bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation of Two-Phase-Flow Patterns and Hydraulic Performance of Electrical Submersible Pumps
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper CSUG/SPE 134089, ’Experimental Investigation on the Viscous Effect on Two-Phase Flow Patterns and Hydraulic Performance of Electrical Submersible Pumps,’ by F.E. Trevisan, SPE, and M.G. Prado, SPE, University of Tulsa, originally prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. See Journal of Canadian Petroleum Technology, April 2011, page 45.
Using a visualization prototype built from original electrical-submersible-pump (ESP) components and with minimal geometrical modifications, an experimental procedure was developed and conducted to address the viscous effect on liquid/gas two-phase flow through ESPs. On the basis of dimensionless groups that govern centrifugal-pump single-phase performance, two-phase experiments were conducted at different shaft speeds, nonslip void fractions, and viscosity values while liquid rates were kept constant at 60% of the maximum rate at the defined shaft speed.
Introduction
An ESP is one of the many existing artificial-lift techniques used in the petroleum industry. It consists of a series of small-diameter diffuser-type casing centrifugal pumps, mainly known for their capacity for handling high volumes. Their applications vary from producing high-productivity oil wells onshore and offshore to dewatering coalbed-methane and gas wells.
The use of ESPs in liquid single-phase applications is well understood. However, the presence of a compressible phase, such as natural gas, will modify the hydraulic performance of this type of pump. The presence of a second phase often will degrade the ability of the pump to deliver pressure, and depending on the amount of gas flowing through the system, instabilities may occur. These, also referred to as surging, eventually lead to extremely low pressure generation, also known as gas lock.
Experimental Description
An ESP visualization prototype was designed, built, and installed in a closed-circuit loop. Fig. 1 in the full-length paper provides a graphical representation of the experimental facility. This closed circuit consisted of a 65-gal tank to store the liquid, from which the fluid passed through a booster pump and a liquid-measuring unit before flowing to the ESP prototype. Air was provided by a 1-hp compressor delivering pressures up to 10 psig and flow rates up to 10 scf/hr. Gas was injected at the liquid line close to the prototype intake and measured by rotameters. After passing through the ESP prototype, the fluids returned to the liquid storage tank that also acted as an open-air separator. Both ESP and booster-pump motors were controlled by individual variable-speed drives linked to the acquisition system. This system also received information the differential-pressure and temperature transducers.
CO2 EOR: Nanotechnology for Mobility Control Studied
Authors: Jikich Sinisha (Jay) 
Published: February 2015

Technology Update
Most domestic conventional oil resources have been produced using primary and secondary recovery techniques, with an average recovery factor estimated at 35%. Additional recovery is possible by using innovative enhanced oil recovery (EOR) techniques. One of these, carbon dioxide (CO2) miscible flooding, is the fastest growing EOR technique in the United States because of the many reservoirs amenable to the process. Current production is almost 310,000 B/D (EOR Survey, Oil and Gas Journal, April 2012), representing approximately 5% of total US oil output.
A revised national resource assessment for CO2 EOR conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in 2011 indicated that “next generation” CO2 EOR can provide 137 billion bbl of additional, technically recoverable domestic oil, with about half (67 billion bbl) economically recoverable at an oil price of USD 85 per bbl. CO2 EOR has the benefit of sequestering CO2 in oil producing formations and is seen as a critical component of future greenhouse gas management programs. This facet of CO2 EOR produces valuable synergies with the carbon capture, utilization, and storage research program with the DOE’s Office of Fossil Energy.
The CO2 EOR process is limited by technology, cost, and the geographic availability of CO2. Technology improvements are needed to increase the displacement efficiency of the process. Not only would advances in displacement efficiency increase oil recovery, it would also lead to the sequestration of additional CO2 volumes.
Background
The Office of Fossil Energy has historically supported a large number of laboratory and field tests in an effort to improve oil recovery processes. A majority of the projects were related to advanced reservoir characterization, mobility control, and conformance of CO2 flooding. In September 2010, the NETL awarded a number of new research projects to further development of the next generation of CO2 EOR, encouraging applicants to pursue small field or pilot testing. Two of the awarded research projects are related to mobility control in CO2 flooding using nanoparticle technologies.
The University of Texas at Austin (UT) is evaluating inexpensive alternative nanoparticles (microscopic particles with at least one dimension less than 100 nm) to provide the large volumes needed for foam stabilization in field-scale CO2 floods. The study entails using low-cost, commercially available “bare” nanoparticles (e.g., silica, fly ash, and iron oxide) and applying a polyethylene glycol (PEG) or other in-house coating to produce low-cost alternatives to develop CO2 foam.
