics
of the CBM Basins in China Most of China’s CBM development focuses on high-rank (Qinshui) and mid-high-rank (Ordos) coals. It is worth noting that, although there is abundant low-rank coal in the Ordos basin, the large-scale CBM development is found in the eastern part of the basin, where mid- to high-rank coals dominate. The problem with high-rank coals, however, is that they generally have lower permeability than low-rank coals. The highest permeabilities in either the Qinshui or Ordos basins are hardly higher than 10 md, with a large portion less than 0.1 md, while permeabilities in US basins can be 1000 md, with the majority higher than 10 md. Similarly, Australian basins are much more permeable than Chinese basins. The very low coal-seam permeabilities in the Qinshui and Ordos basins suggest that the low single-well gas rate can be attributed largely to low permeability.
CO2-Foam Field Pilot Test in a Sandstone Reservoir
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190312, “CO2-Foam Field Pilot Test in Sandstone Reservoir: Complete Analysis of Foam-Pilot Response,” by P.D. Patil, T. Knight, A. Katiyar, SPE, and P. Vanderwal, The Dow Chemical Company; J. Scherlin, SPE, Fleur De Lis Energy; P. Rozowski, SPE, The Dow Chemical Company; M. Ibrahim and G.B. Sridhar, SPE, Schlumberger; and Q.P. Nguyen, SPE, The University of Texas at Austin, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed.
This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. The pilot was successful in demonstrating deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. A 22% decrease in the amount of CO2 injected also was realized as a result of better use of CO2 compared with the baseline.
Introduction
Foam-assisted CO2 enhanced oil recovery (EOR), commonly referred to as CO2-foam EOR, has been proposed as an effective technology for correcting sweep inefficiencies caused by gravity segregation and reservoir heterogeneity. The central concept of CO2-foam EOR is the in- situ generation of a viscous emulsion of CO2 and water stabilized by a surfactant at reservoir conditions. Because the apparent viscosity of a CO2/water/surfactant system is much higher than that of CO2 itself, the mobility of CO2 is significantly reduced. In the reservoir, the generation of foam occurs first in the zones preferentially swept by CO2, gradually diverting CO2 to unswept zones where oil saturation is typically higher. An important feature of the CO2 foam is that the foam strength, and hence the mobility reduction, weakens in the zones where there is substantial oil saturation. As a result, the foam does not interfere with the CO2 displacement process once the CO2 is diverted into zones with substantial oil saturation.
Salt Creek Foam Pilot
Although the CO2 flood in the Salt Creek Field, begun in 2004, has been very successful, certain isolated patterns were seen to exhibit high CO2 production and inefficient CO2 use, most likely because of the channeling of fluids through high-permeability, low-volume zones and the gravity override of the injected fluid. A CO2-foam pilot was undertaken to test whether these conditions could be remediated.
An inverted-five-spot pattern in the Phase V area of the field was screened as the best candidate for the CO2-foam EOR pilot (Fig. 1). The pilot injector was labeled as 22SE30 and the four production wells to be monitored were wells 15SE30, 14SE30, 26SE30, and 28SE30.
While other papers have been devoted to the Salt Creek foam pilot, this paper focuses on the injection-well response, the interwell tracer analysis, and the production response from the monitored producer wells in the pilot area. The authors discuss the injection and production responses for 2 years and 8 months of data. The foam injection in the field was completed in June 2016.
Comments: The Golden Age of Gas Revisited
Authors: Donnelly John 
Published: October 2018

