bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Unconventional Resources (July 2010)
Authors: Polikar Marcel 
Published: February 2015

Technology Focus
“Unconventionals” is a very trendy word indeed. But what is so unconventional about unconventional oil and gas resources?
Heavy-oil exploitation is widely commercialized; whether by mining of the oil sands and oil shales or by in-situ steaming or combusting processes that bring extra-heavy oil to the surface. Yet we say that such oil is unconventional. Research and pilot operations continue in an effort to increase recovery and decrease costs. When “cheap and easy oil” becomes scarce, should we then refer to these recovery techniques as “advanced,” “complex,” or “difficult” recovery rather than the exploitation of “unconventional” oil?
The same could be said for shale gas. A few years ago, such gas was said to be unconventional. However, continued research and recent exploitation with multifracs from horizontal wells have led us to think differently. Already, shale gas appears to be more conventional than coalbed methane. With the ever-increasing need for natural gas as a clean fuel, the importance of producing more gas is growing. Not all “unconventional” gas is equal: Each type is at a different stage of exploitation. While waiting to find out about the effect of renewable energies on our society, gas remains the leading fuel of choice, whether it is natural or a product of gasification of coal or biomass.
So, where do we look next? Previous centuries all favored a particular source of energy: The 19th century focused on coal because it had no other alternative, and the 20th century was mainly oil-centered. In the 21st century, we must turn wisely to the resources we have. There is no doubt that we will have to use a diversity of energy sources adapted to our needs: oil, gas, nuclear, and renewable energies will all find their share.
I expect that our energy industry will expand unconventional-resources development and at the same time advance the growth of nonrenewable sources of energy. This action will guide our strategies for future energy needs. Let us prepare for the future.
Unconventional Resources additional reading available at OnePetro: www.onepetro.org
SPE 125525 • “The Geomechanics of a Shale Play: What Makes a Shale Prospective!” by Larry K. Britt, Britt Rock Mechanics Laboratory, et al.
SPE 129085 • “A Thermal Gas-Production System From Methane-Hydrate Layers by Hot-Water Injection” by K. Sasaki, SPE, Kyushu University, et al.
SPE 125419 • “Successful Strategies for Dewatering Wells Using ESPs” by Lonnie Bassett, Borets-Weatherford
OTC 20644 • “Ocean Thermal-Energy Conversion: Strategies for System Integration and Implementation Using Commercially Available Components and Technology” by J.A. Marti, Offshore Infrastructure Associates, et al.
Montney Unconventional Gas: An Integrated Approach To Optimizing Wellbore Completions
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125970, ’Montney Unconventional Gas - Next Generation, An Integrated Approach To Optimizing Wellbore Completions Technology,’ by Rodney Schnell, SPE, Nicole Tapper, SPE, and Ryan Genyk, SPE, Talisman Energy, and Dalis Deliu, SPE, and Habib Tavakol, SPE, Halliburton, originally prepared for the 2009 SPE Eastern Regional Meeting, Charleston, West Virginia, 23-25 September. The paper has not been peer reviewed.
The full-length paper presents the evolution of well construction in the Montney play, technical and economic challenges, and the new synergy developed between drilling and completions.
Introduction
The Montney formation is a prolific tight gas reservoir in the western Canadian sedimentary basin, in both Alberta and British Columbia. In the Peace River Arch area, horizontal wells with multiple fractures are the key to achieving economic success. Using various area drilling and completion techniques as a starting point, lowering the installation cost without affecting the completion or production results was the driver for the next generation of completions. Swellable-packer systems with ball-drop-actuated sliding sleeves initially were run in various openhole configurations to allow multiple fracture treatments to be pumped in one operation, a significant savings from multiple-day operations. From these successes, a drive to reduce costs further led to cemented ball-drop sliding sleeves with a hydraulic-fracture-initiator sleeve at the toe of the horizontal well.
After installing the cemented sleeves on eight horizontal wells and improving the process continuously, it has been concluded that the system can reduce drilling and completion costs by 25% when compared to swellable-packer systems with intermediate casing and by 50% over traditional cemented liners with perforated completions. These savings are accomplished without affecting well performance negatively.
Background
Swellable Packers. To stimulate the Montney reservoir effectively with multiple fractures, it was necessary to isolate each interval. As a potential improvement to cementing a liner in place and perforating individual intervals, swellable packers were used with sliding sleeves between the packers. The sleeves were actuated using a ball-drop mechanism to isolate the portion of the wellbore that had been fracture stimulated previously. Once isolated, the next interval is accessed when hydraulic pressure from the pumping units opens the next sleeve.
The speed of the completion operations with the swellable packers and ball-drop system is very efficient. It is quite easy for the operator to achieve seven fracture stimulations in 1 day, and there were no problems encountered initiating fractures into the open hole between the swellable packers.
