bluuebunny/crossref_metadata_2025_split huggingface dataset:
NORM: Innovative Thinking With Decommissioning and Radioactive Waste
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125661, ’NORM: The Lessons To Be Learned, New Challenges and Innovative Thinking With Decommissioning and Radioactive Waste,’ by A.L. Smith, SPE, Risk Management Systems, originally prepared for the 2010 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, 12-14 April. The paper has not been peer reviewed.
New challenges arising during decommissioning and with radioactive waste may be addressed through a combination of current best practice and innovative thinking, provided the les-sons learned and progress over the last century are remembered.
Naturally Occurring Radioactive Material (NORM)
Opinions differ on what exactly is meant by the term NORM. Reports of the occurrence of significant concentrations of radionuclides of natural origin in the oil and gas industry go back more than 100 years. When radioactive deposits were found on offshore installations in the early 1980s in the UK North Sea, they were initially known as low specific activity (LSA). The term NORM was first coined by this industry in the US during the late 1980s because of the negative connotation of LSA when referring to the radium-rich scales deposited inside well tubulars, surface piping, vessels, pumps, and other production and processing equipment. Since then, the term has become adopted widely beyond the oil and gas industry and now tends to be associated with almost any type of mineral or mineral-processing activity where the presence of radionuclides of natural origin is of interest.
The term NORM now has become firmly entrenched in our technical vocabulary, but as an acronym for “naturally occurring radioactive material” it is actually a misnomer. The descriptor “naturally occurring” refers to the radionuclides in the material and not necessarily to the material itself, which may well be a product of a physical, chemical, or thermal industrial process. Because radionuclides of natural origin are ubiquitous in the environment, it could be argued that all materials are effectively NORM. So this would include all types of minerals (rocks and soil) and all vegetable and animal matter including the food we eat, the water we drink, and even our own bodies.
Use of the term “technologically enhanced naturally occurring radioactive material” (TENORM) could be more accurate; however, its use does not solve the problem and indeed can be misleading because it implies that the materials of concern are limited to those in which the radionuclides have become concentrated as a result of an industrial process. This often is the case, but not always. Materials in their natural state are in principle no less important to consider than materials with activity concentrations enhanced by some form of processing, and any distinction between the two for the purposes of radiation protection is artificial and without any scientific foundation.
Automation and Surveillance Improve Progressing Cavity Pump Performance
Authors: Fryer A. 
Published: February 2015

This article is based on paper SPE 136690 by the same author, which was presented at the 2010 SPE Progressing Cavity Pumps Conference, Edmonton, Canada, 12-14 September.
To extend the run life of the pump while producing all available fluid is the goal of all progressing cavity pump (PCP) operators. The primary challenge is to do so without starving the pump and causing damage to the stator. The petroleum industry has been searching for years for a reliable way to control PCPs for pump-off. Several methods have been used, from monitoring torque to manual fluid levels. To date, none have been commercially successful. A method for controlling these wells has been developed combining wedge meter flow technology and microprocessor control of both electric motors through the use of variable frequency drives (VFDs) and hydraulic motors using proportional control valves. This method has proved accurate and reliable, extending run life while producing all available fluids.
Combining this automated technology at the well with a web-based system that feeds back real-time data to a dedicated supervisory control and data acquisition (SCADA) host allows PCP technical experts to diagnose problems, and operators to respond quickly to changing well conditions.
This article discusses the advances in automation and optimization of PCPs.
The acceptance of PCPs in the oil and gas industry has grown worldwide. A major concern is potential damage to the stator if the well is pumped off. The most common prevention is to ensure that there is a substantial amount of fluid level above the pump. Operators taking manual fluid level shots and adjusting pump speed has been the most widely used method to maintain a safe fluid level. With advancements in fluid flow measurement and proven algorithms, the PCP controller has eliminated this concern, while producing all the available fluid from the wellbore without damaging the pump.
With this automated technology and a web-based SCADA system, it became possible to monitor several data trends and discover additional control algorithms. Further development of these algorithms is ongoing.
Pump-Off Control for PCPs
Two main objectives were defined when the theory of the PCP controller was introduced. The first objective was to reduce premature pump failure. The most common failure is stator damage due to pump-off. Pump-off is defined as a lack of fluid entry into the pump. This causes a lack of lubrication to the stator, resulting in extremely high temperatures being generated. The high temperature ultimately burns the elastomer in the pump. The stator’s rubber surface becomes hard, brittle, and cracked. In severe circumstances, the stator contour is torn up, producing rubber at surface. This may be caused by one or a combination of the following problems: plugged pump intake, poor inflow, or production rates exceeding inflow.
