bluuebunny/crossref_metadata_2025 huggingface dataset:
Benchmark Helps Select Best Technique for Sand Control in Field Development
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper IPTC 16449, ’Production-Integrated Sand-Control Benchmark for Field Development,’ by Keng Seng Chan, SPE, Danny Chong, SPE, Rahim Masoudi, SPE, Mohamad B. Othman, SPE, and Norbashinatun Salmi Bt M. Nordin, Petronas, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

This paper shares the engineering approach used to determine where and when sand control was needed in offshore Malaysia on the basis of geomechanical sand-free critical-drawdown-pressure (CDP) evaluation for the selected well type, configuration, and completion. The decision to implement a proper method of sand control can be made by comparing the CDP with the minimum drawdown pressure (MDP) required to meet the target production rate. Sand-control-method selection was based not only on the sand-particle-size distribution, well life, and mode of well production but also on maximizing oil and gas recovery per well.

Introduction

The challenge in Malaysia was to design and implement a sand-control completion that could maximize well productivity with a stable wellbore under perceivable changing offshore production conditions implemented at the lowest cost.

The objectives of setting up the sand-control benchmark for the Malaysian field were

To reduce the sand-control completion costs by greater than 50%

To drive a sand-control well-design culture change for developing cost-effective well completions for sandstone reservoirs

To determine selectively where, when, and what sand control is needed in the developing reservoirs

To enable well-placement and reservoir-penetration-trajectory design to maximize sand-free-production drawdown pressure

To optimize the use of expensive sand-control methods

To estimate sand critical erosion pressure drawdown

Fig. 1 shows a carefully developed workflow.

Maximizing CDP

For a well designed to penetrate target reservoir sand, the sand-free CDP should be evaluated for the entire potential producing interval following the designed reservoir-penetration trajectory. Because the geomechanical properties change with pore pressure, this evaluation must be conducted for the whole life cycle.

For cased-hole completion, perforation orientation and phase angle can be optimized to increase the CDP. More effectively, CDP can also be increased by increasing well inclination for the same sand.

In some sands, the CDP can be affected strongly by water production. After water breakthrough, the rock strength and friction angle that affect sand consolidation and stability of sand structure at and near the wellbore may be dramatically reduced. Moreover, when formation sands contain significantly high amounts of water-reactive shale, the whole wellbore can collapse. CDP can then become very small, or even zero. High pressure drawdown could cause wellbore and even completion mechanical failure.
Comments: OPEC Turns 50
Authors: Donnelly John
Published: February 2015

Editor's column

Fifty years ago, the heads of state of five countries—Saudi Arabia, Iran, Iraq, Kuwait, and Venezuela—signed an agreement in Baghdad that would significantly change the way oil is produced, priced, and traded. In a celebration marking OPEC’s half-century, the organization claimed that, despite its obituary having been written numerous times over the years, it had succeeded in achieving its original pledge to “stabilize oil prices in international oil markets with a view to eliminating harmful and unnecessary fluctuations.”

Said current OPEC Secretary General Abdalla Salem El-Badri: “The 50 years have seen various ups and downs, but the organization has remained true to its original goals of safeguarding the interests of its member countries, securing a steady income to producing countries, ensuring efficient and regular supply of petroleum to consumers, and a fair return to investors at fair and acceptable prices.”

OPEC may not dominate headlines like it did during the 1970s’ oil embargoes that quickly got the consumption-rich West’s attention, but it remains relevant and will continue to play a leading role in the oil market in the future. Last month, the organization approved a new Long-Term Strategy, its first in 5 years, in the face of a changing oil outlook. The group also agreed to hold its production steady, leaving output quotas unchanged since December 2008. Then, OPEC announced the last in a series of production cuts designed to revive oil prices that had dropped from USD 140/bbl to USD 34/bbl. The plan worked, with oil prices seemingly stable for now in the USD 70–80/bbl range despite global economic weakness. OPEC’s forecast now sees only a slight increase in global oil demand over the next 2 years, with growth coming from China and other developing countries.