Production Results. Microseismic data show very good coverage of the Montney formation and show that the swellable packers were able to pro-vide adequate isolation consistently between fractures.
Lessons Learned Conducting Drilling and CO2-Injection Operations at the Victor J. Daniel Power Plant in Mississippi
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124003, ’Lessons Learned While Conducting Drilling and CO2- Injection Operations at the Victor J. Daniel Power Plant in Mississippi,’ by George Koperna, SPE, David Riestenberg, SPE, and Robin Petrusak, SPE, Ad - vanced Resources International; Richard Esposito, Southern Company Generation; and Dick Rhudy, Electrical Power Research Institute, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.
Lessons learned from a CO2-injection pilot in southeastern Mississippi highlight issues unique to injection at a power plant. Conventional oil and gas technology was used to track CO2 in the subsurface. An electric-power-generating facility hosted a CO2-sequestration demonstration as part of the Southeast Carbon Sequestration Regional Partnership. The primary goal was to provide a foundation for safe and secure storage of CO2 in a deep saline reservoir within a power plant’s property boundary.
Introduction
In 2008, Mississippi Power Company’s Victor J. Daniel Jr. electric-power-generating facility, in Jackson County, Mississippi, hosted a CO2-sequestration demonstration sponsored by the US Department of Energy (USDOE). The geological-review process identified saline reservoirs for CO2 storage, with the Lower Tuscaloosa formation as the most promising. An observation well, Mississippi Power Company 11-1 (MPC 11-1), and the injection well (MPC 11-2) were drilled during the first half of 2008. In October 2008, more than 3,000 T of CO2 were injected into the Lower Tuscaloosa formation. Fig. 1 shows the location of the two wells on the plant’s property.
Regional Characterization
The test site, like many potential deep-saline-aquifer storage sites, lies in a region with little historical oil and gas activity. As such, only sparse subsurface data were available within the area, and a regional approach to characterizing the subsurface was used. All available geological information for the region was gathered to characterize the subsurface geology.
Only one existing well penetrated the injection and confining intervals within 5 miles of the test site. No recent, high-quality seismic data were available in the immediate area. However, given that the coastal-plain strata along the Mississippi Gulf Coast are characteristically laterally extensive and contain no significant structural deformations (folding or faulting), a regional approach to describe the geology was deemed appropriate as the first step. The observation well (cased, but not completed), 175 ft from the injection well, was scheduled to be drilled and logged (with a full suite of tools) before drilling the injection well to ensure that the test site would be suitable.
CO2 Injection Into Depleted Gas Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123788, ’CO2 Injection Into Depleted Gas Reservoirs,’ by Hrvoje Galic, SPE, Steve Cawley, SPE, and Simon Bishop, SPE, BP, and Steve Todman, SPE, and Frederic Gas, Petroleum Experts Ltd., prepared for the 2009 SPE Offshore Europe Oil and Gas Conference & Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed.
Depleted gas fields represent an opportunity for CO2 storage. However, low reservoir pressure will present a significant challenge for CO2 injection because of phase-behavior issues. This behavior will constrain injection operating parameters significantly during the early stages of CO2 injection. An efficient way of understanding and possibly resolving flow-assurance problems is to adopt an integrated-asset-modeling (IAM) approach. The IAM recognizes the interaction between all system elements and enables observing the effects of many parameter changes within the whole system.
Introduction
The case study modeled a BP-operated asset offshore UK in the southern North Sea (UK SNS) for CO2 injection. The modeled CO2 supply would come from burning fossil fuels at a power plant. The resulting CO2 would be captured, dehydrated, compressed, and transported to an onshore pumping facility at approximately 70–80 bar and at ambient temperature (0 to 20°C).
Under these conditions, CO2 is in dense liquid phase. An onshore pump then would move the CO2 through a subsea pipeline to an offshore injection facility. From there, it would be distributed to several injection wells (most likely converted from existing production service) and injected into a depleted gas reservoir, which had initial conditions of approximately 27 bar and 90°C. The model assumed an approximately constant CO2 delivery rate of 2×106 t/a for a nominal project life of 20 years, with injection beginning in 2013.
Toolkit
The injection-modeling toolkit comprised a full-field thermal reservoir model with wells and well-network descriptions, surface-network descriptions, dynamic connections between the reservoir and the well-/surface-net-work models (acting as a data-transfer system and master controller for the integrated full-field model at each forecast timestep), and a consistent set of fluid pressure/volume/temperature (PVT) descriptions between the different models.
A major technical challenge was related to the phase behavior of CO2. As Fig. 1 shows, pure CO2 has a triple point of 5.18 bar at −56.6°C and a critical point of 73.8 bar at 31.1°C, enabling three different phase regions to be defined under real reservoir conditions: liquid, vapor, and supercritical fluid.
