Oil Price Crash Research Articles

Technology Focus: Deepwater Fields (May 2019)

Technology Focus Deepwater capital expenditure has nose-dived since the oil-price crash of 2014 and has not quite recovered because of the high level of breakeven prices required, but some oil companies maintained their interest in the sector and went ahead with big-ticket projects anyway. Most believe the sector has bottomed out. Brazil’s presalt region is among the areas driving deepwater oil and gas development, while others struggle with costs and technical complexity. So, in a low-oil-price environment, are such deepwater projects viable? The major players in the deepwater market have made significant efforts to minimize costs and increase efficiency, thus shaping 2019 capital budgets. That means activity levels in 2019 likely will mimic those of 2017–18, with perhaps some small gains from small operators taking advantages and looking for opportunities in the current low-cost environment. However, the situation is darkened by global market pessimism. Adding to this, operator project-execution decisions have been delayed and lack of commitment and direction has caused operators to delay deepwater projects and leave the pipeline of future work empty. Even if operators do make decisions in late 2019 to go forward with these projects, the projects are unlikely to commence until late 2020 or even 2021. Royal Dutch Shell is considering only the Gulf of Mexico in their strategic deepwater development going forward to 2020 and beyond, and, despite low oil prices, Shell is advancing its Kaikias, Appomattox, and Coulomb Phase 2 projects in the deepwater Gulf of Mexico, reducing break-even costs and cycle times. Through the forecast period, Africa and the Americas will continue to lead the deepwater market, accounting for 79% of forecast expenditure. Floating production, storage, and offloading vessels will continue to dominate the floating production and storage (FPS) market, with a total of 33 deepwater units (out of 41 FPS units in total) expected to be installed during the 2018–22 period, representing 78% of FPS expenditure. Recommended additional reading at OnePetro: www.onepetro.org. OTC 28872 Changing Landscape of Deepwater-Field Developments by Marcel M. Landwehr, Subsea 7, et al. OTC 29043 The Giant Lula Field: World’s Largest Oil Production in Ultradeep Water Under a Fast-Track Development by Marcelo Becher Rosa, Petrobras, et al. SPE 191960 Early-Stage Detection of Scales in a Deepwater Field Offshore Ghana Through Remote Monitoring of Multiphase Meter by Mahdi Darab, OneSubsea, et al.

Paradox of plenty: Norway’s macroeconomic policy dilemmas during the oil price crash, 2014-15

Norway, a country at the top of global rankings in terms of gross domestic product (GDP) per capita and human development was also in an enviable position with large current account and fiscal surpluses, as well as a massive stock of public assets. Then came a shock; between June 2014 and early 2016 oil prices tumbled by more than 70 percent. As a major oil exporter, Norway’s current account was severely impacted but could this actually draw Norway into a macroeconomic crisis? Couldn’t it just fund its way out of the contractionary pressures building up in the economy using its stock of foreign currency reserves being held in a sovereign wealth fund? This article explores the fiscal and monetary policy challenges that Norway faced in preempting falling GDP growth and rising unemployment while at the same time, warding off a housing bubble going bust.

Evaluating Algeria’s social and economic development using a series of night-time light images between 1992 to 2012

ABSTRACTAfter social and economic problems, Algeria regained its night-time light (NL) brightness as this analysis of space-borne images shows. We evaluate the advancement of artificial light sources and the socioeconomic development between 1992 to 2012 for all 48 provinces. Image calibration improved the consistency and comparability of the DMSP-OLS data. Light detected from gas flaring has been separated to focus on light from human settlements. We then estimated the relationship between night-time light and selected socioeconomic parameters (SEP). Night-time light growth (NLG) and night-time light annual growth (NLAG) indices are calculated at the national, regional and provincial level. Considering the Oil price crash and the Algerian Civil Concord, we take a detailed look at these historic events in Algeria. Our main findings are: (A) The total night-time light (TNL) for human settlements grew nationwide by 128%, (B) night-time light data correlates with socioeconomic parameters such as population, and electric power consumption, (C) the oil price crash resulted in slower night-time light growth, while the Algerian Civil Concord and the end of the crises led to increased TNL, (D) because of government investment, the High Plateaus are the fastest growing region since the end of the crises, (E) space-borne night-time light data can consistently fill the information gap when data from official sources are not available. Government and policy-making bodies may benefit from the presented findings allowing them to oversee and address provincial inequalities and economic development.

How Do Oil and Gas Investors Pick Entrepreneurs? Vice Versa?