The group will face challenges ahead and the country where the organization was created may prove to be its biggest headache. Iraq produces 2.3 million B/D now but has plans to rapidly ratchet up production to rival Saudi Arabia’s 8 million B/D and then eventually reach 12 million B/D. That is provided the country can rebuild its infrastructure, which severely limits such output gains, but the country just last month dramatically increased its estimate of proven oil reserves to 143.1 billion bbl, up from a previous 115 billion bbl. Any increase in Iraqi production would wrest market share from other OPEC producers, which could lead to infighting.

Challenges will also arise as the world looks more to natural gas and alternative fuels for energy. But hydrocarbons will still play a major role in energy supply for years to come, and OPEC member countries hold three-quarters of the globe’s reserves. Ian Skeet, a former Shell executive and author of a book on OPEC’s first 25 years, said about the future oil market then what is likely true today: “What can be said is that the international oil trade will continue, that the main supplier of that trade will be the countries which today form OPEC, and that Saudi Arabia will remain the single most important influence on oil price.”
Techbits: Drilling Technology Advances Reviewed in Workshop
Authors: JPT staff _
Published: February 2015

Techbits

In response to the fact that drilling engineers are constantly challenged to reduce well costs regardless of the economic climate, SPE held an Applied Technology Workshop (ATW) titled “Advances in Drilling Technology and Performance: Drilling the Limit” in Abu Dhabi earlier this year. The 2-day ATW brought more than 117 professionals from 39 international companies together to discuss the tools and techniques that have successfully reduced drilling capital expenditure and the gaps that still need to be addressed.

Improving Drilling Performance

Two technical sessions reviewed the industry’s progress in implementing the techniques and tools that enable full optimization of the drilling process. An ultimate aim of optimization—being able to drill all sections with one bit run—affords economic advantages as well as positive impacts on health, safety, and environment. The sessions provided several examples of where drilling optimization has been achieved.

Fred Florence of National Oilwell Varco discussed the new generation of drilling rigs powered by alternating current (AC). Florence said that new build trends are showing a shift to AC rigs, both on- and offshore, thanks to benefits that include increased top-drive motor speed and greater torque advantages over direct-current drives. In addition, AC rigs are inherently simpler machines, having lower weight and requiring less maintenance. They also lend themselves to easier automation, which improves performance and safety and gives process consistency with less risk.

A challenge Florence highlighted was that AC drives and automation add new components such as sensors, multiplexed signals, computers, networks, and variable-frequency drives, which require suitably trained and competent people. Those drilling contractors that are embracing AC rigs into their portfolios are seeing increased value due to reduced well costs and drilling time. Operators are also recognizing their value and are rewarding it through more contracts for AC rigs.

Tarek Mourad of Halliburton next reviewed the limitations of radioactive sources for various measurement-while-drilling technologies. Mourad cited telemetry limitations of current sources, which prevents a vast amount of data from being pulsed to the surface while drilling and limits a driller’s ability to make decisions that can optimize well placement and maximize the wellbore’s contact with the reservoir. He acknowledged that progress has been made in the areas of downhole analysis and computation, such as pressure sampling and imaging, and noted that work is progressing in the areas of increasing the speed of telemetry codes, electromagnetic-telemetry development, and wired drill pipe.

Other limitations include battery depletion, which is tied to the number of hours that the pumps are off and mud is not pumping, and limited memory size, which is based mainly on high sampling rates. Both of these limitations may necessitate extra trips downhole, which increases costs and safety risks.
Thirty Years of Gas-Shale Fracturing: What Have We Learned?
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 133456, ’Thirty Years of Gas-Shale Fracturing: What Have We Learned?’ by George E. King, SPE, Apache Corporation, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed.

