bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Conferences Highlight Indian, North African E&P Efforts
Authors: JPT staff _ 
Published: February 2015

Techbits
Two conferences held recently highlighted the challenges and opportunities unique to E&P activities in two important oil and gas regions, India and North Africa.
SPE Oil and Gas India Conference and Exhibition (OGIC)
The SPE OGIC, held in January in Mumbai, had an overarching theme of “E&P Business: Excellence Out of Turbulence.” The event, which marked the first conference organized by SPE in India, brought together more than 1,200 industry leaders representing 167 companies from 30 countries to discuss new means of managing risks at times when oil prices undergo wide fluctuations.
To open the conference, Murli Deora, the Government of India’s Minister of Petroleum and Natural Gas, sent a message that included his best wishes for the conference’s success and emphasized its importance to the region. “We need to deploy our best brains to find technologies which can bring [oil and gas] resources to the realm of affordability and sustainability and at a scale which would aid in furthering the region’s economic activities,” Deora said. “There is no single solution. There is no single company, nation, or technology that can meet our energy challenges, all on their own. Sustainable energy solutions would require increasing collective attention and efforts.”
Following the inauguration of the event, a VIP tour of the venue and exhibition space took place, which included dignitaries R.S. Sharma, chairman and managing director of Oil and Natural Gas Corporation (ONGC); Sudhir Vasudeva, OGIC chairperson; and 2010 SPE President Behrooz Fattahi. Several of the 30 companies exhibiting at the conference launched new products, including new rotary steerable systems designed to create smoother wellbores and new multiphase-flow measurement devices that do not require separation of fluids.
An executive plenary session followed, in which panelists including N. M. Borah of Oil India, Derek Fisher of BG India, A.K. Balyan of ONGC, and James McCallum of Senergy shared their regional and international insights on how oil and gas companies are committed to exploring more efficient methods and integrating advanced technologies to enhance their operations and improve productivity.
The first day also included several technical sessions that explored E&P topics such as well simulation, unconventional-resource extraction, reservoir characterization, facility engineering, and drilling challenges. The day closed with a special session titled “Management of Mega Projects,” which addressed the optimum ways to design and manage mega E&P projects, to reduce their intensive capital investments, and the best strategic approaches to improve a project’s overall management process.
The Geared Centrifugal Pump: A New High-Volume Lift System
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 123938, ’The Geared Centrifugal Pump: A New High- Volume Lift System,’ by J.C. Patterson, SPE, ConocoPhillips; W.B. Morrow, SPE, Harrier Technologies.; and M.R. Berry, SPE, Mike Berry Consulting, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.
The geared centrifugal pump (GCP) is a high-volume artificial-lift system consisting of a progressing-cavity-pump (PCP) -style rotating rod string driving a bottom-intake electrical-submersible-pump (ESP) -style multistage centrifugal pump by use of a downhole speed-increasing transmission. The heart of the system is the unique transmission that uses a novel gearing configuration that allows high torque and power. The GCP provides the high-volume lift of an ESP but with better gas handling, simpler operation, and lower capital and operating costs.
Introduction
The GCP is an artificial-lift system consisting of the rotating-rod-string drive of a PCP, driving the multistage centrifugal pump of an ESP by a downhole speed-increasing transmission. The transmission is required to increase the relatively slow rotational speed of the PCP rod string, typically less than 500 rev/min, up to the 3,500-rev/min operational speed of the centrifugal pump.
The GCP was developed as an artificial-lift system to provide the high-volume lift of an ESP without the expensive and troublesome downhole electric motor and cable of the ESP system. The GCP uses efficient and relatively inexpensive industrial electric motors in the surface drive head, requiring none of the special controls or transformers necessary for high-voltage ESP motors. The rotating rod string transmits power downhole with low power losses. This system combines the highly efficient GCP transmission assembly with a modern ESP pump. This combination results in a system with lift efficiency greater than 50%. Because all of the downhole components of the GCP are mechanical, the design is adaptable to very-high-temperature applications such as steam-assisted gravity-drainage (SAGD) projects.
GCP Components
Drive Head. The GCP uses the same drive system as a PCP system. A surface drive head turns a rotating rod string that drives the downhole assembly. The only difference between a PCP drive head and one built for the GCP is the load-capacity requirements of the thrust bearing carrying the rod load. In a PCP drive head, the thrust bearing must carry the weight of the rod string as well as the fluid load. Because the rod string of the GCP does not carry any fluid load, the thrust bearing in the GCP drive head can have a correspondingly lower capacity. Another characteristic of both PCP and GCP drive heads is prime-mover flexibility. Although the majority of well locations have electric power, the GCP can be powered by an internal-combustion engine, a hydraulic motor, or an electric motor.
