If you are here then, like me, you must be curious on what is the P&O community is up to? Well that is the idea of this place (page) and its linked websites. As the Production and Operations Technical Director, it pleases me to welcome you to your window on the production and operation world of activities. The P&O Discipline Page, as we will refer to this website, belongs to you, the P&O members and is administered by the SPE staff. We hope you will make it your gateway to explore and discover what is new in technology, where the upcoming events are and who authored the latest papers on your favorite subjects.
We encourage you to make it an active and viable website so as to spread the knowledge and share the benefits. I hope to be able to update this blog every month and whenever new or important happenings take place. I expect and solicit your input, and look forward to your feedback; please keep your contributions coming.
Finally, please watch this space as work is underway to update and roll the new P&O Technical Section community site with its attempt to provide a more focused technical feed to you, our members, on several main work tracks of the P&O community. We intend to link the technical section seamlessly to your P&O Discipline Page. Happy web-surfing everyone.
Subsea completions have made it possible to produce oil in remote locations and from smaller reservoirs. But the cost of maintaining them may shorten their productive lives.
“Subsea wells have the same things that go wrong as other wells, but fixing them requires moving in a rig and the cost can often be USD 1 million a day,” said Matthew Law, technical manager of sales and marketing at Expro Ax-s Technology. “Where there is direct access from a production platform, there is generally regular well intervention. As a result, the recoverable reserves are higher.”
Major producers such as BP, Chevron, ExxonMobil, Statoil, and Shell are among those seeking to cut the cost of deepwater workovers by 50% or more to allow better maintenance. There is no accepted industry average for how much production can be gained from regular interventions. The consensus is that the potential impact on the thousands of subsea completions represents billions of dollars worth of hydrocarbons.
Read the entire article in the January 2012 issue of JPT.
Revitalizing mature fields embraces multiple objectives, especially maximizing production while minimizing capital expense and reducing the inevitable decline rate and minimizing the operating expense. The collective approach to meet these objectives is application of practical and focused engineering and geology tied with the application of enabling technologies.
Key enabling technologies in the revitalization of mature fields include reservoir simulation, advanced characterization techniques (e.g., 3D seismic and new measurement, tomographic, and visualization techniques), permanent downhole reservoir monitoring, horizontal and multilateral drilling, geosteering, production-enhancement techniques (e.g., secondary- and tertiary-recovery schemes), improved perforation and stimulation methods, new fracturing techniques and fluids, cutting-edge completion technologies, advanced logging techniques, artificial-lift optimization, and conformance control.
Implementation of appropriate enabling technologies can extend the producing life of mature fields. Yet the complexity of some of these fields can still present formidable challenges. It takes the right data, the right tools and techniques, and the right team to create an efficient, cost-effective field-development plan to optimize an aging asset.
Read the paper synopses in the January 2012 issue of JPT.
Syed A. Ali, SPE, is a research advisor with Schlumberger. Previously he was a Chevron Fellow with Chevron Energy Technology Company. Ali received the 2006 SPE Production and Operations Award. He earned BS, MS, and PhD degrees. He served as the Executive Editor of SPE Production & Operations and currently serves on several SPE committees, including the JPT Editorial Committee and Well Completions Subcommittee.
140937-PA – Review of Electrical-Submersible-Pump Surging Correlation and Models
Jose Gamboa and Mauricio Prado, The University of Tulsa
142764-PA – Assessing Gas Lift Capability To Support Asset Design
James W. Hall, SPE, and Mubarak A.M. Jaralla, Qatar Petroleum
144573-PA – World’s Deepest Through-Tubing Electrical Submersible Pumps
J.Y. Julian, SPE, BP; J.C. Patterson, SPE, ConocoPhillips; and B.E. Yingst, SPE, and W.R. Dinkins, SPE, Baker Hughes
140228-PA – Case History: Lessons Learned From Retrieval of Coiled Tubing Stuck by Massive Hydrate Plug When Well Testing in an Ultradeepwater Gas Well in Mexico
Victor Vallejo Arrieta, Aciel Olivares Torralba, Pablo Crespo Hernandez, and Eduardo Rafael Román García, PEMEX; and Claudio Tigre Maia and Michael Guajardo, Halliburton
134483-PA – New Perspective on Gas-Well Liquid Loading and Unloading
C.A.M. Veeken, SPE, NAM, and S.P.C. Belfroid, SPE, TNO
View the entire August 2011 issue of SPE Production & Operations.
