Multifunctional Handling tool launched
Weatherford International recently announced the launch of its UniSlips all-in-one handling tool, the industry’s first rotary-mounted, multifunctional slip for casing, tubing, or drillpipe operations. Read more »
New subsea system launched for jack-up drilling units
Argus Subsea has recently introduced the AZ-15J subsea tree and wellhead system, specially designed for jack-up mobile drilling units. The company states that the new system is the world’s first purpose-built system that allows operators to drill and complete wells at up to 15,000 PSI working pressure without special riser systems or temporary abandonments. Read more »
New drilling motor promises performance boost in challenging environments
Mpact Downhole Motors has introduced a new proprietary downhole drilling motor that promises significant increases in performance and reliability. Designated Model 775 7822 HTS, the drilling motor’s ultralow speed and robust design have helped reduced drilling downtime in field trials in Texas and Louisiana. Read more »
[Download the Higher Resolution Subsurface Imaging white paper.]
It is hard to read road signs if you have poor eyesight, which is why driver’s licenses are issued with restrictions requiring that corrective lenses must be worn. Likewise, it is hard to find and exploit subsurface resources if you can’t clearly see your targets or monitor the movement of fluids in the reservoir.
Engineers now have powerful tools to precisely model subsurface reservoir production behavior, but a precise answer is still wrong if it is derived from an inaccurate subsurface description. Geoscientists make maps and rock property models of the subsurface by interpreting images that are produced from remote sensing data. Analogs from modern depositional environments and outcrop exposures guide subsurface data interpretation to predict ahead of the bit, then postdrill geostatistics are used to fill in stratigraphic details between wellbore control points. Selection of the right depositional model, facies distribution, and geostatistical analog depends on having the sharpest, most detailed and accurate image of the subsurface possible—the Grand Challenge of Higher Resolution Subsurface Imaging.
Over the past century, the industry has relentlessly sought ways to improve subsurface imaging of hydrocarbons. Canadian inventor Reginald Fessenden first patented the use of the seismic method to infer geology in 1917. A decade later, Schlumberger lowered an electric tool down a borehole in France to record the first well log. Today, advances in seismic and gravity data acquisition, electromagnetics, signal processing and modeling powered by high-performance computing, and the nanotechnology revolution are at the forefront of improved
In this paper, we will examine the challenges of getting higher resolution subsurface images of hydrocarbons and touch on emerging research trends and technologies aimed at delivering a more accurate reservoir picture.
Last year in this focus on CO2 applications, I (as others have) connected enhanced
oil recovery (EOR) as an enabling business foundation and a possible way forward
to accomplish carbon capture and storage (CCS) as a business investment. This year,
in an address to the CCS conference in Pittsburgh, Pennsylvania, US Department of
Energy (DOE) Assistant Secretary of Fossil Energy Charles McConnell encouraged the
CCS industry to help operators establish a salient business case between CO2 EOR and
usage and sequestration. Creating a technical lead in CO2 EOR and other usage technologies
establishes an opportunity to commercialize the technologies that could be
in high demand in the years to come, particularly in coal-reliant developing countries
such as China and India.
The technologies needed to accomplish carbon capture, utilization, and storage
(CCUS) require expertise in science and engineering that, in some cases, are not completely
matured or, at least, require a different focus and commitment in science and
business to affect CCUS. An acceptable return on investment will depend on economic
CO2 capture and largely on regulatory stability.
Administratively, the US Environmental Protection Agency proposed a carbon
pollutions standard for new power plants, which will have to meet 1,000 lbm
of CO2 per electrical megawatt-hour produced. Older coal plants average approximately
1,768 lbm of CO2 per megawatt-hour but are exempt from the standard, as are
plants permitted to begin construction within a year. A typical natural-gas electricitygeneration
plant emits 800 to 860 lbm of CO2 per megawatt-hour.
Legislatively, the proposed US Senate Clean Energy Standard Act of 2012 would
implement a credit system to reduce CO2 emissions. A study by the DOE and the Energy
Information Agency (EIA) to evaluate the effects of this policy concluded that virtually
no electrical generation will occur in 2035 from US coal plants that use CCUS
technology even though CCUS is awarded nearly a full credit under the proposed policy.
The policy predicts a significant shift in the long-term electricity-generation mix
in the US by 2035, with coal-fired generation falling to 54% below the reference-case
level. Combined heat and power generators fired by natural gas increase substantially
through 2020, and nuclear and nonhydropower renewable generation plays a larger
role between 2020 and 2035. The proposed policy could reduce US electric-power-sector
CO2 emissions to 44% below the EIA’s reference case in 2035. National average
delivered electricity prices could increase gradually to 18% above the reference case
by 2035. However, there will still be a need to use the CO2 from the gas-powered plants
in the US and coal-powered plants worldwide by CCUS or other methods. These conclusions
concur with recent reports published by some major oil and gas entities on
the future of natural gas for electrical generation in the US.
The need for pure CCS in developed countries such as the US may not be as great
as in developing countries; but, the US and other developed countries have the ability
and capability to implement CCS through CCUS.
Read the paper synopses in the July 2012 issue of JPT.
John D. Rogers, SPE, is vice president of operations for Fusion Reservoir Engineering Services. With 30 years of experience, he previously worked as a production/operations engineer for Amoco, as a research scientist for the Petroleum Recovery Research Center of New Mexico Tech, and for the National Energy Technology Laboratory of the DOE. Rogers holds BS and PhD degrees in chemical engineering from New Mexico State University and an MS degree in petroleum engineering from Texas Tech University. Rogers has contributed to more than 30 publications and has served on several SPE editorial and conference committees. He currently serves on the JPT Editorial Committee.