Annular-Velocity Enhancement With Gas Lift as a Deliquefication Method
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 130256, ’Annular Velocity Enhancement With Gas Lift as a Deliquification Method for Tight Gas Wells With Long Completion Intervals,’ by S.A. Pohler, SPE, W.D. Holmes, SPE, and S.A. Cox, SPE, Marathon Oil Corporation, originally prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed.
It is common practice in the industry to complete multiple reservoirs in a single wellbore to establish commercial production rates from tight gas completions. In some cases, these zones are separated vertically by several hundred to more than 1,000 ft. The deliquefication of these completions is one of the most challenging problems facing our industry. Many of the deliquefication methods currently being used are effective over only a portion of the wellbore.
Introduction
It is common practice to complete tight gas wells with the tubing tail above the bottom perforation. This completion practice allows static liquid to stand across the lower set of perforations. Static liquid standing across the perforations promotes increased near-well liquid saturations through a process of spontaneous imbibition. The imbibition process is a damage mechanism that can be present upon initial completion and can continue throughout the productive life of the well if allowed to form through ineffective liquid-removal/completion practices.
There are a number of different methods currently in use for the deliquefication of gas wells. Some of the more common are plunger lift, chemical-foam lift, and conventional pumps (i.e., rod pumps, electrical submersible pumps, and progressing-cavity pumps). Each method has drawbacks when it comes to deliquefying wells with long completion intervals. Effective liquid removal can improve overall well performance significantly. However, an effective system cannot ignore the potential presence of a static liquid column. Current completion technology has been found to have limited effectiveness when long productive intervals are involved. Therefore, a modified continuous-flow gas lift system is proposed that includes a packer and crossover system and that allows for gas lifting the well below the bottom perforation. The details of this completion process and its field applications are discussed in the body of the full-length paper.
Technology Focus: CO2 Applications (July 2010)
Authors: Gomersall Sam 
Published: February 2015

Technology Focus
“CO2 storage is just a hole in the ground.”
The creation of an effective carbon-capture and -storage (CCS) project involves a complex relationship between a CO2 emitter and a CO2-storage provider and the alignment of each of their major project developments. Power generators, who are major emitters of CO2, generally have little knowledge or interest in the subsurface and are prone to oversimplification—on occasions representing storage as a “hole in the ground.” Conversely, oil and gas operators do not see CO2 storage as part of their range of business activities, unless it involves enhanced oil recovery or provides a solution to unlock a gas project with a high CO2 content. As a result, the wider oil and gas sector is not yet fully engaged with the CCS opportunity.
Without a full appreciation of the end-to-end CCS project, it is difficult to ensure effective risk allocation. Power generators tend to take the lead on CCS projects, and experience to date suggests that storage-related issues are not considered sufficiently during the early stages of these projects. To progress, each industry must play its part: providing greater clarity over the nature of the challenges and being willing to understand the other’s issues. The academic sector has identified the funding opportunities that come with CCS and plays an important part in developing and sharing relevant knowledge within and across industries.
However, such knowledge sharing comes with responsibilities. These responsibilities include being very clear about material presented. By way of example: Assessments of capacity to store CO2 sometimes include extreme over- or underestimates (e.g., through approximation or the selection of specific, but unusual, reservoir assumptions). Such material then is used by proponents of one argument (e.g., “storage will never work”) or another (e.g., “storage is just a hole in the ground”) to justify their position.
Of course, the reality is that CO2 storage is a complex matter requiring the effective application of all the subsurface knowledge that we have to identify, appraise, select, and develop suitable storage reservoirs. Effective communication across industries is key to the success of CCS.
CO2 Applications additional reading available at OnePetro: www.onepetro.org
SPE 127080 • “The Application of Environmental-Impact Assessment in Carbon Capture and Storage” by Evert Holleman, Royal Haskoning, et al.
SPE 124002 • “CO2-ECBM/Storage Activities at the San Juan Basin Pump Canyon Test Site” by George J. Koperna Jr., SPE, Advanced Resources International, et al.