Private equity and venture capital firms are just as important to the evolution of the oil and gas industry as the leading operators and service companies. This became evident during the oil price crash when public equity opportunities disappeared and lenders shied away from the industry amid scores of bankruptcies. Illustrating the point earlier this year was Wil VanLoh, founder and CEO of Quantum Energy Partners, who boasted during the NAPE Global Business Conference that his firm would “look really similar to a superindependent” if it were to aggregate all the companies in which it’s currently investing, which altogether tally 2.3 million net acres, 350,000 BOE/D, and 32 rigs working across the US and Canada. With the backing of private investment, entrepreneurs who previously worked for companies such as Shell, Anadarko, Halliburton, Baker Hughes, and even smaller, lesser known entities have applied their unique skills and ideas to find, develop, and produce the latest generation of prolific oil and gas fields quicker and with less money than ever before. But finding those innovators who are actually capable of turning their dreams into reality is difficult. And when you’re the firm tasked with bearing the financial risk that comes with backing fledgling companies that hope to break into an already volatile industry, you tend be choosy. Enter Charlie Leykum, founder of CSL Capital Management, a 10-year-old private equity firm that builds and acquires controlling interests in oil and gas service and equipment companies. It’s currently launching its $1.5-billion Fund III as well as a special-purpose acquisition company, which raises capital from public investors, enabling them to participate in private equity purchases. “So much of what we do is finding not just an individual or a group of individuals who are technically or commercially really savvy,” but finding a “harmonized, well-working team,” Leykum said during the SPE Gulf Coast Section’s recent Innovation Entrepreneurship Symposium. CSL only considers business plans where a team is either in place or assembling with “a subject matter expert who’s the key decision maker” as well as technical and operations personnel. Together, they must have a firm grasp of the challenges and risks involved in building a business. When looking at possible investments, CSL wants technical leadership in a market. When CSL invested in a fracturing company in the early 2000s that ended up successful, Leykum said, the firm partnered with a major service company’s “lead fracturing executive for the business line” whose skills and expertise could solve—and had solved—unique challenges in different basins.

Oil price and USD-Naira exchange rate crash: Can economic diversification save the Naira?

Naira lost half of its foreign exchange value in less than two years following 2014 oil price crash, and has not recovered despite numerous government's attempts. This study thus evaluated the potential of economic diversification (proxied by non-oil export performance) in saving the Naira by analysing a nexus between oil price, exchange rate and nonoil export. Estimation of a rearranged current account equation within Autoregressive Distributed Lag (ARDL) and Vector Autoregressive (VAR) models, using monthly data from January 2008 to December 2015 yielded the following results. There is a direct relationship between oil price and exchange rate, and this affirms that sharp decline in the former induced the latter's deterioration. Increase in non-oil exports led to appreciation of USD-Naira exchange rate both in the short run and the long run. Import, on the other hand, induced depreciation of the exchange rate in the long run. Diversification, by increasing export revenue and reducing import bills, therefore has a great potential to improve the value of Naira.

Dramatic Enrollment Shifts Plague Petroleum Engineering Programs

The sharp oil price volatility during 2014–16 is now being felt by US undergraduate petroleum engineering (PE) programs, where enrollment is in steep decline after hitting record highs at the onset of the price downturn. The number of US students pursuing bachelor’s degrees in PE programs fell to 6,263 in fall 2017 from 8,712 in fall 2016 as attitudes toward the discipline continued to shift, according to data compiled by Lloyd Heinze, PE professor at Texas Tech University’s Bob L. Herd Department of Petroleum Engineering. Enrollment in fall 2015 remained elevated at 11,069, slightly lower than a peak of 11,474 in fall 2014 when the oil price crash was under way—meaning it took 2 years before enrollment numbers began tracking oil prices. “Students are starting to realize the job market is very different from when they started out as freshmen,” said Heinze, who has followed PE enrollment trends for decades. A student who is slated to graduate with a BS in PE this spring, for example, likely enrolled in fall 2014 after West Texas Intermediate (WTI) prices had spent much of the year at more than $100/bbl. In their sophomore year, WTI cratered to $26/bbl before stabilizing in the $40-60/bbl range for their junior and senior years. With fewer students in the pipeline, fewer graduates are expected in the coming years, reversing an oversupply of those trying to enter the workforce. The number of undergraduate PE degrees granted is projected to plunge from more than 2,000 in each of 2015–16, 2016–17, and 2017–18 to around 1,220 in 2018–19 and 680 in 2019–20, Heinze’s data project. At 470 and 130, respectively, master’s degrees and PhDs granted are expected to remain somewhat elevated in 2017–18 compared with their averages during the previous decade. The steadier post-grad numbers may be supported in part by fewer available jobs. One Extreme to Another Heinze noted that Texas Tech’s PE department, like many PE departments across the country, is still reeling from the “tremendous overload” of students in recent years, a problem over which it had no control. “I can tell you that even if oil prices last year were $100/bbl, we were already on track to put out more students than $100/bbl can support.” Many public university PE programs are at the mercy of how many prospective students meet published admissions requirements. That is to say, programs cannot simply deny qualified students because those programs’ faculties, resources, and even lecture halls have become overextended. As a result, average undergraduate student-faculty ratios ballooned to about 46:1 in fall 2013.

