bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Unconventional Recovery (July 2008)
Authors: Norris Stephen 
Published: February 2015

Technology Focus
Have you heard the story about the "17-year overnight sensation" (Durham 2005)? (If you work in northern Texas or are involved in unconventional resources, then your answer probably is yes, and if so, please bear with me—it is a great story and worthy of being repeated.)
In the early 1980s, in a county on the outskirts of Fort Worth, Texas, there was a privately owned oil and gas company that just would not give up on a novel idea it had for obtaining a new source of gas for a large existing gas-gathering infrastructure and a large gas-processing plant. It seemed that whenever it drilled a well for deeper horizons, it encountered a significant gas show in a very thick shale section that contained methane and some heavier gases. Some brave soul, probably a very young engineer or geologist, suggested testing the shale to see if it possibly could be productive. At the time, the conventional wisdom was that the shale was probably a source rock, but was certainly not reservoir quality and certainly not productive. But the president of the company had faith in his young professionals and gave the go-ahead for testing.
The first well, the C.W. Slay No. 1, was an economic failure, as were the next 40 wells (Bowker 2003). It took 17 years for the company to develop an economic technique that worked. How many companies that you know have that kind of patience? In 1999, very few people had heard of the Barnett shale, but by 2001, it was well on the way to becoming the largest gas field in Texas.
I think that stories like this make unconventional recovery a very exciting arena in which to work. The resource is there, the demand is definitely there, and it is up to engineers, geologists, and enlightened managers to make it happen.
In this issue, we look at three great examples of applying new technology and knowhow in the areas of coalbed methane, tight-gas-field deliquification, and gas hydrates. Is there another 17-year overnight sensation here? You be the judge.

References
Bowker, K.A. 2003. Recent Developments of the Barnett Shale Play, Fort Worth
Basin. West Texas Geological Society Bulletin42 (6): 4–11.
Durham, L.S. 2005. The 17-Year Overnight Sensation. Explorer 2005 (May). www.aapg.org/explorer/2005/05may/barnett_shale.cfm. Accessed 5 June 2008.
Unconventional Recovery additional reading available at the SPE eLibrary: www.spe.org.
SPE 114173 • "Stimulating Unconventional Reservoirs: Maximizing Network Growth While Optimizing Fracture Conductivity" by N.R. Warpinski, SPE, Pinnacle Technologies, et al.
SPE 110590 • "Potential for Oil-Shale Development in the US" by Khosrow Biglarbigi, Intek, et al.
Additional reading available at OnePetro: www.onepetro.org.
OTC 19519 • "Four Critical Needs To Change the Hydrate-Energy Paradigm From Assessment to Production: The 2007 Report to Congress by the US Federal Methane Hydrate Advisory Committee" by Dendy Sloan, SPE, Colorado School of Mines, et al.
Are We Really Listening?
Authors: Hoyer Carel 
Published: February 2015

Guest editorial
It is often said that there is a reason we have two ears and one mouth. Similarly, most would agree that things would go a lot easier during well construction if both operators and service entities spent more time listening and trying to comprehend and less time talking. All this talking makes me wonder—who is really listening to what the well is trying to tell them while it is being drilled?
Old habits are a poor excuse for allowing drilling hazards to eat up a budget. But that is the case for many "conventional-wisdom" well construction and fluid programs, where 10 to 40% of expenditures are still spent drilling trouble zones and large contingency funds are the norm. Given we have likely already drilled most of the "easy" prospects, unless we change our approach, drilling-related nonproductive time will no doubt continue trending upwards.
From one well to the next, "the way we've always done it" often trumps lessons learned. The magnitude of the resulting spending—particularly to combat known and predicted hazards—makes a harsh point. For instance, an analysis of Gulf of Mexico data from James K. Dodson Company shows that wellbore instability accounts for more than 31% of total nonproductive time in nonsubsalt wells and 41% in subsalt wells. For a 20,000-ft well, extrapolated losses add up to the millions of dollars.
However, it has also been shown that these trouble zones can be effectively and efficiently drilled or even avoided if new drilling practices are considered, applied, and combined with proven drilling technologies, products, and processes.