Although high gas-flow rates from shales are a relatively recent phenomenon, the knowledge bases of shale-specific well completions and fracturing and shale-well operations have been growing for more than 3 decades, and shale-gas has been produced for more than 190 years. During the last decade, projected recovery of shale gas in place (GIP) has increased from approximately 2% to estimates of 50%, mainly through development and adaptation of technologies to fit shale-gas developments. This work surveyed more than 350 shale completion, fracturing, and operations publications, linking geosciences and engineering information together to relay learnings that will identify both intriguing information on selective opening and stabilizing of microfracture systems within the shales and new fields of endeavor needed to achieve the next level of shale-development advancement.   

Introduction

The first lessons from this study were:

No two shales are alike. Shales vary areally and vertically within a trend, even along the wellbore.

Shale “fabric” differences, combined with in-situ stresses and geologic changes, often are sufficient to require stimulation changes within a single well to obtain best recovery.

Understanding and predicting shale-well performance require identification of a critical data set that must be collected to enable optimization of the completion and stimulation design.

There are no optimum, one-size-fits-all completion or stimulation designs for shale wells.

Although gas-shale-completions literature is developing rapidly, the history of gas-shale research offers a starting point that can help explain many phenomena seen in shales worldwide. Of the more than 350 references reviewed for this report and the 250 included, more than 60% date from 2007 or later, and learnings are increasing rapidly. The full-length paper seeks to define many of these advances and associates the references. This work is not about any single shale; rather, it focuses on characteristics within shale that can be addressed with completion, stimulation, and production technology to create opportunities for increasing gas recovery. The objective of this paper was to compile, explain, and link as much usable information as possible on the topics of completion, fracturing, and production behaviors.
From Bacteria to Barrels: Microbiology Having an Impact on Oil Fields
Authors: Rassenfoss Stephen
Published: February 2015

The science behind the use of microbes to enhance oil recovery has advanced significantly, but it suffers from old associations.

After decades of trial and error, those working on microbial enhanced oil recovery have identified the “oil-eating” bacteria that laboratory tests suggest can change the properties in an oil reservoir, and know better how to put them to work. The increasing knowledge of the role microbial life plays in oil and gas reservoirs has also led to new approaches for controlling corrosion, managing bacterially produced hydrogen sulfide, and creating natural gas from coal.

(In this story, “eat” is used to describe the metabolic processes of bacteria. For instance, oil eating is more precisely hydrocarbon oxidizing.)

But the greatest potential payoff and the most debate come from the idea of microbes for enhanced oil recovery (MEOR). “There is a much greater understanding of what microbiology is doing in a reservoir” and how that can be used to produce more oil, said Stuart Page, chief executive officer of Glori Energy, a company that has staked its future of convincing the industry that microbes can be used to recover more oil.

MEOR is still often associated with promoters promising better oil production by dumping molasses into oil wells. “From a historical point of view, it is seen as snake oil,” Page said.

The image is darker than the history, which has been more hit and miss. For those in small companies, such as Glori, and big ones, such as Statoil, the challenge has been convincing experts in the field that promoting bacterial growth can be a consistent and effective way to produce more oil.

Work on using microbes to find oil goes back further than seismic imaging and the history of MEOR goes back more than 50 years.

Claude ZoBell, the scientist hired by the American Petroleum Institute who first discovered the microbiological ori-gins of oil, patented his MEOR concept in 1957. His approach involved introducing high-performing bacteria into a reservoir. It is one of many that has been tried and failed as people slowly came to better understand the exotic life in reservoirs.
Interest Grows In Asia Pacific Offshore Projects
Authors: Parshall Joel
Published: February 2015

The vast horizon of the Asia Paciﬁc offshore region is a diverse and dynamic arena for oil and gas development, one of contrasts, complexities, and challenges. While there is no overriding theme such as the tremendous reserves of the Middle East, or bold new story as in the Brazilian pre-salt or North American tight shale, Asia Paciﬁc offshore is one of the world’s most active hydrocarbon provinces. More than 55% of the global oil and gas heavy lift vessel ﬂeet* operated in the region at some point during 2010, according to IHS’ ODS-Petrodata unit. Asia Paciﬁc offshore has the resources, commitment of its resource owners, and economic drivers to remain a major factor in global petroleum development for decades.