98774-PA – What Would Be the Impact of Temporarily Fracturing Production Wells During Squeeze Treatments?
Abdul Al-Rabaani, PDO, and Eric J. Mackay, Heriot-Watt University
141384-PA – Modeling the Application of Scale-Inhibitor-Squeeze Retention-Enhancing Additives
O. Vazquez, Heriot-Watt University; P. Thanasutives, PTT Exploration and Production Plc; C. Eliasson and N. Fleming, Statoil; and E. Mackay, Heriot-Watt University
132535-PA – Laboratory Study of Diversion Using Polymer-Based In-Situ-Gelled Acids
A.M. Gomaa, SPE, M.A. Mahmoud, SPE, and H.A. Nasr-El-Din, SPE, Texas A&M University
133380-PA – Methods for Enhancing Far-Field Complexity in Fracturing Operations
Loyd East Jr., SPE, Halliburton; M.Y. Soliman, SPE, Texas Tech University; and Jody Augustine, SPE, Halliburton
It was not long ago that finding a natural-gas field beneath your property was viewed universally as a stroke of good luck. Now, local natural-gas development is feared by many who assume the “new technology” of “fracing” is environmentally harmful. In reality, the first hydraulic-fracturing treatment was tested in a North Carolina granite quarry way back in 1903. Hydraulic fracturing has been used successfully in more than a million wells since then, and, currently, hundreds of fracturing stages are pumped every day. Very impressive for a “new” technology!
Partly because of these very successful and trouble-free wells, natural gas has enjoyed an enviable reputation as a clean, cheap, and abundant energy source. However, we need only to look to the nuclear industry to see that a hard-won reputation can be ruined by false rumors, isolated incidents, or the worst examples of safety, environmental, and reporting practices. If we always strive to be good neighbors in the communities in which we work, we can remain proud natural-gas producers for years to come.
Because stimulated wells make up an increasing portion of supply with each passing year, we have become dependent upon wells that require additional attention and often exhibit high decline rates. To buffer the supply/demand swings, gas-storage wells are used for both injection of dehydrated pipeline gas and production of newly saturated formation gas. Water-vapor equilibrium will reduce the water saturation around injection wellbores but may increase salt precipitation in the same region. A new study from the Middle East describes a means of maximizing sand-free gas-production rates from wells in unconsolidated zones, without a difficult-to-place hydraulic fracture. A third paper describes a means of identifying well candidates that may need a second treatment because of deterioration of the original fracture or the need to access additional reservoir. A downloadable full-length technical paper provides a new decline-curve functional form that can match unconventional wells with long transient-flow periods w hile honoring late-time interference and depletion. These papers provide some legitimately new technology.
Read the paper synopses in the November 2011 issue of JPT.
Scott J. Wilson, SPE, is a Senior Vice President of Ryder Scott Company. He specializes in well-performance prediction and optimization, reserves appraisals, simulation studies, software development, and training. Wilson has worked in all major producing regions in his 25-year career as an engineer and consultant with Arco and Ryder Scott. He is Cochairperson of the SPE Reserves and Economics Technical Interest Group and serves on the JPT Editorial Committee. Wilson holds a BS degree in petroleum engineering from the Colorado School of Mines and an MBA degree from the University of Colorado. He holds two patents and is a registered professional engineer in Alaska, Colorado, Texas, and Wyoming.
The science behind the use of microbes to enhance oil recovery has advanced significantly, but it suffers from old associations.
After decades of trial and error, those working on microbial enhanced oil recovery have identified the “oil-eating” bacteria that laboratory tests suggest can change the properties in an oil reservoir, and know better how to put them to work. The increasing knowledge of the role microbial life plays in oil and gas reservoirs has also led to new approaches for controlling corrosion, managing bacterially-produced hydrogen sulfide, and creating natural gas from coal.
(In this story, “eat” is used to describe the metabolic processes of bacteria. For instance, oil eating is more precisely hydrocarbon oxidizing.)
But the greatest potential payoff and the most debate come from the idea of microbes for enhanced oil recovery (MEOR). “There is a much greater understanding of what microbiology is doing in a reservoir” and how that can be used to produce more oil, said Stuart Page, chief executive officer of Glori Energy, a company that has staked its future of convincing the industry that microbes can be used to recover more oil.
Read the full article from the November 2011 JPT.