Editor's column
Seven years ago, the International Energy Agency (IEA) issued a report on the prospects of natural gas titled, Are We Entering the Golden Age of Gas? The answer appears to be not yet, but the growth in supply and trade, and moves to de-link the price of gas from the price of oil could propel the cleanest-burning hydrocarbon forward as the fuel to the future.
Gas supplies are plentiful and exports are surging. Most of this is due to the growth of shale in the US, which has led the country to become a major exporter of liquefied natural gas (LNG) along with Australia. Just as the US shale revolution disrupted the global oil market, it is reshaping the world’s gas trade. The US produced 71.1 Bcf/d of gas in 2017, a 1% increase over the previous year and near its all-time high. US output is now 20% of global production. Russia, the world’s second-largest gas producer, reached output of 61.5 Bcf/d last year. US gas exports, in the form of LNG and mostly to Asia, were 1.7 Bcf/d in 2017, while pipeline exports totaled 6.3 Bcf/d, mostly to Mexico.
What has hampered the international growth of gas in the past is its lack of tradability and its relation to a global price marker. Gas has long been linked to oil prices—which have shown sharp volatility the past decade—and tied to long-term contracts, both of which contain risks for both buyers and sellers. But the increase of LNG exports has opened the door to more international trade and discussion of establishing global price markers. Companies are increasingly using US Henry Hub prices as a reference point for international gas trade. And CME Group and Cheniere Energy are developing an LNG futures contract linked to physical delivery at Cheniere’s Sabine Pass, Texas terminal.
Before now, gas has been traded regionally or through long-term contracts based on the price of oil. US gas was priced off Henry Hub but trade in Europe used a regional trading hub and Asia, one of the largest importers of gas, preferred contracts linked to crude. De-linking the price of gas from oil would protect buyers and sellers from price movements in oil that do not reflect gas market fundamentals. That stability could give rise to more investment in gas production and infrastructure.
Gas proponents argue that gas should be the bridge to the future, as the world transitions from one based heavily on oil to a global energy mix that includes more alternative energy sources. China is relying more on gas as it weans itself from heavy coal use.
Major gas producing countries—including Iraq, Russia, Qatar, and Venezuela—have discussed forming a gas-type OPEC organization to create market stability. This Gas Exporting Countries Forum’s goal is to increase the share of gas in the global energy supply. These producers so far appear reluctant to embrace the free-market approach that growth in LNG is bringing about. But, as the IEA recently pointed out, half of the global consumption increase in gas in the medium term will come from emerging economies in Asia. And they stand to benefit most from market-based natural gas pricing.
Call for More Technology Gains Dominates Unconventionals Conference
Authors: Jacobs Trent , Zborowski Matt , Rassenfoss Stephen 
Published: October 2018

In the oil and gas industry, downturns are first met with extreme and widespread pain. But then the industry tends to turn to new technologies, the adoption of which eventually becomes so significant that it changes the makeup of the entire business.
This metamorphic change was on display at the 2018 Unconventional Resources Technology Conference (URTeC) in Houston, where digital technologies and their role in improving economics dominated the discussion. On the exhibition floor and in technical sessions, it was clear that analytics and machine learning tools are enjoying greater uptake and delivering early wins—yet, there remain a number of kinks to work out. Here are some highlights that capture the shale sector’s views on how its digital transformation is shaping up.

Pioneer’s Analytics Project Reveals the Good and Bad of Machine Learning
Trent Jacobs, JPT Digital Editor
Machine learning is supposed to help the oil and gas industry discover the important insights that human engineers keep missing. However, a recent project by Pioneer Natural Resources shows that engineers do indeed know their stuff and, while the machines are powerful and full of potential, they still need to get smarter.

Big Leaps Still To Come in Unconventional Technology
Matt Zborowski, Technology Writer
Today’s advancements in unconventional technology are worth marveling over, but there is still plenty of room for growth, a panel of industry leaders agreed at the Unconventional Resources Technology Conference (URTeC).
“There are certain times in the history of the industry when technology proceeds at such a fast pace, you would describe it as revolutionary. We are living in one of those times,” said Greg Leveille, ConocoPhillips chief technology officer.

In the Shale Business, It’s Time for Another Revolution
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
The report card for unconventional oil and gas producers from a leading industry analyst is A+ for growth and F- for paying back investors.
But Bob Brackett, senior analyst for Sanford C. Bernstein & Co., who created the report card, said he is seeing signs of change.
On the production side, the industry is struggling to keep up with the Permian Basin because output is exceeding available pipeline capacity. On the supply side, the industry may be moving away from pushing production so hard it drives down prices to levels where no one can make money.
Technology Focus: Completions (September 2018)
Authors: Lehr Doug 
Published: October 2018