A realistic and integrated model for evaluating oil sands development with Steam Assisted Gravity Drainage technology in Canada

Oil sands resource is the third largest oil reserve, and 70% of the oil sands are in Canada. The emerging of Steam Assisted Gravity Drainage technology has made the commercial development of oil sands economically feasible. However, with the recent oil price crash, the development of oil sands has faced an uphill battle. A realistic and integrated evaluation model is highly needed to overcome difficulties from the low oil price and provide meaningful and valuable information for operators as well as investors to make the right decision. The existing evaluation models have considerable limitations (i.e., the incapability of evaluating integrated oil sands development with Steam Assisted Gravity Drainage technology, the lack of investigation into the input parameters with historical data, and ignoring the effect of the subsurface reservoir, etc.). This study developed an integrated evaluation model through the analyses of a significant amount of actual historical data. This integrated model includes six subcomponent models, ranging from the subsurface reservoir to infield flowline. Data from 35 Canadian oil sands development with 15 internal and external parameters were collected and investigated. The oil price effect was analyzed and quantified through simulations. The breakeven Western Canada Select oil price of $39/bbl. (equal to the West Texas Intermediate oil price of $55/bbl.) and other key price points and distributions were identified. Also, the top seven geological and technical parameters that contribute 86% of the net present value variations were identified and investigated. These quantified effects of external and internal parameters are useful findings for decision making. Considering various price scenarios and uncertainties of the input parameters, this study has concluded that developing oil sands resources with the Steam Assisted Gravity Drainage technology is economically feasible and socially beneficial after we take all stakeholder interests into consideration, which is true even with the sustainable and realistic oil price in the foreseeable future.

Technology Focus: EOR Operations (June 2017)

Technology Focus When I started editing this section in 2015, the year after the oil-price crash, many industry commentators were predicting a strong recovery in oil price by now; instead, the concept of “lower for longer” has become the present reality. Now, many commentators expect a shortfall in supply by the mid-2020s and the effect of shorter-cycle shale oil developments to be just two of the factors affecting price in the future. Sometimes, I hear the view that, without high oil prices, enhanced oil recovery (EOR) does not have a place in the mix of projects delivering the new production needed over the next decade. However, high oil prices are not the whole story. High oil prices may cause an over-heated market that squeezes the value from EOR. By their nature, EOR projects are often longer-term investments, so investing in new EOR projects at a time when real-term costs are at their highest (pushed by the high oil price) may not be the best strategy. Significant progress in cost reduction has been made in the industry following the price downturn, not only in the direct cost of construction and operations but also through a determined drive to simplify and streamline new projects in concepts selected for facilities and wells. Through this competitive scoping, project economics can be improved to deliver more-robust investment opportunities. The discipline of a lower-for-longer world can create the conditions in which long-term investment decisions can be made. In the mix of new projects needed to fill any production shortfall in the coming decade, brownfield improved and enhanced oil recovery can compete with the alternatives available to the industry. SPE continues to play an important role in sharing best practices to allow the industry to reap the benefit of project learnings, and I hope you find that the selected papers and recommended reading provide useful insights. Recommended additional reading at OnePetro: www.onepetro.org. SPE 180755 Enhanced SAGD Startup Techniques for Improved Thermal Efficiency and Conformance—A Field-Test-Based Investigation by J.M. Dragani, Cenovus Energy, et al. SPE 180739 Results of a Polymer-Flooding Pilot in the Tambaredjo Heavy-Oil Field, Suriname by E. Delamaide, IFP Technologies, et al. SPE 183362 Successful Flood-Front and Breakthrough Prediction of Miscible WAG in a Complex Carbonate Reservoir—A Case Study by Z.U.R. Qureshi, ADCO, et al.

