bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Cementing/Zonal Isolation (May 2016)
Authors: DeBruijn Gunnar 
Published: January 2017

Technology Focus
Is zonal isolation provided by cement? Cementing is central to the discussion of zonal isolation and well integrity because cement typically provides at least one barrier in a well and is a component of the barrier envelope or barrier system during well construction and the operational phases of the well. Cement parameters are typically included in regulations and included as part of the permanent-abandonment requirements for oil and gas wells.
As an industry, installing and maintaining the cement barrier and well integrity are part of our social license to operate. Since the first use of cement in oil wells in 1906, we as an industry have been proud that we have established and continuously improved cementing practices.
There is a long history of industry standards for cementing, with the American Petroleum Institute establishing the first cementing standard in 1948. SPE has also included cementing sessions at technical conferences for the last half-century. A quick search on the word “cement” in the SPE OnePetro database yields 21,133 results, dating back to 1945.
In the last several years, regulations have been updated and rewritten worldwide. In every jurisdiction, we can point to a regulation or industry standard that affects drilling and cementing operations. This regulatory attention compels us to double-check our practices, continue effective techniques, and develop technology where improvements are needed.
Technology is also focused on improving verification of cement placement and barrier achievement. Cement evaluation, including wellsite observations during cement placement, pressure tests, and logging techniques, are part of the well-integrity equation. These enhanced evaluation methods provide confidence that zonal isolation and well integrity are achieved.
As an industry and as SPE professionals, we work to provide energy from wells that use cement as a key component in providing zonal isolation and well integrity. We comply with regulations, industry standards, and industry best practices and continually update technology that instills confidence in zonal isolation and well integrity for our industry, stakeholders, and society. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 172937 Achieving Cementing Improvement in Horizontal Tight-Gasfield Development by Pungki Ariyanto, BP, et al.
SPE/IADC 167922 Intermixing of Cementing Fluids: Understanding Mud Displacement and Cement Placement by Zhongming Chen, Baker Hughes, et al.
SPE 175237 A Decade of Self-Sealing- Cement Technology Application To Ensure Long-Term Well Integrity by Arash Shadravan, ReservoirFocus, et al.
Run-Life Improvement by Implementation of Artificial-Lift-Systems Failure Classification
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173913, “Run-Life Improvement by Implementation of Artificial-Lift- Systems Failure Classification and Root-Cause Failure Classification,” by Edward Rubiano, José Luis Martin, Jesus Prada, Manuel Monroy, Laura Labrador, Jonathan Celis, and Jahir Gutierrez, Oxy, and Michel Bohorquez, Ecopetrol, prepared for the 2015 SPE Artificial Lift Conference—Latin America and Caribbean, Salvador, Brazil, 27–28 May. The paper has not been peer reviewed.
This paper describes a methodology for classification of artificial-lift-system (ALS) failures and addition of a commonly used root-cause failure classification. This methodology was applied to different ALSs such as beam pumps (BPs), progressing cavity pumps (PCPs), electrical submersible pumps (ESPs), and electrical submersible progressing cavity pumps (ESPCPs). The starting point was the definition of the boundaries of each system. Then, each job in the well was defined as (1) a failure, (2) a failure, non-ALS, or (3) no failure, in order to look for ways to improve run life.
Introduction
La Cira-Infantas oil field is in the Middle Magdalena Valley in Colombia (Fig. 1). The vast majority of the wells are completed with 7-in. production casing and perforated with 5 shots/ft with no sand-control completion in place, and then the ALS is installed.
ALS in La Cira-Infantas
From the beginning of the activity in La Cira-Infantas, almost 100 years ago, several ALSs have been used to produce fluids from the wells. Since 2005, the field has offered different conditions, depending on the mature state of the waterflooding— high water percentage, high and low flow rates, free gas, and corrosive fluids.
Currently, ALSs such as BPs, PCPs, ESPs, and ESPCPs are used for producing the total fluid of the field.
Failure Analysis
The root-cause failure-analysis (RCFA) process used in La Cira-Infantas has the objective of finding the real cause of a given failure and identifying effective solutions to prevent a recurrence of the failure. The steps for the RCFA are as follows.
Initial Diagnosis and Failure Confirmation. When an ALS ceases to lift the expected production, specific procedures are performed to try to restart the system. If production is not re-established, a downhole failure is confirmed.
Pulling Equipment From the Well. Mechanical and electrical tests are performed to determine ALS condition. Tubing is tested for leaks. As equipment is pulled, each part of the ALS is inspected carefully and qualitative measurements are taken.
Technology Focus: New-Frontier Reservoirs I
Authors: Chipperfield Simon 
Published: January 2017

Overview
With the current changes in the industry, are we seeing the demise of unconventional reservoir development? Let us review several recent industry indicators.
