bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Compatibility of Drilling Fluid, Completion Fluid, and Other Well-Treatment Fluids for Deepwater Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141513, ’Chemical Additives for Improving Compatibility of Drilling Fluid, Completion Fluid, and Other Well-Treatment Fluids for Deepwater Wells,’ by Xiaoping (Victoria) Qiu, SPE, Lee Morgenthaler, SPE, Eddy Martch, SPE, Hiep Vu, SPE, Mootasem Chtay, and Vanessa Farrell David, Shell International E&P, prepared for the 2011 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, 11-13 April. The paper has not been peer reviewed.
In Gulf of Mexico (GOM) deepwater completions, synthetic-based mud (SBM) has been used widely for drilling the reservoir section. With increasing well depth and higher reservoir pressure, higher-density drilling fluids are used. It has been observed that with the increased density of drilling fluid, the incompatibility of drilling fluid, completion fluid, and other well-treatment fluids can cause additional problems in drilling and completion activities. Often, the formation damage caused by such incompatibility can be very difficult to remediate. Chemical additives were studied for preventing this incompatibility between drilling fluid, completion fluid, and other well-treatment fluids.
Introduction
In deep water, wellbore cleanup is critical for drilling and completing wells. There have been cases in the GOM in which several extra days were needed to achieve acceptable cleanup. Also, when displacement is not effective, mud residue may cause formation damage in the subsequent well completion. One displacement problem is that when completion brine or spacer fluid is mixed with SBM, the mixture may form very viscous, paste-like materials that are difficult to displace or can cause problems with shaker operations.
In addition to mud displacement, the compatibility of SBM and injected fluids during frac-pack operations is important. Sometimes, loss of whole mud into the formation is unavoidable when drilling and completing a well at overbalanced conditions. The mixture of SBM and completion brine lost into the reservoir may become viscous and difficult to break and flow back. Injected frac-pack fluid or gravel-pack fluid also might contact the mud and form mixtures that are difficult to move and can reduce well productivity.
In GOM well-completion operations, acids are sometimes pumped before the frac pack or gravel pack to clean up the post-perforation pill and to help clean up the perforations to improve fluid injectivity. Incompatibility of SBM and acids can affect well productivity significantly. Also, HCl, organic acids, and mud acids (such as HCl/HF or organic-acid/HF acid blends) may be pumped to clean up perforations or near-wellbore damage before the frac-pack fluid is injected. If mud remains in the wellbore or if SBM is lost to the reservoir, acid may come into contact with the SBM, resulting in the viscous paste-like mixture that is worse than the mixture of SBM and brine or SBM and spacer fluid.
Technology Focus: Gas Production Technology (November 2011)
Authors: Wilson Scott J. 
Published: February 2015

Technology Focus
It was not long ago that finding a natural-gas field beneath your property was viewed universally as a stroke of good luck. Now, local natural-gas development is feared by many who assume the “new technology” of “fracing” is environ-mentally harmful. In reality, the first hydraulic-fracturing treatment was tested in a North Carolina granite quarry way back in 1903. Hydraulic fracturing has been used successfully in more than a million wells since then, and, currently, hundreds of fracturing stages are pumped every day. Very impressive for a “new” technology!
Partly because of these very successful and trouble-free wells, natural gas has enjoyed an enviable reputation as a clean, cheap, and abundant energy source. However, we need only to look to the nuclear industry to see that a hard-won reputation can be ruined by false rumors, isolated incidents, or the worst examples of safety, environmental, and reporting practices. If we always strive to be good neighbors in the communities in which we work, we can remain proud natural-gas producers for years to come.
Because stimulated wells make up an increasing portion of supply with each passing year, we have become dependent upon wells that require additional attention and often exhibit high decline rates. To buffer the supply/demand swings, gas-storage wells are used for both injection of dehydrated pipeline gas and production of newly saturated formation gas. Water-vapor equilibrium will reduce the water saturation around injection wellbores but may increase salt precipitation in the same region. A new study from the Middle East describes a means of maximizing sand-free gas-production rates from wells in unconsolidated zones, without a difficult-to-place hydraulic fracture. A third paper describes a means of identifying well candidates that may need a second treatment because of deterioration of the original fracture or the need to access additional reservoir. A downloadable full-length technical paper provides a new decline-curve functional form that can match unconventional wells with long transient-flow periods while honoring late-time interference and depletion. These papers provide some legitimately new technology.
Gas Production Technology additional reading available at OnePetro: www.onepetro.org
SPE 137748 • “Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs” by Anh N. Duong, ConocoPhillips. (See SPE Res Eval & Eng, June 2011, page 377.)