Legacy Constraints
The very earliest wells were drilled "underbalanced." Hydrocarbons flowed to the surface until events like Spindletop in 1901 created environmental and safety challenges. It was only from the desire to reach greater depths that drilling fluids were weighted up and "overbalanced drilling" was invented.
Imagine if a rotating control device (RCD) and automated choke manifold had been invented instead, and all wells had been drilled underbalanced to the present day? Imagine the difficulty in trying to persuade long-time reservoir engineers or drillers to now commence drilling their wells overbalanced, pumping foreign chemicals and particulate into their wellbore to get to total depth (TD) and then being given the "solution" by the service companies to pump expensive stimulation treatments to try and remove or bypass the damage, before handing over to the completion group. Or the need to start running multimillion dollar tools with nuclear sources downhole to indirectly measure rock properties and try and deduce, using complex software, where the oil might actually be located with the very real risk of leaving some of these expensive tools downhole.
Polymer Treatment Controls Fluid Loss While Maintaining Hydrocarbon Flow
Authors: Eoff Larry , Waltman Bart 
Published: February 2015

Technology Update
The loss of pumped fluids that are circulated from surface to total depth (TD) and back during various drilling, completion, and intervention operations poses numerous problems affecting wells and reservoirs. Fluid loss (FL) to the formation is costly not only in terms of the fluid itself, diverted from its task, but in the time and expense required to mitigate the problem. Well control can be compromised, wellbore cleanouts impaired, and reservoirs damaged, sometimes permanently, as a result of fluids entering the formation.
A low-viscosity, solids-free FL treatment can help (1) cure lost circulation, (2) prevent loss of expensive drill-in fluid during workovers, (3) improve well control by maintaining a hydrostatic column, and (4) provide FL control in vertical- and horizontal-well gravel-packing operations.
The treatment technology, developed by Halliburton as the LO-Gard fluid-loss-control system, relies on an associative polymer to decrease matrix permeability to aqueous fluids, limiting leakoff into treated zones. A significant property of the treating fluid is that it causes little or no damage to the flow of hydrocarbons.
The treatment fluid may be used in various applications.Well intervention cleanouts by coiled tubing and hydraulic workoverGravel packingMost lost-circulation events occurring during cementing, fracturing, and drillingAfter tubing-conveyed perforating (TCP) operationsFL control before, during, and after gravel packingElectrical submersible pump (ESP) replacement operationsCirculation maintenance in horizontal openhole completions across unconsolidated sands (Fig. 1)Formation permeability reduction inHigh-permeability streaksThinned or eroded drill-in fluid wall cakeBreeched or fractured wall cakeNatural- or hydraulic-fracture networks

FL Problems and Causes
During workovers, gravel-pack completions, ESP replacement, underbalanced TCP (UTCP), and other applications, aqueous well fluids are usually circulated continuously between the surface and TD. Maintenance of a hydrostatic column is necessary for well control and to enable treatment fluids to be injected into the targeted intervals downhole, without fear of overdisplacing the treatment fluids.
Whatever Happened to the Skills Crisis in the Oil and Gas Industry?
Authors: Peek Peter , Gantes Patrick 
Published: February 2015

Talent & Technology
During the years leading up to the financial crisis of 2008–09, growing skills shortages were one of the main concerns of the oil and gas industry. A 2007 study by Cambridge Energy Research Associates estimated a shortage of 55,500 engineers and project management staff to deliver the more than 400 major projects that were then scheduled to come on stream over the next 5 years. A 2008 Ernst & Young survey showed that nearly 90% of senior human resources executives at 22 top international oil and gas companies thought the industry faced a major talent void and they called the problem one of the top five business issues facing their companies. Several research institutions even ventured to calculate the cost of skills shortages for the industry, and one of the more conservative studies estimated that the US oil and gas industry alone lost between USD 4 and 5 billion in 2006 as a result of the skills shortage.
A number of oil and gas executives argued that if nothing is done, there would be a slowdown in reserve replacements, a "capacity shut-in," and a major increase in operating costs within the next 5 to 10 years. Already, during 2007 and early 2008, reports were coming in of project delays around the world because of the lack of skilled personnel.
We all know that that situation has changed since then. Crude oil prices plunged from more than USD 140/bbl to under USD 40/bbl as the global recession reduced energy demand in the importing countries. And the demand for higher-skilled workers dropped as production declined and producers cut capital expenditure on exploration and new production facilities. The outcome is that many companies and governments, which had developed plans to invest in human resources to tackle the skills shortage, have decided to drop these or scale them down significantly.
This raises an important question: Once the current recession is over, and the industry gears up to meet growing energy demand, will it again be faced with skills shortages restricting production? Clearly, smaller energy companies with limited access to capital have fewer options. But the larger ones with more capital, does it make sense they drop human resources from their investment plans?
Several large companies are already positioning themselves for the recovery. They have maintained or even increased capital expenditures to be able to meet higher demand in the future. But what we have seen so far is that these plans only cover capital investment in production and exploration. So far we have not seen any major plan to address the potential of future skills shortages once the industry gets ready to meet higher energy demands. In our view, the industry risks paying a high price if it ignores the threat of skills shortages limiting future production.
Taking Advantage of Turbulent Times
Authors: Ferling Albrecht , Sternesky Michael 
Published: February 2015

