bluuebunny/crossref_metadata_2025 huggingface dataset:
Emerging Frontiers: Big Data!
Authors: Spath Jeff
Published: February 2015

President's column

“Big data,” once only the concern of database geeks or a marketing technique among retailers, is now part of our mainstream consciousness and vocabulary. Big data is having a profound impact on the upstream E&P industry as well.

What is “big data”? According to a McKinsey Global Institute report, “big data refers to datasets whose size is beyond the ability of typical database software tools to capture, store, manage, and analyze.” I like this definition because it does not require a dataset of any specific size. It allows datasets to increase as technology advances. This definition also varies to the extent that different industries have different standards of database and analytic software tools.

To get a feel for just how big data has become, consider recent rates of data growth. In 2012, disk drives worldwide added 7 exabytes (1018) of new data. Global data volumes are projected to increase 40% per year, while global information technology (IT) spend will grow only 5%. Thirty billion pieces of content are shared on Facebook each month. Or consider that Asia now leads the world in the generation and storage of personal location data due simply to the number of mobile phones—an estimated 800 million in China alone.

How mainstream has big data become? Consider these examples of wide-spread usage:

High-speed supercomputers statistically analyze massive amounts of data, enabling scientific breakthroughs such as the gene sequencing of individual organisms and entire ecosystems.

Coaxing the Higgs boson into a nanosecond of existence required the global distribution and analysis of roughly 200 petabytes of data.

Or, more familiar to most of us, retail organizations cleverly obtain our behaviors, preferences, and product perceptions by monitoring our Facebook and Twitter information.

The combination of massive amounts of data and sophisticated analytics is profoundly affecting a spectrum of industries, and oil and gas is no exception.

Big Data in the Oil Field

The amount of data that our industry acquires, communicates, stores, and analyzes is exploding exponentially. For example, the growth of land seismic acquisition is one of the most data-intensive phases of our industry. Channel count has roughly doubled every 3.5 years since 1970. Together with advances in the acquisition technology— which now measures vector information rather than scalar—the data acquired and stored in a typical survey has grown from gigabytes to petabytes. Furthermore, the growing popularity of permanently installed geophones for monitoring fluid fronts, passive monitoring of carbon capture sequestration sites, and observing microseismic events during hydraulic fracturing has driven an extraordinary and daunting growth in seismic data of all forms.
Robotic Roustabouts for Tomorrow's Subsea Fields
Authors: Jacobs Trent
Published: February 2015

Robotic submarines, capable of operating by themselves thousands of feet underwater for months or perhaps years at a time, are under development as the vanguard of tomorrow’s subsea oil and gas fields. This development comes as the offshore oil and gas industry moves into ever-deeper waters and remote areas of the world, where installing a floating production facility is either economically unjustifiable or infeasible.

The industry’s solution is to install production equipment on the seafloor, where someone, or something, must keep a close eye on all of it. That something is likely to be what are known as field resident autonomous underwater vehicles (AUVs). Nonresident AUVs have already paved the way by proving they can carry out detailed inspections of platforms and pipelines in some cases four times faster than a human-piloted remotely operated vehicle (ROV). Two of the leading companies in the resident AUV business, Lockheed Martin and Saab Seaeye, are blending proven military technology with new software and hardware optimized for the offshore industry. Their emerging systems represent a new breed of subsea robots that will be capable of much more than earlier generations of autonomous systems. As their capabilities are realized, resident AUVs will eventually be assigned many of the same tasks that ROVs are carrying out today.

To achieve that end, offshore operators are working with manufacturers to identify how best to fully deploy this emerging technology. Much of the groundwork is being laid through DeepStar, a research and development consortium that counts 11 operating companies as members. “We are already using AUVs for certain functions on a sporadic basis, but we’re trying to understand, as operators, what else this technology can do reliably,” said Greg Kusinski, DeepStar director and Chevron senior advisor to DeepStar.

DeepStar’s primary goal is to accelerate the development and adoption of AUV technology by drafting interface standards, similar to the standards already developed for ROVs. Among the interface issues yet to be resolved is how resident AUVs will connect to life support systems in a subsea field. Because resident AUVs will have to remain submerged for months to possibly years at a time, the docking station is a critical piece of equipment that will charge up the AUV and upload its data to the operator’s server by a subsea Internet connection.

Once the particulars of the docking station are understood, Kusinski said careful consideration must be given to other issues, such as where to place it among the subsea infrastructure. “There are a lot of questions of that nature,” he said. “As responsible operators, we are addressing these issues in a very systematic and methodical manner. I don’t think anyone is interested in putting a bunch of them down there and just seeing what happens.” DeepStar expects to conclude its AUV study on interfaces in about a year and will deliver its recommended best practices to the American Petroleum Institute for review.
Zonal Isolation Through Gas Hydrates Offshore Tanzania
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163462, ’Zonal Isolation Through Gas Hydrates Offshore Tanzania,’ by J. Volstad and T. Tveit, Statoil, and P. Aguilar, N. Hurtado, and M. Bogaerts, Schlumberger, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.