Numerous 2016 published outlooks still forecast unconventional production to increase from 10% in 2016 to greater than 25% by 2035 from sustained growth in North America and China. By 2040, it is also expected that unconventional supplies will account for nearly 90% of North American gas production. This increase in unconventional-gas demand is expected to be driven by a fundamental global requirement for energy in the medium term that is affordable, abundant, clean, and available.
Are these forecasts still realistic in the shorter term, when we are faced with a low oil price? I would argue that they are still realistic because, although the industry is contracting, it is quite clear that companies are rapidly adapting to the oil-price drop. Apache, for example, is quoting that unconventional-well costs have reduced by 45% below their 2014 average, with 50% of these savings as a result of new technologies. Shell is highlighting similar well-cost reductions of 30% year on year. The cost savings arise from many areas. These include new drill-bit technology; replacing diesel with cleaner and less-expensive natural gas for rig fuel; pad drilling; fracture-stimulation optimization, including fewer and smaller fracture stimulations; alternative proppant; and recycling more completion fluid. In other regions of the world, where unconventionals are more immature, such as Argentina, Saudi Arabia, and China, appraisal and exploration also continue for the most-attractive unconventional plays.
So, are we seeing the demise of unconventional developments? No, clearly not. The unconventional industry is adapting to deliver the energy demands of the future despite the low oil price. The key frontiers or challenges for the unconventional industry to grow are technological, geographical, commercial, and geological. This feature highlights some of these key frontiers being explored around the world to ensure that the unconventional industry does not just survive but thrives. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 174754 Proving the Concept of Unconventional Gas Reservoirs in Saudi Arabia Through Multistage-Fractured Horizontal Wells by Ali Al-Momin, Saudi Aramco, et al.
OTC 25739 Offshore Methane Hydrates in the Gulf of Mexico: A Study in Economic Viability by Jaeger Wells, Kiewit Energy Group, et al.
SPE 176260 Unconventional Resources: The Next Generation—Assessing Coal to Liquids, Oil Shale, Underground Coal Gasification, Microbial Coal Conversion, and Other Technologies With the SPEPRMS by Douglas Peacock, Gaffney, Cline, and Associates, et al.
Guest Editorial: Lessons for a Downturn
Authors: King George E. 
Published: January 2017

Guest editorial
Downturns offer you a choice: panic and shut down all but breathing or make use of the opportunities that desperation has handed you. What? In the good times of a price boom, we have no time, and usually no impetus, to alter the way we work and how we apply science and technology. This activity breeds inefficiency and waste, but the flow of easy profits is like an opioid drug, blinding forward-looking senses that should warn us that a price bust may be around the next corner with a demand reduction, manufacturing slowdown, renewable energy advance, or an upset in political alignments.
The world currently needs the energy density and reliability of fossil fuels, but high cost and inefficient use will eventually kill this golden goose. Often, when the good times end, we pull back, believing all the while that the next boom and easy profits are just around the corner if we can just hold on. This is the recipe for bankruptcy.
Every wave of a technology powerful enough to alter the economic landscape in any industry has a life span divided into three parts: an often rough beginning, a period of growth where the technology reaches a zenith of efficiency, and the inevitable plateau where we think it cannot be exceeded or replaced. All the while, a new technology is often quietly building that can upset our comfortable operations world. The history of the oil field is littered with the memories of companies that ignored developments by overreaching only for the profits made available by a boom and ignoring the future. While some would like to believe that wildcatters’ luck will drive the next upturn, the promises of unconventional formations will not be unlocked by chance. An attempt to express the problem might start with a small modification to the proverb, “There are none so deaf as those who will not listen.”
Better Practices
So, what is to be done in a downturn? Those on the science side of production companies can use the time to review each part of well performance with the objective of looking for better practices than the “best” practices that we have unconsciously limited ourselves to. Operators accepting this path often come out stronger after a slump. Gains in efficiency, generated from a better understanding of a company’s well-development practices, remain after oil prices rebound and supplier discounts disappear. The enablers are keeping and supporting a technological staff that is capable of learning prior to and while in survival mode, plus a management team that is wiser about how and where to invest before and after prices rebound. Most of all, it requires tearing down some barriers that “successful experience” has erected to the abandoning of methods with which we have become accustomed.
Mergers in a Low Oil-Price Environment: Proceed With Caution
Authors: Evans Bob , Nyquist Scott , Yanosek Kassia 
Published: January 2017

Management
Unlike what happened during previous oil-price collapses, merger and acquisition (M&A) activity has been limited since prices started to fall in 2014. But the signs are that M&A activity may be building, and oil company management teams should think about which deal strategies they should pursue. The oil-price trend has historically been one of the most important determinants of how value is created in the oil and gas industry, and some M&A strategies that worked in the rising-price environment over the past 15 years may not work in today’s market. This article examines the industry’s M&A performance across cycles back to 1986 and identifies strategies that could help companies create value through the price trough, measured by total returns to shareholders.