Management
Set in motion by the global financial markets collapse, oil and gas markets have suffered a huge setback since July 2008 when commodity prices began to fall. Energy demand has fallen in all sectors of the global economy, and the lack of available credit and seizing of credit markets had an immediate impact on economic activity in all sectors, signaling the beginning of a deeper and longer recession than we have seen in the last 30 years. These turbulent times require fast and immediate reaction.
Supply and demand balances have been difficult to determine, and oil prices have been volatile over the past year. Today's uncertainty adds considerable complexity to the process of making the right investment decisions for future supply. If the situation does not change soon, the industry may be subject to a very severe supply crunch in the middle of the next decade.
Extraordinary times can also create opportunity. Many companies used the last four years of rising commodity prices as an opportunity to reduce debt and bolster their balance sheets. That may lead to an uptick in mergers and acquisitions of companies with strong and proven reserve positions in politically stable host countries. The risk/reward balance is tilting toward the purchase of whole companies to replace reserves produced.
The ability to quickly integrate an acquisition into the enterprise, which can save millions of dollars, is a significant agility requirement in these troubled times. Today, technology can enable the faster integration of an acquired company's assets with overlapping assets within the enterprise. Using Web-based systems and service-oriented architecture, a virtual consolidation of the underlying enterprise systems can be quickly achieved at the presentation layer, pulling data from the different legacy systems into one unifying view. This virtual consolidation enables the quick integration of overlapping assets with consistent work processes, resulting in faster realization of economies of scale and elimination of redundancies, and gives the acquisition-integration teams more time to harmonize the legacy business systems.
Technology Focus: Reservoir Simulation and Visualization (July 2009)
Authors: Crick Martin 
Published: February 2015

Technology Focus
For many years, the title of this feature has been "Reservoir Simulation and Visualization," but year by year fewer papers are submitted on visualization. This clearly reflects that 3D visualization is no longer a novelty—it is a standard part of our workflow. This trend ties with another I noted last year—greater inclusion of geological modeling in history-matching workflows. Visualization is an essential part of the geological-modeling workflow, one of the geologist's key quality-checking steps, and only with good 3D-graphics workstations did geological modeling become mainstream. However, it does not seem likely that history matching will die out as a topic for papers any time soon!
A great variety of techniques are being deployed to automate the process of history matching (improving the engineer's productivity) and to improve the quality of the result. Several experimental-design techniques are reported, as researchers continue attempts to extract the maximum benefit out of the fewest runs. It will be interesting to see if developments in hardware, leading to ever-reducing computing costs, result in a change of emphasis.
Although history matching remains a key focus, the broader application of mathematical-optimization techniques to prediction is emerging as a key topic of interest. This application goes to the heart of our role as reservoir engineers, and it is good to see history matching treated as merely a means to an end, rather than an end in itself.
The variety of reservoirs being developed and studied with simulation continues to grow, and the boundaries of technology continue to stretch. Naturally fractured carbonates, heavy oil under thermal recovery, tight gas, shale gas, coalbed methane, and other projects all feature more-complex and sophisticated wells.
The 2009 SPE Reservoir Simulation Symposium produced many excellent papers on the underlying technology and algorithms of simulation and its application: It is good to see that innovation continues. Sadly, many of these papers do not lend themselves well to the synopsis format of this feature, so I strongly urge you to track down the Proceedings from a colleague if you were unable to attend.
Reservoir Simulation and Visualization additional reading available at OnePetro: www.onepetro.org
SPE 118178 • "An Integrated Case Study From Seismic to Simulation Through Geostatistical Inversion" by S. Soni, SPE, Fugro-Jason, et al.
SPE 119139 • "Comparison of Stochastic Sampling Algorithms for Uncertainty Quantification" by L. Mohamed, SPE, Heriot-Watt University, et al.
SPE 122934 • "A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and Simulation" by C. Du, SPE, Schlumberger, et al.
Technology Focus: Unconventional Resources (July 2009)
Authors: Polikar Marcel 
Published: February 2015