China's Shale Gas Potential Looks Bright, But Development Raises Questions
Authors: Rassenfoss Stephen 
Published: February 2015

Shell is evaluating shale gas prospects in the Sichuan basin in hopes of replicating its success in the Changbei field, a tight gas project with PetroChina, that required advanced exploration and production technology.
China ranks first in the world in shale gas in the ground, based on just two massive basins. But the estimate in a report from the US Energy Information Administration (EIA) is based on what is technically possible, not when, or if, anyone will produce that gas.
“The time dimensions are up to infinity. It is a technically recoverable number without a time constraint,” said Vello Kuuskraa, the president of Advanced Resources International, which conducted the World Shale Gas Resources study for the EIA, part of the US Department of Energy.
China’s plan to aggressively tilt its coal- and oil-based economy toward natural gas by exploiting its shale resources is on the scale of what the US did to shift from a shortage to a glut of gas. But some question whether China will be able to reach its goal of leaping from virtually no shale gas production now to 60 billion–100 billion m3/a by 2020, equal to 6–10 Bcf/D.
The exploration business there is worlds different than the US model that allowed independent gas companies to quickly lease and explore large blocks of land with the support of service companies providing advanced drilling and fracturing services.
In China, international companies must partner with government-controlled Chinese ones that control the prospects, and multiple layers of government permission are needed to get things done.
High population density and tight water supplies are an issue in one of those basins, the Sichuan. In the other, the Tarim, there are few people to consider, but it is a remote region far from markets.
On the plus side, the EIA study estimated that the Sichuan and Tarim basins hold 1,275 Tcf of technically recoverable gas, assuming that about 25% of the gas in the ground can be produced. “These are two massive world-class basins with multiple formations,” offering stacked layers of shale gas, Kuuskraa said. They are in a country with a voracious appetite for energy and a plan to increase its reliance on gas, which represents only 4% of Chinese energy consumption.
Why Asset Integrity Implementation Often Fails
Authors: Ciaraldi Stephen W. 
Published: February 2015

Management
Compare the approaches of the top 10 operating companies around the world to tackling the asset integrity challenge and you will find many similarities. Whether in the models used to identify risks or the approaches used to manage them, the industry thinking has evolved to a point at which most agree on the fundamental elements of how to approach integrity management.
Look closer and you might find some more commonalities. The reasons asset integrity management strategies often fail to achieve the expected results are also often the same from operator to operator.
So what are these reasons, and how can you ensure you are building them into your implementation strategy to ensure that you do not repeat them? There are 10 reasons why integrity management implementations often fail.
Trying to tackle integrity in isolation.
Perhaps the most common reason asset integrity strategies fail is integrity specialists trying to achieve integrity in isolation. Integrity is not a subject that thrives in a silo—it requires the entire business to be aware, on board, and supporting of a unified effort. Staffers need to know how integrity affects their daily job, and they need to be encouraged, cajoled, instructed, and motivated to ensure that they are working together. Different groups have different goals, but not caring about others’ goals and complaining about having to do others’ work demonstrates a silo mentality. If that type of silo mentality exists, there will be problems in implementing integrity management.
Losing sight of process, people, and plant.
It may seem obvious, but an asset integrity plan is an extremely complex undertaking with many moving parts and even more stakeholders involved in its successful execution. Recognizing that there are many reasons why asset integrity implementations do not achieve the results expected of them is an important starting point. Problems are not confined to one particular area of an integrity implementation and can just as easily emerge in either the process, the people, or the plant components that make up an integrated integrity management program. Focus too narrowly on one area and you can be sure problems will emerge elsewhere. The key to implementation is the effective working together of these three components and ensuring that checks and balances exist at every stage.
Ormen Lange Hydrodynamic-Aquifer Model
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 153507, ’Predicting Water in the Crest of a Giant Gas Field: Ormen Lange Hydrodynamic-Aquifer Model,’ by M. Boya Ferrero, S. Price, SPE, and J. Hognestad, Shell, prepared for the 2012 EAGE Conference & Exhibition/SPE Europec, Copenhagen, Denmark, 4-7 June. The paper has not been peer reviewed.