The impact of oil price changes on major US tight oil plays

ABSTRACTUS oil production for the last decade has been revolutionized by tight oil development activities around the country. The main oil plays contributing approximately 50% of the US total daily production are the Permian, Bakken, Eagle Ford, and Niobrara plays. Among the factors sustaining this tight oil revolution are advanced well positioning technology undergirded by high crude oil prices. Since the fourth quarter of 2014, oil prices have dropped from highs of $105/bbl observed in 2013 to lows of $28/bbl, leading to seismic shifts in activities across the oil plays. However, these impacts have not been uniform across all plays. This paper examines the varied impact of crude oil price fluctuations on the nation’s top tight oil plays. Using an autoregressive distributed lag (ARDL) approach, this study investigates the effects of oil prices and rig counts on oil production in these plays. The results show that oil price fluctuations affect all tight oil plays differently. Plays like the Permian show more resilience even amidst the oil price crash and plays like the Bakken are impacted in the short and long run by oil price fluctuations. This study also shows that the long-run impact of price fluctuations is not symmetrical and oil production increase caused by a rise in price is more sustained than production drops that follow price declines. In an era of lower oil prices, these insights become even more valuable to decision makers and operators who search for opportunities to stay profitable.

Australian exploration review 2016

In 2016, explorers in Australia were called upon to demonstrate realistic optimism. The year clearly demonstrated that during an industry contraction, such as that seen by the upstream oil and gas industry since the oil price crash of late 2014, near field conventional exploration still produces discoveries. These include Shefu, Muruk, Davis, Outtrim and Spartan. Amungee NW demonstrated unconventional gas flows in the Beetaloo Basin. As usual, new reservoirs were discovered in appraisal programs such as at Roc and Phoenix South. Exploration lows, however, were the general mood with the inevitable unsuccessful wells, decreases in permit awards and associated work programs, the general low level of drilling activity both offshore and onshore, frustrations at approval delays and constraints and the still contracting business environment. This Petroleum Exploration Society of Australia review looks in detail at the trends and highlights for oil and gas exploration both onshore and offshore Australia during 2016; not just outcomes with the drill bit, but also leading industry health indicators such as drilling, seismic data acquisition and permit awards. It also seeks to be insightful and to make conclusions about the condition of oil and gas exploration in Australia, as well as comment on future implications for the industry.

The oil price crash in 2014/15: Was there a (negative) financial bubble?

This paper suggests that there was a negative bubble in oil prices in 2014/15, which decreased them beyond the level justified by economic fundamentals. This proposition is corroborated by two sets of bubble detection strategies: the first set consists of tests for financial bubbles, while the second set consists of the log-periodic power law (LPPL) model for negative financial bubbles. Despite the methodological differences between these detection methods, they provided the same outcome: the oil price experienced a statistically significant negative financial bubble in the last months of 2014 and at the beginning of 2015. These results also hold after several robustness checks which consider the effect of conditional heteroskedasticity, model set-ups with additional restrictions, longer data samples, tests with lower frequency data and with an alternative proxy variable to measure the fundamental value of oil.

Comments: The Toll on Future Supply

Editor's column Low oil prices have taken a huge toll on exploration and production (E&P) activity, and the decline could lead to production shortfalls in the future. Discoveries of new reserves have now fallen to their lowest level in 60 years as projects are canceled or pushed back due to low prices and company budget and staff cuts. Operators discovered 2.8 billion bbl of crude oil and liquids last year, the lowest volume since 1954, according to a new report by consultancy IHS. Most of the reserves were found in deep water, which take years to bring on to production. Two other recent reports were much-discussed during last month’s Offshore Technology Conference in Houston. Global deepwater spending continues to fall because of the oil price crash, with the Americas and Africa the only bright spots, according to a new study by Douglas-Westwood. A year ago, the consultancy saw 210 potential projects for installation in the next 5 years but now expects only 118 projects to be installed during 2016–2020. E&P capital spending will be led by investments in the Americas and Africa, which combined will account for 87% of expenditures. The development of east Africa’s gas basins and several US Gulf of Mexico plays will keep those centers as deepwater hubs. The Gulf of Mexico projects include Shell’s Appomattox field, its largest floating platform offshore US; Anadarko’s subsea tiebacks at three fields; Chevron’s Jack/St. Malo floating production system; and BP’s Mad Dog phase 2 development. Wood Mackenzie is warning that the steep drop in production could lead to critical shortfalls in the future. It expects the industry to spend USD 40 billion/yr on exploration and appraisal from 2016 to 2018, less than half of what was spent during 2012–2014, and that number could be lower depending on what oil prices do. The consultancy sees a shift to smaller, near-field operations in the immediate future, with the industry eschewing high-dollar complex projects that potentially bring more lucrative output. Even many medium-term discoveries made before the price downfall are being delayed because of company budget cuts. Those factors contribute to its prediction that continued poor exploration results could lead to a 4.5-million-B/D shortfall in the industry meeting demand by 2035, although a lot of variables could change in 19 years. Consultancies are not the only ones worried about coming supply shortfalls. Schlumberger Chief Executive Officer Paal Kibsgaard, speaking to investors about the company’s first quarter earnings, said E&P investment likely will not meet future global energy demand unless something changes. “I think we will need significant increases in E&P investment,” he was quoted as saying. “If you look at new investments that are relatively short cycle, there are two sources of that. It is going to be the conventional land international and it is going to be the unconventional land in North America. …So I think the sources of additional production for 2017 are limited to these items. Beyond that, I think we need a widespread, significant increase in E&P investments to get supply back to where it can meet growing demand.” JPT