Technology Focus
I am very excited to begin my term as editorial reviewer for Completions. JPT has always been the source of cutting-edge information on industry technology developments, and I pledge to continue that tradition through expert review and selection of papers.
Our industry is showing signs of emerging from the recent downturn, and commodity prices are improving slowly. There is intense focus across the industry on profitability in the current low-oil-price environment, and profitability must be achieved while (a) meeting regulatory requirements, (b) delivering value to stakeholders, and (c) attracting and retaining the best talent available. Yet, today’s profitability is not the only challenge. Laying the groundwork for future profitability also must occur.
One of the more powerful tools available to help achieve sustained profitability is innovation, and it has consistently generated cutting-edge technologies that have advanced the oil and gas industry.
The good news is that innovation has continued during the downturn. For example, advancements in dissolvable-materials technology and downhole data acquisition have continued. While the former primarily advances efficiency in multizone shale well completions, the latter will advance effectiveness in both land and offshore completions. Process innovation is also occurring and is evident in the drive to create advanced numerical models for optimization of stimulation and hardware choices in multizone shale well completions. Finally, increased focus on reliability in design, installation, and operation has emerged as both operators and suppliers recognize the contribution of risk management to completion technology and systems.
The papers presented in this month’s Completions feature are great examples of how innovation is driving profitability, and I hope that they help you drive profitability in your completions.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 188729 Laser Perforation: Laboratory to Field by Sameeh I. Batarseh, Saudi Aramco, et al.
SPE 187353 Best Practices for Sustained Well Productivity: A Look Back in to Frac-Pack Completions by Mark Knobles, Chevron, et al.
SPE 187185 On/Off ICD Well-Performance Assessment Below an ESP Using Intelligent Chemical Inflow Tracer Technology in a Brownfield in Kuwait by M.A. Siddiqui, KOC, et al.
Technology Focus: Oilfield Chemistry (September 2018)
Authors: Wylde Jonathan 
Published: October 2018

Technology Focus
The last 3 years have seen an unprecedented increase in paraffin-related challenges in the world of production chemistry. The industry is producing more-challenging crude oil as the production of light, sweet, and easy-to-treat crude declines. The new crudes coming on stream contain more-complex combinations of paraffinic components.
We are aware of the bimodal distribution of paraffin displayed nicely in high-temperature gas chromatography of, for example, Eagle Ford crude oil, which shows a double peak distribution of paraffin. Some of the more-recent publications highlighted are using more-advanced analytical techniques to characterize crude oil because heavier paraffin components are not detectable by classical methods. Characterization using techniques such as nuclear magnetic resonance and matrix-assisted laser desorption/ionization time-of-flight mass spectrometry are detecting paraffin chains in excess of C100 and determining a trimodal distribution of paraffin in crude oil that is difficult to treat using today’s technology, thus requiring a change in approach and thinking for the production chemist. Such crudes are being developed today—crude oils from some of the more extreme shale plays around the world such as the Montney formation in British Colombia, Canada; Vaca Muerta in Argentina; East African crude oils of Uganda, Chad, and Kenya; and crude oils in the Far East such as those in Indonesia and Vietnam.
The current chemical technology begins to reach its limit of functionality in a crude oil that contains paraffin chains of C75+ in length. The featured papers give some insights into the work under way to elucidate the structure performance relationships between inhibitors and crude oils containing these higher paraffinic species. Much work remains in order to develop more-effective solutions and strategies for these incredibly challenging and highly paraffinic crude oils.
The featured papers summarize some of the state-of-the-art techniques to determine the true nature of paraffin deposition from these bi- and trimodal crude oils as well as advanced techniques to truly characterize and treat produced fluids and recovered solids samples. Readers are encouraged to research the recommended additional reading and take some time to delve into the references contained in these papers. This literature contains an extensive review of the history and current state of the art in paraffin science for the oilfield chemist and engineer.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 27855 Work Flow To Evaluate Wax-Deposition Risk Along Subsea Production Systems by O. Coronado, Genesis, et al.
OTC 28714 Cold-Finger Benchmarking Study for Paraffin-Inhibitor Selection by Yun Peng, Shell, et al.
SPE 187252 Investigating the Performance of Paraffin Inhibitors Under Different Operating Conditions by Anshul Dubey, The University of Tulsa, et al.
It May Be Boom Time for the Oil-Rich Powder River Basin
Authors: Zborowski Matt 
Published: October 2018