Simulation showed that hydrodynamically tilted/stepping contacts depend on the rate of water flow across the aquifer, stratigraphic baffling and faulting, effective aquifer area, and reservoir quality. The role of sealing faults over geological time was downplayed in terms of justifying the fluid distribution. However, baffling during production is expected. At Ormen Lange, the hydrodynamic aquifer has pushed gas from the crest of the structure into the south of the field, leaving behind a northward-thickening prism of residual gas, which was imaged with a seismic direct hydrocarbon indicator (DHI). Confirmation of the hydrodynamic aquifer in this field was achieved after drilling an appraisal well in the north of the structure that corroborated fluids (water with residual gas) and pressures as predicted by the hydrodynamic-aquifer model.
Introduction
The Ormen Lange gas field was discovered in 1997, with first production in 2007. It is a large (8×40-km) deep-water reservoir 125 km offshore Norway at 700- to 1100-m water depth. Ormen Lange sands have excellent reservoir quality, with 26 to 30% average porosity and 500- to 1,000-md permeability. The field was developed with four subsea templates and 10 high-rate large-borehole wells.
The initial field-development plan was based on a stratigraphic trap filled to spill point, with the gas accumulation being delineated by a seismic DHI, which was postulated to indicate perched water on the edges of the structure. The field-development plan was defined on the basis of information available from only four exploration and appraisal wells. The need to understand the field’s charge history became apparent when, in 2008, an appraisal well in the northern part of the field encountered only residual-gas saturations in the crest of the structure and in the middle of a high DHI. Therefore, the DHI could not be used as a proxy for the current free-water level (FWL) because seismic cannot distinguish between mobile-gas and residual-gas saturations. Subsequently, three additional appraisal wells confirmed elevated contacts, residual gas, and gas communication across the field.
Offshore ESP-Selection Criteria: An Industry Study
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146652, ’Offshore ESP-Selection Criteria: An Industry Study,’ by Michael C. Romer, SPE, Mark E. Johnson, SPE, Pat C. Underwood, SPE, and Amanda L. Albers, SPE, ExxonMobil, and Russ M. Bacon, R.M. Bacon Engineering, prepared for the 2012 SPE Deepwater Drilling and Completions Conference, Galveston, Texas, 20-21 June. The paper has not been peer reviewed.
Most offshore wells that require artificial lift are gas lifted because gas typically is readily available and, compared with other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electrical submersible pumps (ESPs) can increase oil production and reserves recovery efficiently and economically under the appropriate operating conditions. ESPs can lower the abandonment pressure and, in the long term, possibly reduce the total number of wells required to deplete an asset. Because few ESPs are installed in offshore wells, ESP-screening “rules of thumb” were formed as a simple guide to prioritize offshore ESP candidates.
Introduction
Pumps typically achieve higher drawdowns than gas lift under appropriate operating conditions. Early in the life of the pump, greater production is achieved with its higher drawdowns. Note that increased production over the long term must be supported by good reservoir management and voidage-replacement practices. Lowering the flowing bottomhole pressure can improve a well’s access to reserves in stratified reservoirs. Pumps also reduce the burden on the gas-compression system and enable selling gas or reallocating it to other gas lift wells.
ESPs have a small topside footprint, do not impair subsurface-safety-valve operation, can achieve high production rates, and can aid fluid processing on production facilities because high-pressure power fluid or gas is not required. However, it can be difficult to determine the best ESP candidates when faced with numerous opportunities, limited resources for reserves studies or artificial-lift analyses, and finite installation capital. ESPs can help maximize an asset’s profitability, and screening criteria can streamline the candidate-selection process.
These screening criteria were developed for dry-tree offshore applications. The high complexity, cost, and risk involved with subsea ESP installations and workovers typically have limited subsea pumping to seafloor technologies such as subsea separation, multiphase pumps, cartridge ESPs, and caisson ESPs. This trend may change with continued progress in alternative ESP-deployment/-retrieval technologies and/or run-life and reliability improvements.
Technology Focus: Unconventional Resources (July 2012)
Authors: Chipperfield Simon 
Published: February 2015

Technology Focus
“Geology drives technology,” and “the best solutions are multidisciplinary.”
Understanding the best way to develop an unconventional reservoir requires an understanding of the rocks and a close interaction between the geosciences and engineering. Without this base understanding and creative tension, unlocking the full potential of any play will not be achieved. Some of the greatest results in my career have come when working in a cross-functional team where all members were sufficiently aware of the geology to then apply the most appropriate technology for extraction. Interaction was open, robust, and balanced, and amazing results were produced.
The most successful field developments that are being proposed today in unconventional gas use this model. For example, horizontal wells with multistaged stimulation that use image logs to identify and target existing rock fabrics highlight the close working relationship between drilling, geology, stimulation, and geomechanics.