Multidomain Data and Modeling Unlock Unconventional Reservoir Challenges
Authors: Ganguly Utpal , Cipolla Craig 
Published: February 2015

Technology Update
Completion strategy and hydraulic fracture stimulation are important keys to economic success in low- permeability and unconventional reservoirs such as tight sand and shale. Therefore, engineering workflows in unconventional reservoirs need to focus on completion and stimulation optimization, just as they do well placement and spacing.
The primary obstacles associated with optimizing completions in these reservoirs have been the absence of hydraulic fracture models that properly simulate the complex fracture propagation common in many reservoirs, the lack of efficient methods to create discrete reservoir simulation grids to rigorously model hydrocarbon production from complex hydraulic fractures, the lack of automated fracture treatment staging algorithms, and the lack of ability to efficiently integrate microseismic mapping measurements with geological and geophysical data.
This article details a novel approach for enabling efficient multistage completions, new complex fracture models, unstructured gridding-based reservoir simulation, and a comprehensive integrated workflow developed within single reservoir-centric stimulation design software. Though primarily focused on unconventional reservoirs, this efficient full-cycle seismic-to- simulation workflow is applicable also for conventional reservoirs.
Seismic-to-Simulation Through Stimulation
In recent years, an increasing amount of hydrocarbons in North America have been produced from unconventional reservoirs, with a similar trend expected worldwide. The International Energy Agency projects the hydrocarbon reserves in unconventional reservoirs to be as high as 8 trillion BOE. Most of these low-permeability reservoirs must be hydraulically fractured to produce. In unconventional reservoirs, stimulation is the key step in the seismic-to-simulation workflow.
For unconventional reservoirs, detailed reservoir characterization plays a fundamental role in completion design, affecting the staging strategy, location of perforations or fracture ports, and stimulation design. Properly modeling the interaction of induced fractures with the rock fabric and coupling the hydraulic fracture geometry and conductivity with subsequent well performance is an essential element in this comprehensive workflow. The unconventional reservoir simulations include a detailed geologic description. The modeling is focused on the well and the specifics of the completion (i.e., the hydraulic fracture treatments). In contrast, this information can be significantly scaled up for conventional reservoirs, shifting the focus to large-scale reservoir behavior (i.e., multiwell and full-field simulation models).
Reelwell Drilling Method Makes Use of Dual-Conduit Drillstring
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
The Reelwell drilling method (RDM) is a drilling solution using a unique flow arrangement. RDM employs drillpipe where an inner string is installed to form a dual-conduit drillstring. This allows the fluid and cuttings from the bottom of the well to return to the surface through the inside of the drillstring. RDM enables improved hole cleaning, reduced possibility for washouts, and improved downhole pressure control. RDM has unique features for managed-pressure drilling (MPD) and extended-reach drilling (ERD). A special feature of RDM is that it allows MPD and underbalanced operations (UBO) to be performed with a heavy fluid in the well annulus by means of the Reel-well multigradient system. This implies that MPD and UBO can be performed with two well barriers and, thus, improved safety.
RDM started its development in 2004 and has been through several full-scale tests. In 2009, the system was used for the first time for directional drilling with MPD in a land well in Norway. In 2010, RDM was used for the first time in a live shale gas well in Canada. These operations have validated RDM and its features and are important steps proving its potential.
Arrangements and Rig Description
Fig. 1 presents a schematic of the system. The system is based on a dual-channel drillstring, where one flow path is used to convey the drilling fluid into the well down to the bit and the other channel is used for the return fluid from the bottom of the well. This arrangement implies a modification of the drilling fluid flow arrangement.
The following special tools and arrangements are used.
Dual Drillstring (DDS). The DDS can be manufactured in various sizes; the current size used consists of 6⅝-in. drillpipe adapted with 3.5-in. inner pipe that has been fitted with stab-in innerstring connectors. The DDS is handled on the rig floor as conventional drillpipe.
Topdrive Adapter (TDA). A dual-conduit swivel connects the rig’s topdrive unit to the dual drillstring and enables rotation of the drillstring by the top drive. The TDA is connected to the surface flow control unit through an additional separate stand pipe and mud hose.
Flow Control Unit (FCU). The FCU is a control valve arrangement equipped with pressure and flow sensors and permits accurate control of the in/out flow in the RDM system. The control unit connects to all the flow paths of the system, as shown in Fig. 1.
Dual-Float Valve (DFV). The DFV is a device located at the bottom of the DDS. The DFV includes a flow cross-over from the well annulus into the return channel of the DDS. The DFV incorporates valves that isolate the drillstring from the well during connections. In the fail-safe default position, the DFV closes both channels of the DDS. A conventional BHA is made up below the DFV.