Deepwater cementing becomes increasingly challenging as drilling operations move to greater water depths and more-remote locations. Before the first exploration well for an operator offshore Tanzania was spudded, an extensive cementing-operations risk analysis was performed. The risks determined were low temperatures at seabed, unconsolidated formations close to seabed, potential shallow gas, and likely presence of hydrates. To drill further sections successfully, objectives were identified as zonal isolation across the shallow-flow and hydrate zones, cementing back to seabed, and good cement around the casing shoe.

Introduction

Block 2 (Fig. 1) is located southeast of Tanzania’s capital, Dar es Salaam. The water depths in Block 2 vary from 1000 to 3000 m. The target is an excellent-quality sandstone gas reservoir with very large potential. The seabed consists of soft clays and silts with minor sandy intervals. Shallow hazards were identified for this block from seismic data.

Preparation for the exploration phase started in 2007 when the license for Block 2 was awarded. Two exploration wells have been drilled in Block 2 offshore Tanzania to date. The wells were drilled in ultradeep water, with respective water depths of 2419 and 2627 m. Both wells were drilled successfully and have found commercial gas reserves.

Well Design

The well design for both wells was jetting a 36-in. conductor casing to provide sufficient well-bearing capacity. The surface casing was set deep enough to isolate all shallow zones with potential hydrates and shallow water and gas flow. The intermediate string was set above the top of the target reservoir, and the reservoir was drilled and plugged after the reservoir was evaluated. Both exploration wells were drilled vertically to total depth. The riserless section was drilled with seawater and water-based mud, while the deeper sections were drilled with a synthetic-based mud.

Challenges

The main challenges for the two wells were related to the great water depth (low fracture gradients and low temperatures) and the risk of encountering hydrates and potential shallow flows, which would need to be isolated by the surface casing.
Comments: Academic Leaders
Authors: Donnelly John
Published: February 2015

Editor's column

With sadness, we note the loss of two members who mentored countless students and colleagues during their distinguished careers on different sides of the globe. Kermit Brown, a longtime professor at the University of Tulsa and the University of Texas, died on 10 December at the age of 86. Ion Cretu, a professor and leader in the Romanian scientific community, died on 15 November. He was 76. Colleagues speak warmly of both men and the influence they had on them and others in the profession.

Brown was honored at last year’s SPE Annual Technical Conference and Exhibition with the JPT Legends of Production and Operations award. He was a noted authority on artificial lift and changed the way the industry viewed that technology, and contributed to the industry as an educator, researcher, and consultant in a career that spanned more than 50 years. He wrote portions of the Gas Lift Manual that transformed the way that technology was used and became the gas-lift authority in the industry. His book on nodal analysis is still widely used by those both inside and outside academia.

It was at the University of Tulsa that Brown had his biggest impact. Colleagues say he changed that school’s petroleum engineering department forever through his bold and innovative leadership. He started a doctoral program there, and he created a research model that other universities would later adopt. Brown developed a consortium in which oil companies would contribute a small amount of money each year and university faculty and students would conduct research of specific interest to the industry. The program put the department closer to the needs of oil and gas companies, benefiting students greatly in the process, and reduced the school’s reliance on government funding. Thorough his leadership, the University of Tulsa began its first research program, called the Tulsa University Drilling Research Project.

Cretu began working in 1958 with the Oil, Gas, and Geology Institute in Bucharest and then for the Petroleum-Gas University of Ploiesti as a lecturer, associate professor, and, beginning in 1978, as professor in the Department of Hydraulics, Thermotechnics, and Reservoir Engineering. He held numerous positions at the university during his academic career, including head of the department, vice dean and dean of the Well Drilling and Reservoir Exploration Faculty, and vice rector of the school. He supervised more than 45 doctoral trainees at the university.

He was well known in the Romanian scientific community, was widely published, and was active in the International Association of Hydraulic Research, the Romanian National Committee of World Oil Congresses, and the Scientific Council of the Ministry of Geology. Cretu also served as president of the SPE Romanian Section.
India's First Deepwater Offshore Field Showcases Ingenuity
Authors: Kulkarni Pramod
Published: February 2015

India’s first deepwater oil and gas field, located in the KG-D6 block 60 km off the east coast of India in the Bay of Bengal, is a success story of government initiative, private enterprise, and global engineering ingenuity. Operated by Reliance Industries, a multinational corporation based in Mumbai, KG-D6 is a world-class discovery at 1200-m depth with proved plus probable reserves of 11.3 Tcf. The fast-track construction of the oil and gas production facilities involved the mobilization of engineering talent, manufacturing capabilities, and construction skills in the US, Europe, the Middle East, and Asia (Fig. 1). In the process, the KG-D6 field has set numerous world records and milestones for India’s emerging oil and gas industry.