SPE 126444 • “Development of Storage Coefficients for Determining the Effective CO2 Storage Resource in Deep Saline Formations” by Charles D. Gorecki, SPE, University of North Dakota, et al.
Offshore Drilling and Public Service
Authors: Bromwich Michael 
Published: February 2015

Guest editorial
Approximately a year ago, in June 2010, US President Barack Obama and Secretary of the Interior Ken Salazar asked me to serve as director of the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). Two months earlier, the Deepwater Horizon exploded, taking the lives of 11 men, injuring 17 others, and causing nearly 5 million bbl of oil to spill into the Gulf of Mexico. It was an event with enormous human and environmental consequences, which will leave a lasting legacy. It was an event that jolted industry and government alike.
In the wake of Deepwater Horizon, BOEMRE has raised the bar for safety, oversight, and environmental protection at every stage of the drilling process. We have made significant progress, but there is still much work to be done. One of the most pressing issues facing the agency is ensuring that we can fill our ranks with the nation’s best and the brightest engineers and scientists.
Strengthening Regulations
First, a brief look at the reforms we have undertaken. Among the central tasks that needed to be addressed was the strengthening of the rules and regulations that govern offshore drilling. We needed to enhance drilling and workplace safety and provide additional protection for the environment. We did so quickly and responsibly. Within a few short months, we developed and implemented two important new rules.
The first rule, the Drilling Safety Rule, created tough new standards for well design, casing, and cementing, and new rules for well control procedures and equipment, including blowout preventers. Operators are now required to obtain independent third party inspection and certification of the proposed drilling process, and an engineer must certify that blowout preventers meet new standards for testing and maintenance and are capable of severing the drill pipe under anticipated well pressures. The second rule, the Workplace Safety Rule, requires operators to systematically identify risks and establish barriers to those risks and thereby seeks to reduce the human and organizational errors that lie at the heart of many accidents and oil spills.
In addition, operators must now have a plan and the demonstrated ability to shut in a deepwater blowout and capture oil flowing from a wild well. Thus, rather than improvising a containment response on the fly—with the hits and misses we saw during the attempts to bring the Macondo well under control—each operator must develop a containment plan that includes demonstration of access to containment technology such as a capping stack, and BOEMRE has to approve this plan.
Oil Shale: The Rock That Burns
Authors: Beckwith Robin 
Published: February 2015

The term “oil shale” refers generally to fine-grained sedimentary rock that contains solid bituminous materials, called kerogen, which can be converted into liquid and gaseous hydrocarbons (petroleum liquids, natural gas liquids, and methane) when the rock is heated in the chemical process of destructive distillation known as pyrolysis. Oil shale is found in a variety of depositional environments, including fresh water to highly saline lakes, epicontinental marine basins and subtidal shelves, and in limnic and coastal swamps, commonly in association with deposits of coal. Unlike crude oil or even tar sands, oil shale has not been subject to high enough heat over a long enough period of time to break the complex solid hydrocarbons down into lighter, liquid and gaseous compounds. One of its defining characteristics, however, is that it contains enough oil to burn without further processing, giving rise to its Ute Indian name, “the rock that burns.”
According to Jeremy Boak, director of the Center for Oil Shale Technology and Research, “oil shale” is not a misnomer, as is commonly held. “If oil shale is not shale,” he said, “then neither is the Barnett, the Haynesville, the Niobrara, or the Eagle Ford.” The difference is that shale oil, as currently used for plays like the Bakken and Eagle Ford, refers to rock that contains liquid hydrocarbons, and oil shale refers to rock that yields hydrocarbons upon heating under appropriate conditions. Many names have been used for oil shale over the centuries, such as albertite, algal coal, alum shale, bituminite, boghead coal, cannel coal, gas coal, kerosene shale, kukersite, schistes bitumineux, stellarite, tasmanite, torbanite, and wollongongite. Some of these names are still in use.
The organic matter in oil shale—composed chiefly of carbon, hydrogen, oxygen, and small amounts of sufur and nitrogen—is predominantly kerogen, which by definition is an organic material that is typically insoluble in ordinary organic solvents. The mineral and elemental content of oil shale differs distinctly from coal. The ash (or mineral) content of coal is generally less than 40 weight percent (wt%), whereas oil shale commonly has an ash content greater than 60 wt%. The organic matter of oil shale typically has a higher hydrogen and lower oxygen content than that of lignite and bituminous coal.
Technology Focus: CO2 Applications (July 2011)
Authors: Rogers John D. 