Technology Focus
The baton has been passed, and so, during the next 3 years, I will provide here a brief editorial about and drawing your attention to recent publications or events pertaining to unconventional resources.
I have been around the industry since the late 1970s and have seen many changes since. I started my petroleum career working in the unconventional oil sands of Alberta, Canada, which are similar to but colder than those of Venezuela. Although unconventional-oil exploitation is still a dynamic topic, activity in unconventional gas (e.g., tight gas, shale gas, and coalbed methane) is picking up as environmental awareness surrounding the exploitation of unconventional resources grows. So, my editorial is about "unconventionals," a very trendy word indeed.
What are unconventional resources and what characterizes them? I will broach this topic in a general way without offering a definition—this has been debated for a long time! There are unconventional locations (e.g., deep water or beneath national parklands, a lake, or a city), which require unconventional methods. There are unconventional formations (e.g., oil sands and coalbed methane) containing hydrocarbons that cannot be produced in a conventional (primary or secondary) way with available equipment, or are not being exploited because of unavailable methods and/or high costs. Unconventional technologies are being developed to recover these unconventional and difficult-to-recover hydrocarbons, from drilling and completions to logging to production. There are unconventional "energies," with a shift toward renewable ones such as wind, solar, geothermal, and deep ocean energies, and biofuels.
Obviously, the environment is a priority, and large efforts are expended nowadays in this direction. For example, greenhouse gases are being captured and disposed of in deep rocks or in the water in pilot projects; these gases are also used for enhanced oil recovery.
The more-than-century-old "oil and gas" industry has changed into an "energy" industry. As this industry is redefined, many of the technologies that traditionally have been used for oil and gas exploration and development are needed to expand unconventional resources and advance the development of other sources of energy, whether they are nonrenewable or renewable ones. It is natural for this growth of the industry to happen. Along the way, we will find/discover new technologies that will also help the development or redevelopment of the old established sources. Bright is the future!
Unconventional Resources additional reading available at OnePetro: www.onepetro.org
SPE 119891 • "Workflow for Stratigraphic Characterization of Unconventional Gas Shales" by Roger M. Slatt, SPE, University of Oklahoma, et al.
IPTC 12743 • "Importance of Unconventional Oil Resources in Shaping the Far East Energy Future" by Philip Stark, IHS, et al.
SPE 113852 • "Oil and Gas Expertise for Geothermal Exploitation: The Need for Technology Transfer" by Gioia Falcone, SPE, Texas A&M University, et al.
Ocean-Thermal-Energy Conversion
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19979, "Ocean-Thermal- Energy Conversion (OTEC): Technical Viability, Cost Projections, and De velopment Strategies," by T.J. Plocek and M. Laboy, Offshore Infrastructure Associates, and J.A. Marti, Technical Consulting Group, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.
Ocean-thermal-energy conversion (OTEC) is a renewable-energy source particularly suited for tropical zones. It uses the temperature difference between the warm surface ocean water and the cold deep ocean water to generate electricity and, if desired, potable water. This alternative energy source does not depend on fossil fuels, is not vulnerable to world market fluctuations and has less environmental impact than other energy sources.

Introduction
OTEC is a renewable-energy technology that is applicable to most parts of the world's deep oceans between 20° north and 20° south latitude, including the Caribbean Sea and the Gulf of Mexico; the Pacific, Atlantic, and Indian Oceans; and the Arabian Sea, where the temperature difference between the warm surface ocean water and the cold deep ocean water is equal to or greater than 68°F. OTEC basically recovers part of the solar energy absorbed by the ocean. Its main application is in tropical zones where deep ocean water is available at a short distance from the shore (less than 6 miles). In addition, the potential site must have a marine environment that allows the operation of a stable system.
One of the greatest advantages of OTEC is that it allows the coproduction of potable water in addition to electric power. It is possible to produce as much 0.5 million gal/D for each MW of electricity generated. Because OTEC does not use fossil fuel, the produced electricity has a fixed cost; thus, it is not susceptible to the cost volatility that affects other energy sources such as petroleum, coal, and natural gas. Moreover, the environmental impact is less than that of other sources of energy because no products of combustion are generated during the power-production process. All of these aspects have caused a revival of interest in OTEC.

Basic Principles
An OTEC plant consists of a heat engine that converts thermal energy into mechanical work by use of the temperature gradient between a heat source and a heat sink. Although this temperature gradient is relatively small compared to a steam engine, the principle is the same. OTEC technology is divided into three categories: closed cycle, open cycle, and hybrid cycle.