First Success of Licensing Round

The KG-D6 block was awarded in 2000 to a partnership of Reliance Industries (90%) and Niko Resources of Calgary (10%) in the first licensing round initiated by the government of India through its New Economic Licensing Program (NELP). Before NELP, India carried out E&P activities through public-sector companies such as the Oil and Natural Gas Corporation (ONGC). ONGC remains the leading operator in India, but eight rounds of NELP have opened the country’s oil and gas sector to a variety of other public-sector companies (Indian Oil, Hindustan Petroleum, Gujarat State Petroleum Corporation), international oil companies (Cairn Energy, British Gas, Eni), and Indian private companies in addition to Reliance (Essar, Jubilant).

Reliance Industries is an Indian conglomerate with extensive operations in the textile, petrochemical, and retail sectors with annual revenues of USD 28 billion. The company was launched in 1962 as yarn trading company by Dhirubhai Ambani. The growth of the company is a study in vertical integration. From yarn, Reliance built textile mills, petrochemical complexes, and entered the upstream oil and gas industry in 1999.

Deepwater Discoveries

The Krishna-Godavari (KG) Basin covers an area of more than 20 000 km2 on land and extends into the bay more than 24 000 km2 down a steep slope to 2000-m depth (Fig. 2). The Krishna and western part of the Godavari troughs are filled with mainly Paleozoic and Mesozoic sediments, while the eastern part of the Godavari trough contains a predominantly Upper Mesozoic and Tertiary section. The discovery of biogenic gas has been made primarily in the Upper Pliocene plays.
Spotlight Falls on East Africa as Activity Levels Rise
Authors: Sheehan John
Published: February 2015

West and north Africa have traditionally been the continent’s hotbeds of oil and gas E&P, but recent successes in east Africa may change that. Significant discoveries in the region, combined with a range of new opportunities through licensing rounds, are attracting new players to relatively underexplored countries such as Uganda, Kenya, Tanzania, and Mozambique.

Perhaps the most exciting development in east Africa has been Tullow Oil’s extraordinary success in and around Lake Albert in Uganda and the Democratic Republic of Congo (DRC). Tullow holds interests in three licenses on the Ugandan side of the Lake Albert Rift Basin in Blocks 1, 2, and 3A.

Since exploration drilling began in 2005, the Irish independent has had a near 100% success record discovering more than 900 million bbl of gross contingent resources over a range of 150 km in 15 separate fields. As Tim O’Hanlon, Tullow’s vice president for African business, explains, however, the development project is not without some unique challenges. “In Uganda and the DRC we are 1300 km from anywhere. While we have had huge potential displayed from this little basin, there is no doubt there are challenges. It is a tough project but the most interesting project Tullow has.

“We have got over 2 billion bbl in potential across the lake from highly productive reservoirs. We have flowed wells at 12,000–14,000 BOPD of light oil, albeit waxy, not unsurprisingly,” he said. “We also have some big reserves so far in individual pools. We have at least three fields with 200–300 million bbl each, so they are a great anchor that can kick off various development scenarios. With our partner Heritage we have invested USD 750 million here while in the process we have created wealth of over USD 50 billion for the country [Uganda].”

Tullow’s onshore drilling activity has focused on the Butiaba area of Blocks 1 and 2 in 2008 and 2009, where upside potential of more than 1 billion bbl of oil was identified and 11 wells drilled. Particularly significant finds were made in the Victoria Nile Delta play with 10 discoveries including Buffalo-Giraffe in Block 1, which has a continuous oil column of 459 ft (140 m) and very-high-quality sand-stone reservoirs.

In Block 3A, the Kingfisher-3 appraisal well was completed in December 2008, having encountered up to 131 ft (40 m) of oil-bearing sands in communication with those production tested in the earlier Kingfisher-1 and Kingfisher-2 wells. In Block 2, the initial Ngassa well encountered borehole instability when being drilled and a new location was identified to reduce the operational complexity of the well trajectory.
Distributed Downhole Measurements Describe Salt Drilling While Underreaming
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124121, ’Salt Drilling While Underreaming Behaviors Illuminated by Distributed Downhole Measurements,’ by B.J. Kull, SPE, and R.G. Duff, SPE, Chevron, and A.J. Clarke, SPE, D.G. Perez, and S.M.Stuart, SPE, NOV, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

Many developments in the deepwater Gulf of Mexico (GOM) target reservoirs below salt sections. Because well plans increasingly call for drilling through long salt sections, a common strategy in the GOM is to drill while simultaneously opening the hole with an underreaming tool. This configuration presents unique dynamic behaviors to the drilling system. Understanding the drilling system is important to reduce vibrations. Identification of drillstring dynamic behavior is critical.