SPE 142283 • “Effect of Water-Blocking Damage on Flow Efficiency and Productivity in Tight Gas Reservoirs” by Hassan Bahrami, Curtin University, et al.
SPE 139260 • “Production Allocation in Multilayer Gas-Producing Wells Using Temperature Measurements (by Genetic Algorithm)” by Reda Rabie, SPE, Cairo University, et al.
The Challenges of Reusing Produced Water
Authors: Whalen Tom 
Published: February 2015

Guest editorial
Reusing produced and flowback water in hydraulic fracturing operations appears to be a win-win proposition by transforming the industry’s biggest waste product into a resource, with the added benefit of reducing our environmental footprint. The economics are right. Scores of successful projects prove that produced and flowback water can be treated at a lower cost than acquiring and using fresh water. And the treatment technology certainly exists. The oil field is overrun today with companies claiming to have all manner of technologies to treat water.
So, if it is such a good idea, why has the industry been slow to embrace reusing produced and flowback water? Perhaps because it is not as simple as it seems. The challenges are organizational, emotional, and technical.
Few oil companies are organized to recognize the total cost of water. Sourcing, transporting, storing, and treating fresh water and then constructing disposal wells, maintaining that infrastructure, and transporting and disposing of produced water is rarely managed from a central group. Typically, field operations are financially responsible for sourcing water, but the costs of disposal are managed elsewhere in the organization. This division of responsibility creates a false economy for water, artificially lowering the price, and distorting the true cost.
Some operators also are anxious about reusing produced water if they do not feel confident that it will meet the performance requirements of the fracturing fluid or preserve the integrity of the reservoir. Plus, there is some resistance to building the infrastructure to collect, treat, and reuse produced water.
Reusing produced water is more technically complicated than just pulling up to a wellsite with a treatment system. The chemistry of these waters is complex and specialized expertise is needed to successfully treat produced water and formulate a productive fracturing fluid, while protecting the integrity of the wellbore and the reservoir. It takes in-depth analysis of the water to determine what constituents must be removed and/or what additives are necessary.
But, as an industry, we are naive if we think the decades-old strategy of sourcing fresh water and then disposing of produced water is sustainable. A growing list of regulations will force us to look for alternatives.
The US Environmental Protection Agency estimates that 140 billion gallons of water are needed annually for hydraulic fracturing operations in the United States alone. While that is just a fraction of the total US water usage, our industry is becoming a lightning rod in the water use debate. Add to that the growing concern about bourgeoning truck traffic on local roads and the seismic activity often blamed on high-pressure wastewater injection into disposal wells, and you have an environment ripe for regulation proliferation.
Switch: The New Documentary on Energy's Future
Authors: Beckwith Robin 
Published: February 2015

Switch documentary
How will the switch to cleaner energy sources occur? This is the basic question Scott Tinker, director of the Bureau of Economic Geology and Allday Endowed Chair professor at The University of Texas at Austin, explores in the documentary film, Switch, which he co-produced and in which he is featured as interviewer and narrator. Attendees at this year’s SPE Annual Technical Conference & Exhibition (ATCE) enjoyed a complimentary screening of the film Monday evening, 8 October. In addition, Tinker delivered the keynote presentation at the SPE Research & Development (R&D) Technical Section annual meeting, held at ATCE the evening before.
The quest Tinker embarks upon in Switch is one of keen interest to those involved with energy R&D, because both the continued cost-effective exploitation and delivery of fossil fuels as well as the search for alternative sources of energy depend on innovations in technology.
The documentary follows Tinker as he travels the world to discuss “the switch,” giving us along the way an inside look at all the major types of energy—hydro, coal, crude oil, biofuels, natural gas, geothermal, solar, wind, and nuclear.
Geology Is Destiny
Starting with “one of the most successful energy transitions in the world … , energy so clean you can drink it,” Tinker explains that Norway’s geology is why it can generate 99% of its electrical power from hydro. In fact, a country’s geology proves critical in determining its ability to transition from electricity’s mainstay—cheap and abundant coal. As Tinker says in the film, “Take massive global fuel supply, combine it with fast, simple power generation, and you get the cheapest electricity in the world. That’s why we’re still hooked.” Getting unhooked is difficult, given our species’ large and growing presence, as well as the push for a greater proportion of people to participate in the lifestyle benefits that accrue from energy use.
The logistics of maintaining while also continuing to build a global system of transport, communication, and comfort for humans is formidable. The massive physical infrastructure changes, capital equipment costs, and economic consequences involved in a global energy switch make its pace one involving decades or centuries rather than months and years. Switch gives us insight into the physics, economics, and scale involved in current energy supply and demand. An example is given early in the film of the scale involved in keeping the world supplied with energy. The annual volume of the material moved at the Belle Ayr Mine in the US Powder River Basin—the largest coal reserve in the world—is equal to three times the volume of the entire Panama Canal. And that is just one of the mines in the Powder River Basin.