Unconventional Measures for Shale Reservoirs

Unconventional Measures for Shale Reservoirs

Regulating global shipping corporations' accountability for reducing greenhouse gas emissions in the seas

Up until the recent oil and commodity price crash in 2015, there has been exponential growth in global shipping and trade, and this increase means that prompt action is required to reduce vessel-sourced greenhouse gas (GHG) emissions. Future projections suggest that maritime CO2 emissions will increase substantially by between 50% and 250%. However, there is currently no international instrument holding global shipping corporations accountable for their vessels' performance in emissions reduction. This article critically assesses the current accountability practices and regulations in place for these corporations. It suggests that stakeholders in this industry need to further explore the market based mechanisms (MBMs) that can encourage and even demand that these corporations systematically disclose their vessels' emissions reduction performance in an accurate and timely manner. Developing such mechanisms is vital to assist in the reduction of GHG emissions since a comprehensive international instrument is unlikely to be implemented soon.

An Analysis of OPEC's Strategic Actions, US Shale Growth and the 2014 Oil Price Crash

In November 2014, OPEC announced a new strategy geared towards improving its market share. Oil-market analysts interpreted this as an attempt to squeeze higher-cost producers including US shale oil out of the market. Over the next year, crude oil prices crashed, with large repercussions for the global economy. We present a simple equilibrium model that explains the fundamental market factors that can rationalize such a regime switch by OPEC. These include: (i) the growth of US shale oil production; (ii) the slowdown of global oil demand; (iii) reduced cohesiveness of the OPEC cartel; (iv) production ramp-ups in other non-OPEC countries. We show that these qualitative predictions are broadly consistent with oil market developments during 2014-15. The model is calibrated to oil market data; it predicts accommodation up to 2014 and a market-share strategy thereafter, and explains large oil-price swings as well as realistically high levels of OPEC output.

An Analysis of OPEC's Strategic Actions, US Shale Growth and the 2014 Oil Price Crash

In November 2014, OPEC announced a new strategy geared towards improving its market share. Oil-market analysts interpreted this as an attempt to squeeze higher-cost producers including US shale oil out of the market. Over the next year, crude oil prices crashed, with large repercussions for the global economy. We present a simple equilibrium model that explains the fundamental market factors that can rationalize such a regime switch by OPEC. These include: (i) the growth of US shale oil production; (ii) the slowdown of global oil demand; (iii) reduced cohesiveness of the OPEC cartel; (iv) production ramp-ups in other non-OPEC countries. We show that these qualitative predictions are broadly consistent with oil market developments during 2014-15. The model is calibrated to oil market data; it predicts accommodation up to 2014 and a market-share strategy thereafter, and explains large oil-price swings as well as realistically high levels of OPEC output.