Keeping the CO2 in a liquid or super-critical phase is essential to realize the benefits from the high density of the fluid in terms of bulk-transportation efficiency, injectivity potential, and stored-CO2 mass.
En Route: An Unconventional Future
Authors: Labastie Alain 
Published: February 2015

President's column
In the last couple of years, we have seen an extraordinary growth of unconventional gas activity that is literally reshaping our industry—notably, tight gas reservoirs and gas shales in North America and CSG/LNG projects in Australia (CSG means coal seam gas, which is another name for coalbed methane).
These advances were made feasible by technology, which made possible what was once considered impossible to achieve (production per well, sufficiently low cost per well, etc.), but also by perseverance. We must not forget that it took about 20 years to find the key to unlock the potential of these unconventional gas plays, whose resource had been identified a long while ago. This remark applies also to the development of another unconventional hydrocarbon, the oil sands of Canada; it took 20 years from the concept of steam-assisted gravity drainage (SAGD), and the first patent by Roger Butler, to significant production using this technology
As recently as 5 years ago, almost nobody was forecasting what is happening now with gas shales. Our current success has been made possible by a few technological breakthroughs, or step changes, which are by essence difficult to predict. I think that will be the case for all unconventional hydrocarbons, such as oil shales and, perhaps someday, gas hydrates. It is almost impossible to make a reliable guess about when gas hydrates will come onstream with significance, but this will happen at some time. It is also interesting to compare oil shales and gas shales—oil-shale production still faces a lot of technological barriers, and the economics look quite uncertain, which is exactly the situation gas shales were in 20 years ago.
Unconventional hydrocarbons are interesting for two reasons: (1) the resources are huge, and may cover our needs for more than a century; and (2) the geographic distribution of those resources, which is mostly in non-OPEC countries. The gas resource is important in North America, central Europe, and Australia. The oil-shales resource, as known today, is mostly in North America and “new” countries such as Jordan, Lithuania, Morocco, and a few others.
A very important point is that, in addition to “traditional” technology challenges, the development of all types of unconventional hydrocarbons is facing similar environmental issues: One is land use—in all cases, footprint is important, mostly due to the large number of wells. The other is water issues—production of dirty water (to be treated adequately), or the risk or fear of contamination of aquifers when fracturing the pay zone.
Fiber-Optic Sensing Technology Providing Well, Reservoir Information - Anyplace, Anytime
Authors: Koelman J. Vianney 
Published: February 2015

Technology Update
Fiber-optic sensing is known in the oil and gas industry as a technology that allows continuous temperature profiling along entire well paths. However, surveillance applications focusing solely on temperature measurements are limited to recovery processes with a clear, unambiguous thermal signature. This has prevented fiber-optic sensing from becoming a widely deployed technology in oil and gas production. However, we are now witnessing a confluence of novel fiber-optic technologies that promise a much wider range of subsurface measurements. This opens new avenues in well and reservoir management and highlights the opportunity for fiber optics to become a pervasive oilfield technology. For this to achieve reality, the multiple sensing technologies being introduced by various providers need to be combined and deployment costs contained. The key enabler to achieving these goals is to bundle a selection of fibers into a single cable suitable for downhole deployment and optimized for monitoring a variety of in-situ data.
Distributed Sensing—A Growing Toolbox of Fiber-Optic Techniques
The individual sensing technologies are at various stages of development and derisking. Distributed temperature sensing (DTS) is the most mature technology, followed by distributed strain sensing (DSS). The latter technology, developed by Shell and Baker Hughes under the product name RTCM (Real Time Compaction Monitoring), allows operators to monitor tiny well deformations during the lifetime of a well (Earles et al. 2010). Both technologies can be combined, and fiber-optic pressure sensing capabilities (often labeled DPS) provide complementary data to this mix of sensing technologies (Available DPS systems tend to provide single- or multipoint pressure readings as opposed to true distributed pressure measurements, it should be noted.)
Other fiber-optic sensing technologies, such as distributed acoustic sensing (DAS) and distributed chemical sensing (DCS), are less mature but are expected to hit the market in the next few years. DAS turns a standard telecom fiber deployed over an entire well path into a permanent array of microphones. DCS, the latest addition to the growing toolbox of fiber-optic techniques, will allow the detection of specific molecules along the full inflow area of producing wells. Last year, Shell embarked on a collaboration with QinetiQ, based in the UK, to evaluate the potential of DAS for oil and gas applications, and this year Shell entered into a similar arrangement with TNO, based in the Netherlands, with the aim of derisking DCS technology. Currently, the DAS technology is undergoing field trials, while DCS is in an early derisking phase.