Industry Must Earn Its License to Operate
Authors: Donnelly John 
Published: February 2015

Conference review
Earning a “license to operate” and creating a common health, safety, and environmental culture across the oil and gas industry were two of the dominant themes of the 2012 International Conference on HSE in Oil and Gas Exploration and Production. The conference was held in Perth in September and was jointly organized by SPE and the Australian Petroleum Production & Exploration Association (APPEA).
Panel and technical sessions covered numerous aspects of the broad discipline, which encompasses HSE, social responsibility and management issues, and featured contemporary topics such as produced water management, evolving human rights standards, climate change, and unconventional operations.
The conference’s opening keynote session featured Norman Moore, minister for Mines and Petroleum, Fisheries, and Electoral Affairs for Western Australia; 2012 SPE President Ganesh Thakur; APPEA chairman David Knox, who is also managing director and chief executive officer of Santos; and Melody Meyer, executive committee chairperson of the conference and president of Chevron Asia E&P.
Dangers of Complacency
Knox said that recent industry accidents are reminders of the dangers of complacency, while noting that lost-time incidents in Australia and elsewhere have decreased. “As a member of the oil and gas industry, I am often asked what keeps me up at night,” he said. “I can honestly say that it is the thought of something happening somewhere in our industry that results in a tragic event—an event that seriously injures someone, that kills someone, or that seriously harms the environment.”
Public trust is the oil and gas industry’s license to operate, Knox said. “It is what provides us with the permission for the business to act, to explore, develop and produce oil and gas resources that ultimately our host countries and communities depend on to prosper,” he said. “The risk is that our host communities look in the rear view mirror and see an industry whose track record in managing its impact on people and the environment is not acceptable. And as a result, their expectation of future behavior is questioned.”
Industry and regulators must find the right balance to ensure public safety while giving oil and gas companies the ability to succeed. “We need the balance between providing the community and governments with confidence in the rigor of oversight, while making sure regulation is not actually detracting from real performance and improvement,” Knox said. “Regulation in our industry can be effective. But it can be extremely effective if it puts the onus on the operators to demonstrate that they can operate safely.”
Nanoparticle Use in Drilling Fluids Can Effectively Reduce Permeability in Shale
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 157031, ’Application of Nanotechnology in Drilling Fluids,’ by Katherine Price Hoelscher, SPE, Guido De Stefano, SPE, Meghan Riley, SPE, and Steve Young, SPE, M-I SWACO, prepared for the 2012 SPE International Oilfield Nanotechnology Conference and Exhibition, Noordwijk, The Netherlands, 12-14 June. The paper has not been peer reviewed.
The potential to apply water-based drilling fluids confidently in unconventional shale formations has been studied using engineered nanoparticles to minimize shale permeability by physically plugging the nanometer-sized pores. Nanoparticle technology and testing protocols were developed using the Marcellus and the Mancos as shale candidates. Nanoparticles in this study are specifically designed to plug the nanometer-sized shale pores physically, thereby reducing pressure transmission in the shale.
Introduction
Silica nanoparticles are commercially available and can be engineered to meet all specifications needed for the purpose. The particle size can vary between 5 and 100 nm. The right sizes of nanoparticles can be selected, and, in combination with a correct fluid-loss package, the particles can minimize the fluid/rock interaction. Surface treatment on the nanosilica particle has been discovered to have a major influence on the final performance.
An investigation into using nanoparticles as a drilling-fluid additive to enhance wellbore stability has been successful. The nanomaterial works by virtually shutting off water movement between the formation and wellbore. In shale formations with nanodarcy permeability, such as the Marcellus, the usual drilling-fluid method of relying on a filter cake to reduce fluid loss (or leakoff) cannot be used because a filter cake may not form because of the extremely low permeability of the shale. The solution for this problem is to engineer a nanoparticle that will be added to the drilling fluid to plug the pores of the shale and shut off water loss.
Background
The hurdle to maintaining wellbore stability in shale formations is to control the water interaction with the rock. The water enters the shale through pores, which vary in size from approximately 3 to 100 nm, inducing fractures and, thereby, reducing the stability of the wellbore. By effectively plugging the exposed pores of the rock and not allowing water to enter, wellbore stability is retained. One conventional bridging theory is referred to as the one-third rule of filtration (Abrahm’s theory), where the material used to plug a pore is required to be approximately one-third to one-seventh of the size of median pore opening. There are other theories with varying size requirements for the plugging material; however, none is perfect. An ideal plugging material also will accommodate the variability in pores within the formation.