It is tempting to view the Asia Paciﬁc offshore as one large emerging market. Yet it is more than that. Countries such as China and Vietnam, which once were closed to most outside capital investment, are clearly open for business. Future oil and gas growth opportunities—though not necessarily the same for both countries—appear to have few limits. But then there is Indonesia, which certainly ranks as a mature province. A longtime oil exporter, it withdrew from OPEC in 2008 after becoming a net importer. Yet Indonesia is anything but a fading star. Projects such as Gendalo-Gehem and Abadi have technologically sophisticated development plans to meet major technical and commercial challenges, and the East Natuna project targets gigantic natural gas reserves—although accompanied by massive levels of CO2. Success in these and other projects could help Indonesia move closer to self-sufﬁciency in petroleum supply.

Challenges of many types face offshore projects throughout the Asia Paciﬁc region. Industry interest in the area is “quite strong,” according to Dylan Mair, director of Far East information and insight at IHS. “Historically, the big companies moved out of Asia and into exciting places like Brazil,” he said. “What we will probably see in the near future is these IOCs (international oil companies) moving back in. You’ve seen some movement already with the independents. The supermajors have also gotten involved in unconventional hydrocarbon plays where there is a need for external expertise to assist the efforts of the NOCs (national oil companies).”

Not all of the challenging projects are large. The critical need for petroleum to fuel regional growth adds an incentive to unlocking ways of commercializing smaller, often remote accumulations of gas. 

Angus Rodger, Southeast Asia upstream analyst at Wood Mackenzie, described the region’s project environment thusly: “The low-hanging fruit is gone, and newer developments are located in more remote, frontier areas, deeper waters or require tackling more challenging geology. Usually, all of these challenges come together.”
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.
Emerging Frontiers: Keeping Up With Emerging Communication
Authors: Spath Jeff
Published: February 2015

President's column

In this first article on technological frontiers, I will focus on the ways in which modern knowledge-transfer avenues are impacting the industry and, more specifically, SPE. While communication methods like social media have been in our vocabulary for years, their presence is now ubiquitous in our workplace and, more recently, on our mobile devices. Just look at how social media and mobile devices are now being used as tools to disseminate information about current events.

Beyond using the various social media methods “socially” and for news, the technologies behind the methods are changing the way we work. It is estimated that the number of social network users around the world will increase 18% from 1.47 billion in 2012 (eMarketer newsletter, 18 June 2013) to 1.73 billion this year. Granted, some of this could be posting our latest travel pictures on Facebook or tweeting about vacations, but I see engineers, particularly young professionals, or the “Sony” generation as I like to call them, writing blogs on their specific engineering issues, posting comments on The Way Ahead Facebook page, and using many other of SPE’s social media platforms.

As the use of social media has grown among our members, SPE has recognized the need to create and engage with members through social media outlets. With the evolving crew change, it is important that we reach and share with members, particularly young members—where they are and where they expect us to be. Building and maintaining social media platforms are necessary to engage with membership.

In line with SPE’s mission to collect, disseminate, and exchange technical knowledge, our social media channels serve that purpose while also allowing SPE and its members the platform to engage, share, learn, and interact with sections, chapters, companies, and industry enthusiasts from around the world. From showcasing the latest news in our flagship magazine, JPT, to highlighting student chapters, to what one can expect at an upcoming event, to who will be instructing training courses, SPE’s social media channels are designed to communicate all things SPE.

SPE Social Media

Our social media channels are varied, with each serving a different purpose. Facebook is the hub, where SPE activities are shared directly with more than 32,000 connections. With a following consisting predominantly of university students and young professionals, a recent Facebook posting about why people chose a career in the oil and gas industry sparked a lot of comments about the great benefits of working in the industry. The post was viewed by more than 11,000 people. At a time when the industry is in need of talented young people, it is exchanges like this that will help communicate the benefits of the industry and reach the level of human resources needed to meet future demand.
Degradable Frac Ball Holds Solution to Persistent Problem in Fracturing
Authors: Aviles Isaac , Dardis Michael , Marya Manuel
Published: February 2015

Technology Update

A highly efficient and popular technique for multistage fracturing involves placing a completion string in the open hole with a series of ball-actuated stages isolated by hydraulically set or swellable packers. This practice has been instrumental to the increase of activity in hydrocarbon-bearing reservoirs, as it allows continuous operation while performing a large number of stimulation treatments.