Years in the making, the recent steady rise in drilling in the Powder River Basin of northeast Wyoming is generating excitement reminiscent of the early days of currently more-established US onshore oil plays.
The upturn in activity is resulting in double-digit production growth. Wells are bubbling over with oil, and operators are bubbling over with enthusiasm. This has been most evident in recent industry presentations, where decision makers from the basin’s exclusive club of operators have gushed over what is becoming a core asset in their portfolios.
Given the basin’s oil richness, multiple stacked horizons, and well performance and economics, “we think it’s comparable and competitive with the big-name basins—whether it’s the Permian, SCOOP, or STACK,” Joseph DeDominic, president and chief operating officer of Anschutz Exploration, said at a recent SPE Gulf Coast Section meeting on the basin.
“This is what really gets us excited—the fact that you have 5,000 ft of stacked pay which is very similar to what you see in the other basins,” generating a high-dollar amount per acre, said Aaron Ketter, vice president of Devon’s Rockies business unit, during the same event. Formations are “highly economical” at $50/bbl and under, he said, with the heart of the Turner zone sometimes breaking even in the high $30s/bbl.
Traditionally known for its prolific coal production, the Powder River Basin’s potential for oil became a stronger point of focus in the industry about a decade ago. Operators began moving in on the region, rigs in tow, collecting limited but valuable data on its formations. When the commodity price downturn struck the industry during 2014–2016, operators pulled back investment, resulting in the basin’s failure to launch.
In its current state as an oil play, the basin is still underdeveloped. While lots of vertical wells have been drilled there in the past, “the truth is, when you look at horizontal development, and even using modern completions, it’s really brand new. We’re just getting started,” said Joseph A. Mills, Samson Resources II president and chief executive officer. “Delineation is what’s happening today and that’s probably what’s going to go on for another couple of years.”
Companies that are now ahead of the curve arrived early in the basin, secured operatorships, began drilling years ago, held onto their acreage—and its accompanying data—through the downturn, and patiently waited for oil prices to rise and costs to fall.
“What’s unique about the Powder is just the areal extent of some of these zones aren’t the same magnitude as you see in the Permian or the Midcontinent. So zip code really matters,” said Ketter.
Current Lay of the Land
Devon, Anschutz, and EOG Resources have the largest positions in the Powder River at around 400,000 net acres each. Chesapeake Energy and Anadarko Petroleum each has around 300,000 net acres, with the latter firm having just spent some $100 million to expand its position.
Now There’s Enough Pressure Pumping and Sand To Go Around
Authors: Zborowski Matt 
Published: October 2018

Operators fracturing wells in the US shale basins are enjoying a steady supply of reasonably priced pressure pumping services and sand.
After the market struggled to keep pace with demand after the downturn, pressure pumpers are deploying enough horsepower to satiate operators and their ambitious production targets, according to data from Rystad Energy. Fracturing work is being augmented by the proliferation of in-basin sand mines, which provide operators a more convenient, less expensive source of proppant during frac jobs.
This comes as the consultancy forecasts the number of horizontal wells fractured to rise 32% in 2018 and 13% in 2019. Total frac stages are projected to increase 37% in 2018 and 16% in 2019. These numbers are based on projected oil prices of around $69/bbl in 2018 and above $70/bbl through 2021.
Demand for pressure pumping horsepower is expected to jump 4 million hp this year to 17 million hp, more than double the 2016 level. Demand is expected to grow 2 million hp in 2019 and another 4 million hp in 2020 to 23 million hp, where it will remain flat in 2021.
On the supply side, horsepower is expected to increase by 4.8 million in 2018, more than meeting demand. Growth will halve to 2.4 million hp in 2019 and then spike to 5.1 million in 2020. The increase next year will primarily serve to fulfill “skyrocketing” demand in the Midcontinent and Haynesville regions, said Ryan Carbrey, Rystad senior vice president, shale research, during a frac market webcast. As of mid-2018, all horsepower that was previously available for refurbishment has been refurbished, Carbrey said, meaning only new horsepower will be added to the field going forward. The overall increased supply—from both refurbished units and newbuilds—has stabilized the market, and price increases aren’t expected through late 2018 or early 2019.
However, some operators aren’t pleased with the work they’re seeing, Rystad has observed. A vice president of one exploration and production (E&P) firm told the consultancy, “Some of these companies grew too fast and the quality of their crews reflect that—too many new guys that don’t know what they’re doing yet.”
Meanwhile, pumping intensity growth, which has increased rapidly since the downturn, is forecast to decline in the coming years “as we believe a lot of the gains from increasing horsepower hours have already been realized,” said Carbrey.
A measure of that intensity, horsepower-hours per horizontal well, are expected to increase by an average of just 2% per year between 2017 and 2021 after an average 29% per year between 2013 and 2017.