Pressure-Sink Mitigation for Horizontal Completions in the Haynesville Shale
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159089, ’Horizontal Pressure-Sink-Mitigation Completion Design: A Case Study in the Haynesville Shale,’ by Robert C. Martinez, SPE, Josh Rosinski, SPE, and Doug Dreher, SPE, Exco Resources, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.
Pressure sinks caused by production from an initial well can impair future completion effectiveness unless steps are taken to mitigate the effects. Pressure sinks exist in an area that was stimulated previously or has a reduced pore pressure, which then creates a path of least resistance for a subsequent nearby stimulation. Pressure-sink-mitigation (PSM) techniques are vital for successful Haynesville shale development. PSM techniques applied to Haynesville shale wells represent a potential breakthrough on how to mitigate the effects of pressure sinks effectively and increase the ultimate gas recovery of the unit.
Introduction
The Haynesville shale-gas play covers the east Texas/north Louisiana border area (Fig. 1). Hydraulic-fracture stimulation is critical to produce natural gas from the nanodarcy-permeability rock. Initial designs used a hybrid treatment (i.e., conventional job) that included a slick water pad followed by low concentrations of 100-mesh sand spaced with slick water sweeps. Fracture modeling showed that these hybrid treatments created very long fracture half-lengths. Fig. 2 shows how wells producing as far as 1 mile in an east-northeast/west-southwest orientation from an ongoing fracture treatment often would exhibit a pressure response during the fracture treatment of the offset well. This well interaction was the first indication that a hybrid slickwater treatment could be influenced by pressure sinks.
Early in the development program, 80-acre offset wells were drilled to evaluate infill-well performance. A conventional completion design and a PSM design (PSM 1) were used on the off-set wells, and performance was reduced significantly. This reduced performance was not limited to 80-acre offset wells. When designing around pressure sinks, production from an existing well within a 1-mile radius could affect performance significantly, and could risk several wells in a development plan. Subsequent stimulations had a similar effect on offsets during and after the stimulation. It became apparent that different completion designs would be needed.
Lowered Tubing Offsets Field Production Decline
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154394, ’Lowering Tubing in the Jonah Field Offsets Production Decline,’ by Chinenye E. Ogugbue, SPE, Cody R. Hopkins, Leah R. Greenly, SPE, Robert K. Wilson, and Gordon E. Gates, BP, prepared for the 2012 Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, 5-7 June. The paper has not been peer reviewed.
Declining reservoir pressure and rate in the Jonah Field in the upper Green River basin in west-central Wyoming led to the common problem of liquid loading. Lowering the end of tubing (EOT) in more than 100 gas wells in the Jonah field enabled an average sustained production increase of approximately 105 Mcf/D, with an undiscounted payout of less than 12 months. In addition, for wells that have had the tubing lowered, the production-decline curves appeared to flatten out, offsetting anticipated double-digit decline.
Introduction
Discovered in the early 1990s, the Jonah field produces gas from the Lance formation, an extremely low-porosity, low-permeability, and fine-grained alluvial sandstone. The field is an overpressured area bounded on west and south by faults. The producing-formation thickness ranges from 2,000 ft updip to 3,500 ft downdip, at depths as shallow as 7,800 ft and as deep as 12,500 ft. Within this interval, the net-to gross-pay ratio varies from 25 to 40%. Sand bodies occur as both individual 9- to 15-ft-thick channels and as stacked-channel sequences, thicker than 200 ft in some places. Stacking of these alluvial-sand bodies resulted in an extremely heterogeneous reservoir in which reservoir sand bodies cover an areal extent of a few acres to as much as 640 acres. The field has been developed on 10-acre spacing. Wells are completed with eight to 16 hydraulic-fracturing stages, with each stage containing five to seven fluvial-sand-body channels. The Lance formation comprises the Lance Derbis Wedge, Lance Overpressure, Middle Lance, Jonah sands (Lance Jonah), Yellow Point sands, and the Wardell sands. The proven commercial gas-producing zones are the Lance Overpressure through the Wardell.
BP operates 262 wells in the Jonah field. The wells have total depths ranging from 10,500 to 12,800 ft, with an approximately 3,500-ft vertical section of thick continental deposit composed of fluvial sandstones, back-swamp shales, coaly shales, and thick braided-stream sandstones. Porosity ranges from 8 to 10%, with permeability equal to 1 to 10 d. The average initial 30-day production was 1.5 MMcf/D. The aver-age condensate yield is 8.5 bbl/MMcf, and the water yield is 5–10 BW/MMcf.