The Trend Toward Shale Oil
Authors: Beckwith Robin 
Published: February 2015

The “shale gale” is not all about natural gas. While US shale gas drilling continues, it now is primarily to hold acreage and build gas reserves. As illustrated in Fig. 1, there is a definite trend in the US away from natural gas to crude oil. Many companies have pulled rigs from development drilling in gas shales to explore wet gas and oil-bearing shale plays. Lured by the prospect of high-value oil, whose margins promise a much higher return than those for natural gas, shale oil in US plays like the Bakken, Eagle Ford, Niobrara, Leonard (or Avalon), and Monterey is being extracted from low-permeability rock in increasing quantities.
For example, while 33 permits were issued in 2008 for drilling in the Eagle Ford Shale, for the first 11 months of 2010, 1,018 permits were issued. Oil and condensate production has also sharply increased in the Eagle Ford, from a combined 0.8 million bbl in 2009 to roughly 3.9 million bbl in the first 10 months of 2010. A recent study—“The Economic Impact of the Eagle Ford Shale,” prepared by the Center for Community and Business Research, University of Texas at San Antonio—forecasts annual Eagle Ford oil production at 15 million bbl for this year, rising consistently until 2020, when it is projected to reach 111.5 million bbl.
In 2008, the US Geological Survey estimated that the US portion of the Bakken formation contains between 3 billion and 4.3 billion bbl (a mean of 3.63 billion bbl) of undiscovered, recoverable oil, ranking it among the largest US oil plays ever. Production in 2009 reached nearly 8 million bbl per month from roughly 4,500 producing wells. Oil production in North Dakota—in the heart of the Bakken—increased from 35 million bbl in 2005 to nearly 80 million bbl in 2009.
Technology Is the Enabler
“The technology drivers that lifted gas recovery from 1% to 50% in the Barnett,” stated Apache global technology consultant George E. King, “will ultimately be the springboard that drives oil recovery from the initial 1% to 1.5% in the Bakken and Eagle Ford oil-producing shales to much higher values.”
Continental Resources, the number one driller and lease holder in the Bakken as of November 2010, with 864,559 net acres, has been driving its production upward with advances in technology. For example, in 2009, it per-formed the first 24-hour continuous hydraulic fracture in the North Dakota portion of the play. In 2010, Continental developed a drilling concept it calls the Eco-Pad, whereby the company drills multiple horizontal wells from a single pad with zero boundary-line setbacks. This concept is expected to reduce drilling and completion costs per well by approximately 10%, with about 70% less surface footprint area than four conventional drilling pads and only one access road.
Recent Developments and Remaining Challenges of Enhanced Oil Recovery
Authors: Pope Gary A. 
Published: February 2015

R&D Grand Challenges - This is the second in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE R&D Committee. The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series are examining each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).
The world is changing. Some look back and some look forward. Some look at the challenges of ramping up enhanced oil recovery (EOR) in the past and some look at the opportunities for doing so now. This article will provide a broad view of recent developments and the remaining challenges for readers who are not EOR specialists.
There has been a renaissance in chemical EOR during the past few years because of major advances in the technology and high oil prices. Thermal and miscible gas methods are much more mature with the exception of processes such as co-injection of gases and surfactants for mobility control. The synergy between the EOR processes and improved reservoir characterization and formation evaluation, reservoir modeling and simulation, reservoir management, well technology, production methods, and facilities is significant and not as widely recognized as it should be.
Polymer flooding is the simplest and most widely used chemical EOR process. Polymer flooding has been used commercially since the 1960s; more oil is produced by polymer flooding than all of the other chemical EOR processes combined. Adding polymer to the water increases its viscosity. The benefit of polymer flooding increases as the oil viscosity and/or the reservoir heterogeneity increases. Polyacrylamide copolymers or hydrolyzed polyacrylamide (HPAM) polymers are by far the most widely used polymer for EOR. Much higher molecular weight HPAM is now available than when it was first used in the 1960s and 1970s. The quality of commercial HPAM polymer has also improved dramatically and the price relative to crude oil has decreased. In the early 1970s, oil sold for about USD 3/bbl and HPAM polymer for about USD 1.50/lb. Now oil is about USD 100/bbl and HPAM stays about the same price.
About 1 to 2 lbs of polymer are needed to produce an incremental barrel of oil, which means the polymer cost is about USD 1.50/bbl to USD 3/bbl. This helps explain why the number of polymer floods is increasing exponentially and about 1 billion lbs of polymer will be used for EOR this year. Most early polymer floods were done using very small amounts of polymer (i.e., low polymer concentrations and small pore volumes of polymer solution), but now we know polymer floods perform much better at large polymer concentration.