Published: February 2015

Technology Focus
The CO2 supply-and-demand trends for enhanced-oil-recovery (EOR) projects are diverging, and many EOR projects, especially in the US, are hindered by lack of sufficient economic CO2 volume and infrastructure. The CO2-supply deficiency—and because a portion of the estimated 30+ Gt/year of anthropogenic CO2 worldwide could supply future EOR projects sufficiently—is driving the EOR industry to be an enabler for early carbon-capture-and-storage (CCS)/sequestration technology and infrastructure development. As EOR/CCS develops, the potentially huge, yet unproven, storage capacity of deep saline formations may become more realistic. The methodology of how to quantify and use saline aquifers is in the developing stages with technical debates.
Geotechnical and transportation issues for CCS are similar to those for EOR processes, but there are differences because of their different purposes. EOR projects have fairly short-term time scales, of several 10s of years after initiation of EOR processes. CCS projects have similar 10s of years of injection time, but indefinite time scales (1,000s of years) for the mineralization processes to be effective. Geological and mineralogical models; coupled geochemistry, geomechanical, and transport models; seal-integrity issues typical of hydrocarbon-phase-behavior physics; large time-scale differences; subsurface uncertainties; and limited or no performance data complicate optimization of CO2-capacity determination and efforts to model the CCS process(es) and sites compared with modeling typical or even atypical EOR projects.
Except for natural-gas plants, business models of large stationary facilities generally view CO2 as a waste. To an operator, CO2 is an expensive but useful fluid to enhance hydrocarbon recovery. In May 2010, the US Environmental Protection Agency issued its final rule addressing greenhouse-gas emissions from large stationary sources and defined CO2 as a pollutant at certain high concentrations, not as a waste. Future business venues for EOR/CCS most likely will include partnerships and alliances with power plants and other large stationary generators to provide and economically capture, use, and store CO2, thus creating a limited CCS industry enabled by the EOR industry.
CO2 Applications additional reading available at OnePetro: www.onepetro.org
SPE 139588 • “The Significance of Caprock-Sealing Integrity for CO2 Storage” by A. Busch, Shell, et al.
SPE 134028 • “Drainage and Imbibition CO2/Brine Relative Permeability Curves at Reservoir Conditions for Carbonate Formations” by D. Brant Bennion, SPE, Weatherford, et al.
SPE 131609 • “Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK” by Min Jin, SPE, Heriot-Watt University, et al.
SPE 139716 • “Perspectives on CCS Cost and Economics” by H.S. Kheshgi, SPE, ExxonMobil, et al.
Spectrum: Building Our Future
Authors: Thakur Ganesh 
Published: February 2015

President's column
The future of our industry is challenging; it is geologically challenging, technologically challenging, and financially challenging, and it is resource intensive. Reservoirs are increasingly difficult and costly to develop and oil and gas comes at a higher cost of extraction. A host of other possible roadblocks complicate this future, including public concern about water issues; environmental impact assessments perhaps limiting access to resource; growth in regulations; and longer permitting processes. This is not an easy scenario.
To achieve the production demands of the future, a significant increase in global energy-related investment will be needed over the next 20 years, especially in technology development. But I believe an even larger piece of global oil and gas investment needs to be in people.
Although the economic downturn has delayed retirements, many engineers and geoscientists working in our industry will retire in the next 5 to 10 years. With the experienced professionals leaving the workforce, our young professionals (YPs) are being asked to take on more responsibilities earlier in their careers. This means that YPs must acquire broad technical and soft skill sets to be able to perform the complex tasks required of them. This requisite, coupled with the increasing complexity of the E&P environment, compounds the challenges facing the industry.
To attract and retain the kind of world-class technical expertise we need to succeed today and tomorrow, we must be willing to invest in extensive training programs that focus not only on the hard technical skills, but also on soft skills such as teamwork and interpersonal communication. This approach will enable YPs to give our industry their best in the fast-moving, team-driven workplace that technology solutions increasingly require.
So how do we attract the talent and accelerate their development? The answer is fundamental to SPE’s purpose: through the power of information dissemination and collaboration.
Sharing knowledge and best practices are essential to help accelerate the time it takes for YPs to reach their full productivity. This is a subject that SPE, especially the board of directors, is very passionate about. SPE has many resources that promote the YPs’ ability to learn from both experienced professionals and each other, and to build valuable networks that will serve them well throughout their professional life, resulting in a stronger industry as a whole.