Most commodities industries are prone to consolidation during the downside of the cycle, when supply surpluses accumulate, prices fall, and competition heats up. The oil and gas industry is no exception (Fig. 1). In the 1998 to 2000 price trough, more than 25 deals greater than USD 1 billion in value were executed in North America alone, including the BP-Amoco, Exxon-Mobil, and Chevron-Texaco megamergers. In total, this wave of deal making amounted to more than USD 350 billion in just over 2 years. It took another decade to match the same amount of deal volume in North American exploration and production (E&P).
Oil prices are recovering from a 12-year low in January (below USD 30/bbl) but remain well below the levels of most of the past decade. There are signs of rising M&A activity, even though few deals have been executed so far. Over the past year, bidask spreads have been too wide for deals to proceed. However, this could change, given the increasing signs of vulnerability among weaker players in the market.
First, industrywide leverage has risen significantly over the past 3 years, and it is particularly high for independent E&P companies with exposure to US shale production. This group’s leverage has spiked—with debt at nearly 10 times earnings before interest, taxes, depreciation, and amortization—indicating an increasing likelihood of restructuring for the most indebted players. Second, pricing hedges are beginning to come off. As a result, it is possible that there will be oil and gas companies available at distressed prices, either because they are in Chapter 11 (continuing to operate while restructuring their debt) or because their market valuations will sink to such low levels that they could be attractive acquisition candidates, even if the buyer has to reach an agreement with its bondholders as part of the deal.
Egypt Strives To Bolster Economy With Foreign Investment, Imports
Authors: Boschee Pam 
Published: January 2017

Middle East Special Section
An international bidding round for oil and gas announced on 1 August is Egypt’s most recent move to bolster its lackluster economy. The country is facing a severe dollar shortage as a drop in tourism, capital, and exports have caused international reserves to sink by more than half to USD 16.4 billion since the political instability in 2011. Economic activity and vital imports also have been limited by the country’s arrears owed to foreign oil companies.
In July, Petroleum Minister Tarek El- Molla said the arrears were reduced to USD 3.4 billion in 2015–2016 from USD 3.5 billion a year earlier. He said the crude oil and natural gas received from the foreign partners’ share during 2015– 2016 was worth USD 5.4 billion, and Egypt paid the partners USD 5.5 billion.
Egypt was once an oil exporter, but declining production and increasing subsidized consumption have turned it into a net importer. It is dependent on imported gas largely from Iraq and Jordan to keep pace with the country’s demand.
The high cost of energy subsidies in Egypt has contributed to the country’s budget deficit and the inability of the Egyptian General Petroleum Corporation (EGPC), the country’s national oil company, to pay off its debt to foreign operators. In the fiscal year (FY) 2013– 2014, Egypt spent USD 18.2 billion on oil product subsidies and USD 1.8 billion on electricity subsidies. In FY 2014–2015, the Egyptian government projected the cost of oil product subsidies to fall to USD 9.2 billion as a result of its implemented subsidy reforms and the drop in global crude oil prices since mid-2014. However, Egypt’s spending on electricity subsidies has increased and is budgeted to cost USD 3.6 billion in FY 2014–2015.
To avoid significant backlash from the public at the prospect of dwindling subsidies, which now account for approximately one-fifth of the government’s total budget, the country is looking to increase production by appealing to foreign investment in its oil and gas sector.
From 2012 to 2013, Egypt’s dry natural gas production declined by 5%. Substantial natural gas discoveries in the Mediterranean Sea and in other areas have been undeveloped because the price that the government was willing to pay foreign operators for the gas was too low, making some projects commercially unviable. However, in recent years Egypt has signed deals to pay foreign operators a higher price for the natural gas they produce.
Technology Focus: Completions (September 2016)
Authors: Clem Nicholas 
Published: January 2017

Technology Focus
The past year has proved to be one of the more challenging years our industry has ever faced. We have been forced to think differently and solve problems in new and unique ways as the oil and gas community has remained laser-focused on reducing costs and improving the economics of its projects. In last year’s article, I highlighted the uniqueness and customizable nature of well completions, which makes the completion strategy a rich target for change as project economics are reevaluated in the face of uncertainty.
As activity plummeted to record lows, we witnessed a calibration of completion strategies. Whether it was further optimization of the preferred completion technique, implementation of new technologies, or a complete shift in completion philosophy, no stone was left unturned when it came to designing and implementing the well architecture. The primary objective was improving well economics, of course, through reducing costs or increasing productivity. So, how does the well completion fit into this overall goal of cost reduction and productivity increase? The answer is simple: time. Time savings can be achieved in a variety of ways, the most significant being deployment speed, installation reliability, and consolidation of trips into the well. Fracturing plugs for plug-and- perforate completions that can be deployed in excess of 600 ft/min without presetting, International Organization for Standardization and American Petroleum Institute qualification standards for sealing devices, autonomous and remotely actuated downhole tools, and equipment that disintegrates downhole are all commonplace examples of how today’s completions are focused, more than ever, on reducing nonproductive time through speed, reliability, and efficiency.