Introduction

Deepwater GOM wells often require drilling through the salt canopy (Fig. 1). In some plays, subsalt targets equate to the majority of the well being placed in salt. Similarly, subsalt targets mean the wells may be very deep and therefore benefit from a large hole size to provide adequate clearances for deepening casing strings. Casing running in salt presents the added challenge of salt creep, often requiring oversized holes. A successful method to address the challenges of drilling deep wells through salt is simultaneously underreaming while drilling. The use of logging-while-drilling (LWD) and rotary-steering tools introduces constraints to underreamer placement and overall bottomhole-assembly (BHA) design.

Distributed measurement in drilling assemblies is an established method of investigation for the operator; however, this study is the first of its kind known for the deepwater GOM. Many directional-measurement schemes use measurements at several locations. Distributed vibration measurement often is achievable in a BHA using multiple LWD tools with vibration-logging capability. Vibration measurement complements avoidance of destructive vibration modes by supplying symptomatic information about the downhole dynamic conditions. When vibrations are high, anecdotal evidence is used to diagnose a dynamic condition. On the basis of that diagnosis, mitigation of the phenomenon may be attempted.

The operator currently is developing several fields that require drilling long salt sections. To optimize drilling and reduce overall development costs per well, understanding dynamic events and vibration limitations is a priority. The salt sections do not require much formation-evaluation data from LWD, so drill rates and tool-memory issues are not always a limiting factor in these sections. Similarly, the lack of permeability in salt reduces the need for controlled-drilling-rate operations because of equivalent circulating density (ECD). Underreaming presents unique challenges in all formations.
Technology Focus: Well Testing (February 2010)
Authors: Angeles Renzo
Published: February 2015

Technology Focus

The advent of computer-aided analysis, derivatives, and deconvolution over the last 3 decades produced a dramatic change in the way we looked at well testing: from a mere well-performance indicator to a powerful reservoir-characterization tool. Well testing is a technical “masterpiece” when it comes to the assessment and exploitation of complex reservoir architectures and frontier assets. Yet, multiple challenges lie ahead of us, from ultradeep wells to subsea subsalt developments with increasing environmental concerns; these are indeed exciting times for the field.

This brings me to the theme of this feature. Well-test analysis continues to push the boundaries of reservoir characterization on all fronts, leading to improved interpretation techniques for unconventional resources, intricate deepwater test programs, and accelerated use of high-resolution-simulation models. In the early 1960s, we would, literally, calculate permeability and skin by use of straight lines on a graph with a pencil. Nowadays, and with the help of better gauge metrology, we are opening a new chapter in the use of well testing for reservoir characterization and proactive field management. Some people have even suggested that we should expand the definition of well testing to include measurements other than pressure. Take, for instance, temperature. Technologies such as distributed-temperature sensing are maturing at a relatively rapid pace, bringing more insights into dynamic-flow description.

As well testing strives to advance and overcome the enormous challenges of today, we need to take a moment and peek outside our tree to see the forest. The papers selected for this feature and those in the reading list are a clear illustration of these latest endeavors. I hope that you will find them of interest.

Well Testing additional reading available at OnePetro: www.onepetro.org

SPE 123982 • “A New Pressure/Rate Deconvolution Algorithm To Analyze Wireline-Formation Tester and Well-Test Data” by Evgeny Pimonov, Schlumberger, et al.

OTC 19767 • “Use of Dynamic Simulation To Refine Well-Testing Procedures and Optimize the Data Required for Deconvolution Techniques” by J.C. Mantecon, SPT Group, et al.

SPE 124271 • “The Value of Well Testing—Optimization of the West Brae Field” by Mike Tharagonnet, SPE, Marathon Oil
En Route: Letter from Russia
Authors: Labastie Alain
Published: February 2015

President's column

I write this column from Moscow, where I am attending the 2010 SPE Russian Oil and Gas Exploration and Production Technical Conference and Exhibition (ROGC), a very successful event that demonstrates how well SPE activities are developing here. During the last year, I travelled several times to Russia for diverse reasons:

To attend a large conference (ROGC), with mostly Russian delegates but also a lot of international visitors;

To make contacts with companies’ headquarters, and their research branches, mostly in Moscow.

To visit oil-producing provinces—some very remote—and make contacts with local operations and our members there;

To visit universities in various parts of the country.

These trips gave me a broad set of perspectives. I learned a lot about Russia and the oil and gas industry there.

