bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.