As our industry evolves and responds to the effects of global economies and geopolitical events, so, too, do the solutions that enable that evolution. What has transpired over the past 18 months, while challenging for all, is oftentimes the necessary catalyst to spark innovation and challenge conventional norms. What was not possible yesterday may be possible today.
I am personally thankful to have had the opportunity to work through this industry cycle and am excited about the future of the oil and gas industry. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 174922 High-Performance Plug-and- Perforate Completions in Unconventional Wells by Liam McNelis, DynaEnergetics, et al.
SPE 176811 Designing, Planning, and Installing an Eight-Zone All-Electric Intelligent Completion System in an Extreme-Reservoir-Contact Well by S. Jacob, Saudi Aramco, et al.
SPE 179136 An Evaluation of Completion Effectiveness in Hydraulically Fractured Wells and the Assessment of Refracturing Scenarios by Jeff Dahl, Devon Energy, et al.
SPE 180966 Stimulation Optimization Using Engineered Diversion Work Flow To Increase Wellbore Contact in Cemented Completions by N. Heaton, Schlumberger, et al.
A 5-Year Journey of Advanced Completions
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175330, “Five Years’ Journey of Advanced Completions for the Kuwait Oil Company,” by Mohammed A. Siddiqui, SPE, Ahmad K. Al-Jasmi, SPE, Menwer M. Al-Rasheedi, and Hashem F. Al-Abdullah, Kuwait Oil Company, prepared for the 2015 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed.
With the objective of increasing its production to 4.0 million BOPD, the Kuwait Oil Company (KOC) is developing its fields with optimum technology solutions. One of these promising technologies is that of advanced completions—specifically, inflow-control devices (ICDs) and interval-control valves (ICVs). Application of this technology led to multifold increases in sustained production in horizontal wells in all reservoirs and a simultaneous reduction in water cut.
Introduction
The main reservoir objectives for applying advanced completions include decreasing the influence of heel-to-toe effects, controlling influx from high-permeability zones, delaying water/gas fronting, depleting the reservoir uniformly, and improving well cleanup and sweep efficiency. Advanced completions are applicable in both sandstone and carbonate reservoirs. The ICVs also provide the advantage of controlling production from multiple laterals in multilateral wells and controlling influx in layered reservoirs. KOC operates several prolific oil reservoirs with significant differences in geological and fluid characteristics (these are described in detail in the complete paper).
ICDs (conventional or advanced) are passive flow-velocity restrictors and offer excellent regulation of flow through the constricted openings (Fig. 1). An optimal pressure drop can be achieved through this equipment in a comprehensive downhole completion design that includes ICD type, placement methodology, and well-thought-out and optimally planned reservoir segmentation with use of geological and petrophysical data. The compartmentalization of the lateral section can be achieved through swellable or mechanical packers.
ICVs are intelligent well-equipment systems whose functions, in principle, are similar to those of the ICD in terms of reservoir management. Additionally, they allow operators to control flow into or out of a segmented reservoir interval wherever selective control over production or injection is required.
Deep-Sea Laser Raman - Developments for In-Situ Chemical Analysis and Applications
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26505, “Deep-Sea Laser Raman—Past, Present, and Future Developments for In-Situ Chemical Analysis and Applications,” by William J. Kirkwood, Monterey Bay Aquarium Research Institute, prepared for the 2016 Offshore Technology Conference Asia, Kuala Lumpur, 22–25 March. The paper has not been peer reviewed.
The deep-ocean Raman in-situ spectrometer (DORISS) instruments were developed for the purposes of identifying compounds and studying in-situ chemical reactions in a nondestructive manner while working with solids, liquids, and gases. The approaches used in the development of three generations of instruments have been successful and have shown that not only is Raman spectroscopy feasible in the deep ocean, but also its results are entirely comparable with spectra taken in terrestrial applications. DORISS has also shown that in-situ measurements are more accurate than returning many samples from the deep sea.
Introduction
The approach taken began with modification of a standard bench-top laboratory unit for use at sea to demonstrate feasibility. The second generation then solved several impediments to improved performance in the deep sea and contributed to the development of additional tools to enhance capabilities. The third generation is now past the design process and in assembly for bench-top testing to bring the fluorescence signal (noise) down to achieve a 19-fold increase in sensitivity. This allows the use of Raman on compounds that have high-order organic compounds such as some oils and makes the detection of carbon dioxide (CO2) much easier. The high-power approach in this system will enable faster operations for subsea mining.