First, the country has an extremely rich cultural diversity, with a long and complicated history. Russia’s physical environment is beautiful, but difficult. I visited our Tyumen Section in western Siberia last winter, where temperatures were as low as –30°C. I was quite impressed to see how people adapt in such extreme conditions. Even in the coldest extremes, we always had an incredibly warm welcome from the people, who have a special sense of hospitality. SPE members are extremely enthusiastic; they are doing a wonderful job in organizing activities and promoting our Society. The student chapters are very active, and SPE is a really prestigious organization for them.

The Russian oil and gas industry is quite interesting. For historical reasons, Russian companies have developed their activities in the past century while staying widely isolated from the rest of the world, operating with different contexts and different constraints. As a result, many technologies developed in Russia are somewhat different from their counterparts in Western countries, and some simply do not have any counterpart in the Western world.

But do not rely on appearances. I visited a factory that looked very poor and old-fashioned from the outside, but inside there was very modern equipment for manufacturing up-to-date perforating tools. I also remember visiting a university in Siberia and talking with scientists who, despite being so remote, were performing world-class research in geostatistics in collaboration with US counterparts.

All this means that technology transfer and, more generally, dissemination of technical knowledge will be particularly interesting both within and with Russia. This will be a two-way street; Russia will have to learn from the Western world and the Western world has to learn from it. Like almost everywhere, many Russian producing fields, including some giants, are aging and their production is declining. They will have to inject not only gas or water, but also technology in general.
Acoustic Flow Monitoring Helps Optimize Swabbing Program for Shallow Gas Wells
Authors: Williams John D. , Airey Jonathan , Summers Denise
Published: February 2015

Technology Update

Conducting economically effective swabbing programs in fields of unmetered shallow natural gas wells is challenging at today’s low gas prices. Producers have long been aware that not all wells respond positively to interventions such as swabbing. At higher gas prices, knowledge of individual well responses to interventions is not critical, as it makes economic sense to swab wells in groups if the increase at the group meter justifies the cost.

As gas prices decline, producers have decreased expenditures on swabbing programs as returns became harder to realize. However, producers can maximize returns on interventions such as swabbing by using acoustic technology to locate high-performing wells and then focusing on maximizing returns from those wells.

Acoustic Flow Measurement

Acoustic technology is employed in a number of applications in the oil and gas industry, including pipeline monitoring and downhole leak detection. In this type of application, acoustics are used to measure the flow of natural gas in shallow wells. Turbulence in the pipe is interpreted into a flow measurement by means of an acoustic sensor that is inexpensive, unobtrusive from an operational perspective, and easy to install. With this device, producers can detect the response to an intervention, decide if the well rates as a high performer and then, if appropriate, move the device to another well. The following four stages of detection, processing, transmission, and representation describe the monitoring process.

The nonintrusive acoustic sensor is mounted to the (typically 2-in.) flowline to detect the signal. Where many flow measurement methods employ straighteners to reduce turbulence, it is turbulence in the flow that creates the strongest acoustic signal. Locations close to rigid objects such as support pilings, which restrict pipe movement and dampen vibration, are avoided whenever possible. Using a magnetic tip to ensure a strong coupling between the pipe surface and the sensor diaphragm, the sensor converts the pipe’s mechanical vibration energy into an acoustic signal. The sound is then focused and amplified mechanically by an acoustic chamber. Finally, a microphone in the chamber converts the signal into a voltage for processing.

In the processing stage, the controller tests the signal for frequencies below 15 kHz. A microprocessor handles the Fourier transform to perform on-site frequency analysis powered by the unit’s built-in solar panel and battery. If the signal is weak, weather-related or other noises such as chattering check valves or loose label tags clanging against the pipe can interfere with frequencies in the range of interest. Filtering may be employed to improve the signal-to-noise ratio by removing as much nongas related noise as possible. The controller then repeatedly samples the acoustic signal to build hourly averages.
Technology Focus: Well Testing (February 2011)
Authors: Angeles Renzo
Published: February 2015

Technology Focus

Often, the trial-and-error method is viewed as an imperfect surrogate for systematic scientific research. Yet, great advances never would have taken place without such an approach. Take shale gas, for example. Despite scarce research conducted by only a few companies, shale-gas plays have undergone massive development and have progressed techniques (e.g., horizontal drilling and multistage fracturing) that enabled resources unavailable less than a decade ago. According to a US Department of Energy report, US shale-gas production is expected to increase from 1.4 Tcf in 2007 to 4.8 Tcf in 2020. That same year, 64% of the total US gas production will come from unconventional gas.

Well testing is no exception. Although transient-linear-fluid-flow and dual-porosity concepts for fractured horizontal wells have been available for many years, painstaking trial and error has been the key to accommodating such extremely-low-permeability ranges in current prefracture- and post-fracture-well-test designs. Similarly, many if not all operators have diligently re-evaluated their appraisal programs in an effort to collect data needed for critical parameters (e.g., gas-in-place and initial pressure) in a cost-effective manner while accounting for varying relationships between matrix and natural- and hydraulic-fracture networks.