A clean fight: environmental management strategies to drive growth, efficiency and competition in CSG

During the past 12 months, operators in LNG–CSG have had little option but to purely focus on cost efficiencies to remain profitable after the oil price crash of 2014 (Macdonald-Smith, 2015). This is set to continue with oil hovering around the $40 per barrel price mark, and as more CSG projects transition into operations in the next five years, an alternative approach to operating must be explored to further promote competitiveness and long-term sustainability in this volatile market (Cassidy and Kosev, 2015). The purpose of this paper is to critically analyse an approach to CSG operations that considers environmental aspects as an effective alternative in addressing the range of operational challenges to improve economic outcomes for operators. Essentially, the approach highlights opportunities to improve yields and further reduce costs along the gas extraction/processing value chain while meeting the critical compliance checklist in CSG. This paper outlines the key hallmarks of an effective adaptive environmental management approach from well site to water treatment operations. It then turns to consider each of the key components that make up this approach, including the role of leadership, contracting strategies, asset management methodologies, treatment technologies, effective remediation and recovery management, and the benefits that efficient operations deliver to surrounding communities. This paper also examines key case studies that are delivering substantial savings for CSG operations in the Bowen and Surat basins. These case studies share a similar theme in their intention to generate and implement improvements in efficiency and value delivered by effective water and environmental management, each within their own context.

Oil Prices Shakes Central Banks of G7

Right now the oil price again ensures many headlines. The Bank of Canada became the first central bank in the Group of Seven to cut interest rates in response to plummeting oil prices, saying the shock will weigh on everything from inflation to business spending. U.S. banks are setting aside more money to cover bad loans to energy companies after oil prices plunged over the last year, raising the possibility that deteriorating loans could start to weigh on their earnings. The question now is: How will the price of oil continues to develop? There are several possibilities. The oil price crash is no longer just an oversupply, but could already signaling deflationary pressure. How was the development in the past year? What is the outlook?

Sources of volatility during four oil price crashes

Previous sharp oil price declines have been accompanied by elevated ex-post volatility. In contrast, volatility was much less elevated during the oil price crash in 2014/15. We provide evidence that oil prices declined in a relatively measured manner during 2014/15, with a dispersion of price changes that was considerably smaller than comparable oil price declines. This finding is robust to using both descriptive and GARCH measures of volatility. Further, the US dollar appreciation exerted a strong influence on volatility during the recent crash; in contrast, the impact of equity market shocks was muted.

Rethinking Proppant: From Liquid to Solid

Propping open fractures to maximize production requires placing enough stout particles of sand or ceramic in a fracture to hold it open for years. The downside of bigger and stronger particles is that they are denser than the fluid used to deliver them, so some will settle in transit. It is also difficult to move proppant past the corners in networks of fractures. The end result is only a limited area gets well propped. There has been a long line of methods offered to deliver more proppant deeper—lighter particles, viscous fluids, and coatings that limit settling. The SPE Hydraulic Fracturing Technology Conference has become a showcase for new ideas. The most striking innovation presented at the March conference in The Woodlands, Texas, was from Oil Chem Technologies, which reported patenting a chemical combination designed to flow into a reservoir as a liquid, which then turns into strong, spherical balls able to hold open a fracture. Saudi Aramco has invested in this innovation and is working with the Houston-area company to measure its properties, with a goal of field testing it later this year, said Paul Berger, vice president and technical director for Oil Chem. “The goal of this technology development is to convert injected fracturing fluid into a highly permeable proppant pack in-situ,” according to the paper he presented at the conference (SPE 173328). “Since the fracturing fluid itself forms the proppant, it can penetrate the fracture length, height, and complex network, maximizing the effective fracture area.” The fracturing conference also presented: Research at Shell to find a strong ceramic shape less likely to settle out of fluid has led to a W-shaped proppant design. Its complex outline causes drag, making it less likely to settle. University of Texas research into whether mild acid can be used to create lasting pathways in microfractures too small to prop open. The goals are similar to those for acidizing carbonate formations— etching production pathways by dissolving calcite. Fairmont Santrol’s large exhibit featuring its Propel SSP Proppant Transport coating. It was competing on the show floor with Trican’s MVP Frac, a coating which can make proppant buoyant by adsorbing gases such as nitrogen. All were selling new ideas at a time when operators were reacting to the oil price crash by sharply reducing the number of wells completed, and relying more on the oldest type of proppant, which is sand. Fairmount Santrol’s polymer coating is able to reduce settling allowing more proppant to reach fractures. The company has taken an invention that it debuted 2 years ago at the conference, and modified it so it can be practically delivered through its extensive proppant supply network. On a huge screen, the proppant supplier featured four promising field tests. The company is seeking early adopters to make a case for its polymer coating, which it says can improve production and reduce the cost of pumping jobs. “People are looking for technology,” to improve results, said Brian Goldstein, product director for Propel SSP technology at Fairmount Santrol. “The change in the market changes the way you think.”