“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
Read the paper synopses in the July 2012 issue of JPT.
Simon Chipperfield, SPE, is team leader of central gas exploitation at Santos. During the past 15 years, he has held positions in petroleum engineering (drilling, completions, and stimulation) and reservoir engineering. Chipperfield previously worked for Shell International E&P. He was awarded the 2007 SPE Cedric K. Ferguson Medal. Chipperfield has authored more than 20 technical publications in the areas of hydraulic fracturing, reservoir engineering, completion technology, and sand control. He holds a petroleum engineering degree with honors from the University of New South Wales. Chipperfield serves on the JPT Editorial Committee and the SPE International Awards Committee and has served as a reviewer for the SPE Production & Operations journal.
Calling all technology champions! A few years ago, I ran across the seven steps to stagnation,
which was a list originally compiled by Erwin M. Soukup. I got a feeling of déjà
vu reading through this list because I had heard these same words spoken from many
managers and peers over my career. If you search for these seven steps on the Internet,
you will find different variations; however, the message is the same. The seven
- We have never done it that way.
- We are not ready for that yet.
- We are doing all right without it.
- We tried it once, and it did not work out.
- It costs too much.
- That is not our responsibility.
- It will not work.
Great ideas for technology improvement or development can have an early demise
when faced with feedback similar to what is on this list. Even with a patent, a product
may never be commercialized without someone to be its champion. While we are fortunate
to have many technology champions in the area of artificial lift, we need more.
The best way to meet and learn from our industry’s best artificial-lift champions
is by attending some of the artificial-lift forums, workshops, and conferences coming
up in 2012 and 2013. Please check out the global events calendar on www.spe.org.
One major SPE artificial-lift event you will not see on the global calendar, however, is
the 2013 Electric Submersible Pump (ESP) Workshop. This is still a section-sponsored
event; however, it has grown to be the primary conference for the ESP industry (the
most-recent event had 560 attendees from 24 countries). Please go to this address for
more information: http://www.spegcs.org/committee/esp-workshop/.
The first paper highlighted features the use of a downhole linear motor to drive a
reciprocating-pump system. This is a new technology that is also featured in two papers
to be presented at the 2012 Annual Technical Conference and Exhibition in San Antonio,
Texas, this October. The two other highlighted papers focus on offshore artificial-lift
systems and discuss the unique challenges and concepts being applied.
Read the paper synopses in the July 2012 issue of JPT.
Shauna Noonan, SPE, is a staff production engineer for ConocoPhillips, where she works as an artificial-lift specialist in the Completions and Production Technology group. Noonan’s responsibilities include development and validation of artificial-lift and completion systems for thermal applications and improving artificial-lift reliability. She has worked on artificial-lift projects worldwide at ConocoPhillips and previously at Chevron for more than 18 years. Noonan has been chairwoman of industry forums and committees and has authored or coauthored numerous papers on artificial lift. She serves as a member of the SPE Production and Operations Advisory Committee, as an Associate Editor for the SPE Production & Operations journal, and as a member of the JPT Editorial Committee. Noonan began her career with Chevron Canada Resources and holds a BS degree in petroleum engineering from the University of Alberta.
This year, there were approximately 200 papers on simulation to select from—and that is after a separate feature on history matching. So, the discipline continues to be active. A noticeable feature is the growing number of simulation papers that use different technology, in the broadest sense of the term—for example, using concepts from signal processing and electrical engineering to model subsurface flow or related phenomena. However, the dominant technology remains finite different representations of Darcy’s law, conservation of mass, and a fluid model.
What is also heartening is the fact that all significant papers on case studies start with descriptions of the geology and often include detailed description of 3D geological modeling. Any simulation that is based on a physical model of the field must surely depend on the quality of the geological model used as input; yet, not that long ago, it was normal to pay only scant regard to the geology when constructing a model and even less when altering it during history matching.
Recent discussion within the SPE Simulation Technical Interest Group has raised the issue of pseudorelative permeabilities, with some arguing that they are obsolete and others strongly disputing the claim. Sadly, there were no papers on the subject that I could include in this feature. The relative permeability curve is where engineering meets geology; anyone involved in complex projects—and who of us is not— knows that it is at the interfaces that complexities arise and are too often ignored. The same is true in our models, so surely relative permeabilities and their multiphase upscaling are topics worth renewed investigation.
All three of the case studies I have selected, which are all from very different settings and parts of the world, were studies directed toward making tangible decisions (e.g., selecting well locations and completion intervals). This highlights once again that good simulation studies are directed toward decision making; having a clear sight of the purpose of the work improves the quality of the work and, thus, of the ultimate decision. The converse is also true.
View the paper synopses in the July 2012 issue of JPT.
Martin Crick, SPE, is chief petroleum engineer with Tullow Oil, responsible for all aspects of reservoir and production engineering in the group worldwide. Previously a principal reservoir engineer with Schlumberger, he was responsible for the design of the reservoir-engineering features in Petrel and, most recently, for a review of well test interpretation workflows within Schlumberger. Crick’s experience over 24 years in the industry has focused on reservoir engineering and, especially, simulation in support of field development planning initially with AEA Technology on contract to the UK government on a wide range of North Sea fields and then with Texaco on Erskine, the first high-pressure/high-temperature field on production in the UK North Sea, and on Karachaganak, the giant gas/condensate field in Kazakhstan. He holds a BS degree in physics from the University of Bristol.