It is undeniable that trial and error should not be used to replace the rigor and thoroughness of systematic scientific research. However, the expanded range of environments that we encounter (from unconventional, to multilayered, to high-pressure/high-temperature reservoirs) requires rapid learning and adaptation, and, therefore, experimentation. The papers selected for this issue are clear examples of best-in-class knowledge development in well testing through first principles and an old familiar approach—trial and error.

Well Testing additional reading available at OnePetro: www.onepetro.org

IPTC 13912 “A Novel Analysis Procedure for Estimating Thickness-Independent Horizontal and Vertical Permeabilities From Pressure Data at an Observation Probe Acquired by Packer/Probe Wireline Formation Testers” by M. Onur, Istanbul Technical University, et al. (See JPT, September 2010, page 56.)

SPE 134534 “Practical Use of Well-Test Deconvolution” by A.C. Gringarten, SPE, Imperial College, London.

SPE 131675 “Pressure-Falloff-Test Interpretation for Leakage Detection During CO2 Injection in a Deep Saline Aquifer” by C.A. Ehlig-Economides, Texas A&M University, et al.
Niobrara Ramps Up To Hot Play For Liquids
Authors: Parshall Joel
Published: February 2015

The Niobrara Shale in the United States has ramped up into a hot play that could soon bring an explosion of horizontal drilling in Colorado and Wyoming. The combination of horizontal drilling and multistage hydraulic fracturing is transforming the Niobrara from a target that has been drilled vertically and primarily for gas for nearly 100 years into a liquids-rich play that is capturing considerable attention. Speaking at the 2011 SPE Annual Technical Conference and Exhibition in Denver, John Ford, general manager of Colorado’s Wattenberg field at Anadarko, described the growing Niobrara activity as “really the next big thing.”

That optimism was understandable. In November, Anadarko announced that its leases at Wattenberg may hold more than a billion barrels of recoverable oil and natural gas. The statement noted company drilling success in 11 recent wells at the field, including the Dolph 27-1HZ horizontal well that showed initial production of more than 1,100 B/D of oil and 2.4 MMcf/D of natural gas. These latest wells have given the company confidence that it can drill between 1,200 and 2,700 wells in northeast Colorado, with approximately 160 wells planned for this year. Based on results so far, the company expects ultimate recovery of between 500 million and 1.5 billion bbl of oil, natural gas liquids, and natural gas on an equivalent basis.

Anadarko is not alone. Chesapeake Energy, Noble, Encana, and EOG Resources are among the largest acreage holders and the most active drillers of many companies—including numerous small independents—probing the Niobrara. Majors such as Shell and Marathon Oil have significant acreage.

There are more than 50 operators in or near the Wattenberg field alone. Situated north/northeast of the Denver area, Wattenberg is the largest producing field in the Denver-Julesburg (D-J) Basin and one of the largest onshore oil and gas fields in the US. 

Reservoir Rock and Producing Regions

Although the Niobrara is usually referred to as a shale, its reservoir rock consists primarily of limestone or chalk intervals, said Steve Sonnenberg, professor of petroleum geology at Colorado School of Mines in a recent edition of the AAPG Explorer (published by the American Association of Petroleum Geologists). “The formation demonstrates facies changes that range from limestone and chalk in the eastern end to calcareous shale in the middle and eventually transitioning to sandstone farther west,” said Sonnenberg, a past president of AAPG. “Depth and thickness are highly variable.”
Making Sense of the 'Overnight' Shale Gas Revolution
Authors: Beckwith Robin
Published: February 2015

Global shale

As the worldwide shale gas revolution becomes more entrenched, excitement surrounding it dims. It appears that momentum has slowed in areas identified as hot spots, such as Europe, Argentina, and Australia, while heightened shale gas development in the United States spins consequences for the global liquefied natural gas (LNG) market as well as continued foreign investment in US shale plays—now spurred in some areas to favor extracting shale’s more lucrative crude oil and natural gas liquids.

However, as Advanced Resources International president Vello Kuuskraa said in mid-2011, “The shale gas story in North America has been an overnight revolution that has taken 30 years to develop.” Each country that is prospective for shale gas is following its unique “overnight” revolution trajectory.

The US ‘Overnight’ Revolution

Retired US Energy Information Administration (EIA) administrator, Richard Newell, stated in late 2011 that “Shale exploration is less risky than conventional gas. It’s more akin to a manufacturing process.” This observation would be untrue without the development of horizontal drilling, multistage hydraulic fracturing, and slickwater fracturing.