“Geology drives technology,” and “the best solutions are multidisciplinary”—this has never been more true than when developing and appraising on the challenging unconventional frontier.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 152596 Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor, and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells by George E. King, Apache Corporation. (See JPT April 2012, Page 34.)
SPE 148751 An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation by Li Fan, Schlumberger, et al.
SPE 150830 Assessment of Unconventional Shale Reservoir: The Fegaguira Formation, Chotts Basin, Tunisia by Nawel Rezouga, ETAP, et al.
Lacq Carbon-Capture and -Sequestration Pilot
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 157157, ’The Lacq CCS Pilot, a First,’ by Jacques Monne, SPE, Total, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.
Carbon capture and sequestration (CCS) holds promise for use on an industrial scale. Total has been involved in CO2 injection and geological storage for more than 15 years, in Canada (Weyburn oil field) for enhanced oil recovery and in Norway (Sleipner and Snohvit fields) for aquifer storage. In 2006, the company decided to set up an experiment for CO2 capture, transportation, and injection in a depleted gas reservoir. The pilot is in the Lacq basin in southwestern France, 800 km from Paris, and has been on stream since January 2010.
Introduction
This CCS project entailed converting an existing air/fuel-gas combustion boiler into an oxygen/fuel-gas combustion (oxy-combustion) boiler using oxygen delivered by an air-separation unit (ASU) to obtain more-efficient combustion and a more-concentrated flue-gas-CO2 stream. The 30-MW oxy-combustion boiler can deliver up to 38 t/h of steam to the high-pressure steam network of the Lacq sour-gas-production and -treatment plant. After quenching the flue-gas stream, the rich CO2 stream is compressed to 27 barg, dried, and transported in gaseous phase by use of existing pipelines to a depleted gas field, 29 km away, where it is injected into the deep Rousse reservoir. Over a 3½-year period, up to 90 000 t of CO22 could be injected.
The main objectives in this experiment were:
To demonstrate the technical feasibility and reliability of an integrated chain comprising steam production and CO2 capture, transportation, and injection into a depleted gas reservoir.
To acquire operating experience and data to scale up the oxy-combustion technology from pilot scale (30 MW) to industrial scale (200 MW) while reducing costs.
To develop on-site monitoring methods and technologies to serve future onshore storage-monitoring programs that will be larger in scale, longer in term, and economically and technically viable (i.e., microseismic and environmental monitoring).
Technical Description
The CCS pilot installation, shown in Fig. 1, consists of an ASU, an oxy-combustion boiler, a direct-cooling contactor, a CO2 compressor, a dryer system, a transportation pipeline, and an injection site (i.e., compressor, injection well, reservoir, and a subsurface-seismic network).
ASU. A dedicated ASU, the oxygen-production unit, was installed on the Lacq gas-treatment complex to produce 240 t/d of low-pressure oxygen (1.8 bara) at 95 to 99.5 vol% purity. Only 99.5% pure oxygen is used to feed the oxy-combustion boiler. The nitrogen rejected by the ASU is partially used for regenerating the dryer system.
BOP Monitoring Seeks To Reduce Downtime, Increase Insight
Authors: Jacobs Trent 
Published: February 2015

Blowout Preventer Technology
A growing trend of heavy industries in the 21st century has been to marry computers and software with large machines to track their performance, and all the hiccups along the way. Known as condition-based monitoring, the process is used to enhance the reliability and performance of railroads, wind turbines, nuclear reactors, and jet engines, but not subsea blowout preventers (BOPs). However, that is slowly starting to change.
All three major BOP makers, as well as some other companies, have introduced BOP monitoring systems that seek to provide new insight into how these massive subsea machines work—and perhaps more important, why they sometimes do not. By improving system reliability, the offshore drilling industry stands to recoup millions of dollars it writes down each year because of BOP downtime.
Today, offshore drillers have little knowledge about the fatigue life of the more than 100 hydroelectric valves and regulators inside a BOP. Makers of BOPs acknowledge that this uncertainty forces companies to replace as much as 25% of the BOP stack each time it undergoes scheduled maintenance to mitigate breakdowns. The practice of arbitrarily replacing parts is only a stopgap measure as drilling contractors report that 50% of downtime on their drilling rigs are caused by problems with BOPs. While they have their differences, the BOP monitoring systems available today seek to completely change this status quo. “The holy grail is to detect a failure early and focus your maintenance efforts on that part, and not just a random part,” said Clayton Simmons, product line manager of BOP monitoring systems at National Oilwell Varco (NOV).