When using this technique, sections of the reservoir can be selectively accessed by pumping actuators, or frac balls, from surface that land on correspondingly sized seats that have progressively larger diameters as operations advance from toe to heel. When all stages have been treated, the well is allowed to flow back, flushing the balls back to surface where they are caught in a ball trap.

Despite more than a quarter of a million stages that have been treated using the sliding sleeve technique, the results are not always up to expectation. Operators have experienced sub-optimal production from wells in which logs and tests indicated high productivity. In searching for a root cause, it has been discovered that often not all balls are recovered. Further investigation has sometimes found that balls may have deformed and become jammed in their seats, plugging all production from beneath. The only solution is to trip into the well and mill out the seats.

Aside from the added cost and risk, the challenge is that this undesirable situation is difficult to identify because other reservoir problems that milling will not solve can present a similar production profile. This adds uncertainty to any decision to mill out the system.

Frac balls are typically made from phenolic or composite materials. The composite material is laminated and, depending upon the orientation of the laminar planes, it can fracture when it seats and is subjected to additional hydraulic pressure during fracturing operations. If the ball fractures before it has served its purpose, the entire job may be jeopardized. Both types of balls are subject to deformation, often referred to as egging, when under pressure (Fig. 1). Slight egging can cause the ball to stick in the upper seats when the well is put on production, or the ball can jam itself into the seat so tightly that the only way to remove it is by milling. A stuck or jammed frac ball acts as a permanent isolation point for all treated stages below it.
Improved Matrix Body Design: Five Factors to Achieve Exceptional Bit Performance in Hard, Abrasive Rock
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

Matrix body bits are known for longevity and reliability in challenging formations such as granite, chert, and abrasive sandstones and conglomerates. What is often missing from bit performance under these conditions is the ability to maintain a relatively high rate of penetration (ROP) while maximizing footage drilled in one run. The goal remains the same: Drill every interval in one run at the optimal ROP. In other words, the bit should not be the limiter when it comes to drilling performance.

Focusing on five key factors that contribute to ROP and longevity, a major bit supplier has designed a matrix body fixed-cutter bit that is setting records in a wide range of fields and formations. The whole is greater than the sum of the parts: The five new technologies comprising the design work to create a significantly higher standard of performance than is typically accepted for hard rock/abrasive rock drilling.

The examples following represent distinct formation types such as sand and shale intervals in the Rockies, limestone and sandstone in east Texas, the Granite Wash formation in the Texas Panhandle, and limestone and dolomite in the Permian Basin.  All of these examples are laden with transition zones and most include conglomerate or other challenges to impact and abrasion resistance.  The bits have been run in conventional and motor applications with equally good outcomes.

Five Performance Factors Cutters. A critical improvement to the new bit design is the polycrystalline diamond compact (PDC) cutter technology. The proprietary interface design of the cutters used provides an extremely durable and efficient cutting element, removing significantly more rock with substantially less wear.

Furthermore, increased abrasion resistance in PDC cutters also increases the ability to withstand intense heat situations, contributing to thermal stability. While both thermally stable bits and abrasion-resistant bits perform similarly at the start of drilling, as cutter wear begins, the thermally stable products wear more slowly.

Ongoing research into wear mechanisms has optimized abrasion and impact resistance, and advanced the vital performance criterion of thermal mechanical integrity (TMI), or resistance to heat-generated wear. With greater TMI, the new cutters are highly TMI-qualified, able to withstand the extreme temperature cycling that occurs during drilling to provide greater strength and durability.