Horizontal drilling has a lengthy his-tory. In the 1980s, especially to economically develop low-permeability gas reservoirs in ultradeep environments (4000 m to 5000 m), operators sought to drill horizontally, thus remaining in the pay zone for distances up to several hundred meters in order to enhance production. In addition, according to the EIA, “Practical application of horizontal drilling to oil production began in the early 1980s, by which time the advent of improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies, particularly downhole telemetry equipment, had brought some applications within the realm of commercial viability.”

Although experimentation dates back to the 19th century, the first official hydraulic fracture stimulation was performed in the Hugoton gas field in Grant County, Kansas, in 1947 by Stanolind Oil (Standard Oil of Indiana). The application of hydraulic fracturing techniques to stimulate oil and gas production began to grow rapidly in the 1950s.

The US benefited from a tax incentive introduced in 1980 (the Alternative Fuel Production Credit, under Article 29 of the Internal Revenue Code) which, along with high gas prices, jump-started US tight gas exploitation. The incentive ended in 1992. During the 1980s and 1990s, Mitchell Energy and Development experimented with deep shale gas production in the Barnett Shale in north-central Texas. As Mitchell’s success gradually became apparent, other companies aggressively entered this play. By 2005, the Barnett Shale alone was producing almost 500 Bcf per year of natural gas.
Automated Alarms for Managing Drilling Pressure and Maintaining Wellbore Stability
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146298, ’Automated Alarms for Managing Drilling Pressure and Maintaining Wellbore Stability - New Concepts in While-Drilling Decision Making,’ by Andreas Sadlier, SPE, Chris Wolfe, SPE, Mike Reese, SPE, and Ian Says, SPE, Baker Hughes, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

With the increased complexity of wells being drilled, significant geologic uncertainty may be encountered during wellbore construction. Uncertainty can take the form of unplanned drilling events such as kicks, lost circulation, and borehole-stability problems. A more proactive effort to predict and identify trouble zones in real time could lead to a substantial reduction in nonproductive time (NPT) and safety risks. Computer systems can automate the filtering and distribution of relevant information to personnel quickly for more-rapid assessment of a situation.

Introduction

To assess and analyze the current risks, field engineers are tasked with monitoring various measurements and data feeds while drilling and, if potential problems occur, making recommendations for corrective actions. With an increasing volume of more-complex data available in real time, how can engineers analyze relevant information effectively and in a timely manner to mitigate risk? One way is to leverage the power in modern computer systems. Software automates the filtering and distribution of relevant information to personnel quickly for rapid assessment of a current drilling challenge. For example, in a pressure-management (PM) operation, alarms can be activated automatically to provide quick warnings on the basis of equivalent-circulating-density (ECD) measurements (in the context of the mud-weight window) and to indicate potential hazards. These alarms could help filter and interpret complex real-time data sets quickly, without relying solely on the experience of the individual pressure engineer to detect a possible drilling risk. A PM and wellbore-stability (WBS) alarming system was designed to reduce complexity and facilitate PM/WBS decision making in near real time.

Background

During drilling, the safe-mud-weight window ranges from the pore-pressure gradient (on the low end) to the fracture gradient (on the high end). The goal of real-time PM involves selecting and maintaining the downhole drilling-fluid pressure within the drilling-mud-weight window to reduce drilling NPT (drilling NPT attributed to pore-pressure and wellbore-instability issues is approximately 40%). To reduce this type of NPT effectively, the use of real-time PM engineers is recommended at the rigsite or from a remote monitoring center.
Technology Focus: Well Testing (February 2012)
Authors: Angeles Renzo
Published: February 2015

Technology Focus

The value of information has a ubiquitous and sometimes pervasive role in modern well testing.  From exploration to field management to surveillance, well-test practitioners deal with a wide array of measurements (e.g., pressure, flow rates, temperature, and fluid analysis) that, more often than not, encompass large amounts of data. This is particularly true for long-term-production-data analysis of established fields, and one can argue the same for any current pressure-transient analysis that also has benefited from improved and more-robust data-acquisition available today. Likewise, dynamic information through downhole testing equipment can be acquired in real time—wirelessly and at sampling frequencies that were not possible only a decade ago.

Yet what seems to be a relative abundance of data often is challenged by the complex environments in which we operate and by our need to assess its value against associated costs and business risks. One way to look at this is under the premise that, while “perfect” information is beneficial to have, it also is costly to acquire and economically inefficient. Is there a unique answer in our choice of type curves, material balance, or specialized graphs?  Should we account for multiphase flow or rock compaction? More importantly, what is the value of the next-best substitute for the information we require?  And can this substitute information still allow us to meet our testing objectives? Herein lies the delicate balance between our choices of risk and uncertainty, which brings us to the message of this feature: We should not look for data-rich, but information-rich, content that meets our testing needs.