Production Method for Methane Hydrate Sees Scientific Success
Authors: Parshall Joel 
Published: February 2015

The testing flare burns brightly during a methane hydrate production test of the Ignik Sikumi No. 1 well on the Alaskan North Slope.
A production method that could unlock large reserves of methane hydrate in sand-dominated reservoirs was tested successfully from a scientific and operational standpoint in a recent research experiment on the Alaskan North Slope (ANS). The experiment was conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in partnership with ConocoPhillips and Japan Oil, Gas, and Metals National Corporation.
A proof-of-concept test was conducted between 15 February and 10 April at the Ignik Sikumi No. 1 well in the Prudhoe Bay field operated by ConocoPhillips. The production technique featured the injection of carbon dioxide (CO2) to exchange and release methane (CH4) from the hydrate, a method developed through laboratory collaboration between the University of Bergen in Norway and ConocoPhillips. The released gas was then produced by means of reservoir depressurization.
“The test objective was to perform injection and flow-back from a single well to validate that the CO2/CH4 exchange mechanism demonstrated in laboratory tests will occur in a reservoir of natural methane hydrates,” said Ray Boswell, technology manager for gas hydrates at the NETL. It was the first field-level trial of a production method involving the exchange of CO2 with the methane molecules contained in a methane hydrate structure. “The focus of the test, including the design of the well, was on the technical feasibility of this new technology, rather than an attempt to produce gas at commercial rates,” Boswell said.
CO2 Mixture Injected in Reservoir
The Ignik Sikumi well test was equipped with downhole fiber-optic distributed temperature and acoustic sensing, three downhole pressure gauges, and full surface instrumentation, including high-resolution in-line gas chromatography. Over a 13-day period, a carbon dioxide/nitrogen mixture was successfully injected into the 30-ft-thick reservoir interval, saturated with methane hydrate, without loss of injectivity. This was followed by a production stage in which the pressure was held above the stability pressure of the in-situ methane hydrate. CH4 was produced during this stage, and initial data analyses indicated that CO2 exchange was achieved. Ongoing analyses of the extensive datasets acquired at the field site are under way to determine the overall efficiency of simultaneous CO2 storage/CH4 production from the reservoir.
As part of the demonstration, the depressurization phase of the test extended for 30 days. The longest previous field test of depressurization to extract gas from hydrate lasted 6 days as part of a Japanese-Canadian testing program at the Mallik well in Canada’s Northwest Territories during 2007 to 2008.
Technology Focus: Formation Evaluation (August 2012)
Authors: Harrison Bob 
Published: February 2015

Technology Focus
A little bit of knowledge is not always a dangerous thing.
Recently, I was reviewing some simulation models with a client’s subsurface team. They were taken aback when I asked them if they were happy with the petro-physical inputs they had been provided with. “It’s not our job to question the petrophysics,” they replied in unison. However, it was obvious that they were struggling to get the simulation model to match the observed reservoir performance and could do so only by dramatically changing the input rock properties. It transpired that their employer had recently bought the asset and the team had inherited the previous operator’s interpretations, which, “to save time,” had simply been imported into their model.
After much cajoling, the team agreed to review the raw core and log data and opened a Pandora’s box. The older wells had poor borehole quality with large washouts, usually in shaly zones, that adversely affected the logs so that they indicated porosity in shales. The net-pay count was, therefore, optimistic. Closer inspection of the permeability/porosity transform revealed that the core data had not been corrected for the Klinkenberg effect or for compaction or even checked against test values. Finally, the computed Corey coefficients for the relative permeability curves looked very low for the oil-wet carbonate they were supposed to characterize, which was because of unstable flooding of the core plugs in the laboratory.
With these revelations in mind, the team members decided that the petrophysics for the field had to be reinterpreted, and they collaborated closely with their company petrophysicist during the review. A new simulation model was built that was more coherent, more consistent, and more realistic and that gave much better results than before.
There is no harm in developing a petrophysical side to one’s discipline. As I mentioned in my Focus column in August 2009, petrophysics touches all the subsurface disciplines in one way or another. Being able to converse intelligently with log analysts and ask them pertinent questions can only be good news for employers and subsurface project managers. It can also save time that may have been wasted creating simulation models that do not reflect reality.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 153537 A Study of Differences in Array-Induction and Multi-Laterolog Responses in a Well Drilled With High-Salinity Water-Based Mud by Bill Corley, Baker Hughes, et al.
SPE 153593 A New Method for Estimating Waterflood Oil-Recovery Efficiency Using Post-Waterflood NMR and Dielectric Well Logs, Belridge Field, California by Daniel A. Reed, Aera Energy, et al.