The papers selected for this feature describe exciting advances and opportunities in well testing. They also show that the proper use of advanced techniques can lead to maximizing the value of the information at hand, even in hostile and unconventional situations.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 143592 Assessment of Rate-Dependent Skin Factors in Gas-Condensate and Volatile-Oil Wells by A.C. Gringarten, SPE, Imperial College London, et al.

SPE 146450 3D Multiphase Streamline-Based Method for Interpretation of Formation-Tester Measurements Acquired in Vertical and Deviated Wells by Hamid Hadibeik, SPE, University of Texas at Austin, et al.

SPE 142818 Application of IFOT in Tight Gas as a Reservoir-Surveillance Technique by E. Pinto, BP plc, et al.
Spatial-Feature Identification and Parameter Estimation From Pressure-Transient Tests
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142996, ’Grid-Based Inversion Methods for Spatial-Feature Identification and Parameter Estimation From Pressure-Transient Tests,’ by K.L. Morton, SPE, and R.J. Booth, Schlumberger; M. Onur, SPE, Istanbul Technical University; and F.J. Kuchuk, SPE, Schlumberger, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.

Three grid-based inversion methods for estimating formation parameters and for spatial geological-feature identification based on pressure-transient-test (PTT) data from multiple-well locations were investigated. The first two methods use efficient adjoint schemes to determine the gradient of the objective functions. The third method uses ensemble Kalman filtering (EnKF) for data assimilation. With these methods, the existence and location of many subseismic features, such as strong spatial permeability variations, faults, fractures, and pinchouts, may be determined by use of exploration and production data.

Introduction

PTTs are used to determine the productivity of a well and the properties of the formation (reservoir) on the basis of downhole and/or surface pressure and flow-rate measurements. The main steps for interpretation are:

Model identification—a possible set of reservoir models is found that may fit the data.

Model-parameter estimation—model parameters are adjusted until the model behavior matches observed data.

Model verification—consistency of the final model is verified by measuring the mismatch between the real system and the model or by comparing with other data.

By use of conventional interpretation methods (i.e., semilog methods such as Horner or Miller-Dyes-Hutchinson, and/or type-curve matching of measured pressure and/or pressure derivative), data including reservoir pressure, an effective average permeability of the formation, skin factor, and wellbore storage can be estimated from the PTT data. In such interpretation, some sort of prior modeling is necessary to constrain the nonlinear parameter estimation because a model with many nonphysical reservoir parameters may match the observed PTT data. This prior knowledge may be available at small scale from logs and cores and at a larger scale from seismic surveys and outcrop analogies. Recently, nonlinear least-squares optimization has been applied to PTT data by use of numerical models with a similarly limited number of parameters—often models that are divided into a small number of regions, within which the reservoir parameters are assumed to be constant.
Cloud Computing: What Upstream Oil and Gas Can Learn From Other Industries
Authors: Perrons Robert K. , Hems Adam
Published: February 2015

Management

The topic of “the cloud” has attracted significant attention throughout the past few years (Cherry 2009; Sterling and Stark 2009) and, as a result, academics and trade journals have created sever-al competing definitions of “cloud computing” (e.g., Motahari-Nezhad et  al. 2009). Underpinning this article is the definition put forward by the US National Institute of Standards and Technology, which describes cloud computing as “a model for enabling ubiquitous, convenient, on-demand network access to a shared pool of configurable computing resources that can be rapidly provisioned and released with minimal management effort or service provider interaction” (Garfinkel 2011, p. 3). Despite the lack of consensus about definitions, however, there is broad agreement on the growing demand for cloud computing. Some estimates suggest that spending on cloud-related technologies and services in the next few years may climb as high as USD 42 billion/year (Buyya et al. 2009).

Roster et al. (2010) identify three of the more commonly cited reasons for migrating functions and capabilities to the cloud:

Cost Reduction. For example, insurance companies are seeking more flexible cost structures, and the cloud allows firms to shift costs to an operating expense rather than a capital outlay, thereby giving them a highly flexible “pay as you go” resource.

Deployment Flexibility. In the media industry, for instance, the type of content that consumers request can suddenly become viral and then immediately fall out of fashion. Demand patterns can therefore swing profoundly from one extreme to the next. A cloud-based infrastructure affords companies in these industries a high degree of flexibility with regard to the amount of computing and data-storage resources that they need at any moment.

Implementation Speed. Doctors in small medical practices usually do not have their own information technology (IT) departments, and cloud computing therefore holds appeal for such enterprises because the technical support bundled into cloud service packages provides the most value for these small businesses in the shortest possible time.

Despite the compelling case for moving toward the cloud, however, the absorption of these technologies and services has been uneven. Some industries—most notably, the financial services and telecommunications sectors—have been relatively quick adopters, while others have approached the cloud more cautiously and slowly.