SPE 154426 Reducing Reservoir Uncertainties Using Advanced Wireline Formation Testing by D. Loi, Eni, et al.
Assessment of European Shale-Gas Play Takes Social Acceptance Into Account
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152339, ’Assessment of an Unusual European Shale-Gas Play: The Cambro- Ordovician Alum Shale, Southern Sweden,’ by Wilfred Pool, Mark Geluk, Janneke Abels, and Graham Tiley, Shell International E&P, and Erdem Idiz and Elise Leenaarts, Shell Global Solutions International, prepared for the 2012 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 20-22 March. The paper has not been peer reviewed.
In 2008, Shell obtained two licenses for unconventional gas exploration in the Skåne region of southern Sweden, with a total size of 2500 km2. The objective was the Cambro-Ordovician alum shale, one of the thickest and richest marine source rocks in onshore northern Europe. Concerns from the residents of Skåne regarding the visual impact of activities and potential impact of drilling activities on the aquifers and on the tourism industry have resulted in extensive engagements with stakeholders and specific requirements around seismic acquisition, site preparation, and operations.
Introduction
In 2006 and 2007, a screening study for potential unconventional basins was undertaken in Shell. The focus for this screening was to identify basins with excellent source rocks because unconventional gas systems require excellent, gas-prone source rocks in the right maturity window. Several source-rock systems were screened, one of which was the Lower Paleozoic system on the east European platform. This system has a considerable regional extent, stretching more than 1500 km from Denmark in the northwest to the Moesian platform in Romania and Bulgaria in the southeast.
The derisking strategy for this opportunity was based on both technical and nontechnical aspects. The aim was to collect geological and geophysical data to constrain depth and thickness of the shale and to identify potential dolerite dykes. In addition, well data were needed to establish rock properties and gas content.
Sweden does not have much exposure to hydrocarbon-related activities, and the application for the two licenses in Skåne resulted in nationwide press attention, especially when it was realized that these were so-called unconventional hydrocarbons. People in the Skåne region were concerned about the impact of the exploration activities in these licenses. The mindset in Shell from the start was to perform the exploration (and, in case of success, the appraisal and production activities) in a sustainable way with minimal impact to ensure social acceptance.
Value of Dispersants for Offshore-Oil-Spill Response
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 23359, ’The Value of Dispersants for Offshore-Oil-Spill Response,’ by Tim Nedwed, Tom Coolbaugh, and Greg Demarco, ExxonMobil, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Each oil-spill-response option must be evaluated for operational limitations (e.g., sea state), potential effectiveness, environmental effects of the response option, applicability under various oil-spill scenarios (e.g., size and location of the spill), and health and safety of the responders. Alternative response tools are available to assist mechanical recovery in treating large offshore oil spills more effectively. There are misperceptions and misunderstandings about dispersants and their use; therefore, a description of dispersant use during the Deepwater Horizon incident is presented.
Introduction
The primary goal of any oil-spill response should be to minimize environmental harm. Although one expectation may be complete physical containment and removal of oil from the environment, this often is not possible (especially with large offshore spills) because of physical limitations of mechanical-recovery systems. Recovery operations during previous offshore spills collected only a small fraction of the spilled oil, even under ideal conditions. The Deepwater Horizon incident was no exception, with estimates indicating that only 3% of the oil was recovered mechanically.
Recognizing significant limitations of mechanical recovery has led to developing alternative response tools—one of which is oil-spill dispersants. Oil-spill dispersants facilitate removal of oil from the environment by enhancing the natural biodegradation process. Dispersants break up a surface slick rapidly into micron-sized droplets that move into the water column. This action provides naturally occurring oil-degrading bacteria greater access to the oil by creating a dilute mixture of oil in water rather than a thick surface accumulation. Fortunately, oil-degrading bacteria exist in all marine environments, having evolved to degrade oil released by natural seeps. Dispersed oil dilutes rapidly, and concentrations above known toxicity thresholds persist for no more than a few hours after effective dispersant application.
During the Deepwater Horizon incident, the amount of damage to the shorelines was far less than expected initially by the public. In many locations where oil did enter, marsh-grass recovery was apparent soon after the spill. This, and other evidence, suggests that a key reason for the limited shoreline effects during the incident was use of dispersants and, in particular, the subsea injection of dispersants at the wellhead.
Oil Behavior During High-Flow Subsea Release
The lower the viscosity of the oil, the higher the flow rate, and vice versa. Also, the ability to disperse oil is inversely related to the fluid’s viscosity, and oils remain readily dispersible with viscosities up to several thousand centipoises.