bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Artificial Lift (July 2008)
Authors: Scott Stuart L. 
Published: February 2015

Technology Focus
Artificial lift plays a fundamental role in several international plays. This month, artificial lift in oil-sand and deepwater developments is highlighted. In both cases, artificial lift is not just accelerating production but is vital to the economic success of the overall development.
Today, the Canadian oil-sand developments have followed these different approaches: mining, cyclic steam injection, and steam-assisted gravity drainage (SAGD). As reservoir depth increases, artificial lift, rather than mining, is used to bring hydrocarbons to the surface. While cyclic steam injection and SAGD both push the high-temperature envelope for pumping, new techniques are being proved for this harsh environment. During the production phase of cyclic steam injection, the wells initially flow to the surface. Later production moves into the "flumping" stage (simultaneous flowing and pumping) and then into pumping. While sucker-rod pumping has been dominant, progressing-cavity pumps and electrical submersible pumps (ESPs) are being proved under these extreme conditions. In addition to downhole pumping, there is widespread use of surface multiphase pumps. Technologies that allow pumping high-temperature fluids without cooling represent opportunities to retain heat and improve the overall process efficiency. Surface pumping of a high-temperature multiphase mixture has become an established technology in Alberta.
For deep water, artificial lift plays a strategic role, enabling companies that possess advanced technology to develop fields that other companies may determine to be too difficult. The ability to deliver an advanced artificial-lift system is the difference between booking reserves and walking away from deepwater discoveries. Only recently have we seen rapid growth in the application of subsea multiphase pumping. In addition to seafloor boosting, several other artificial-lift methods are applied in deep water, including gas lift and wellbore ESPs. In all cases, the ultimate success of these developments depends on the reliability of the artificial-lift system combined with the cost of intervention.
Artificial Lift additional reading available at the SPE eLibrary: www.spe.org
SPE 113904 • "Recent Advances and Practical Applications of Integrated Production Modeling at Jack Asset in Deepwater Gulf of Mexico" by Umut Ozdogan, Chevron Energy Technology Company, et al.
IPTC 11594 • "A New Approach to Gas Lift Optimization Using an Integrated Asset Model" by Fernando Gutierrez, Schlumberger, et al.
SPE 110234 • "Overview of Beam-Pump Operations" by O. Lynn Rowlan, Echometer Company, et al.
Additional reading available at OnePetro: www.onepetro.org
OTC 18820 • "The Use of Subsea Gas Lift in Deepwater Applications" by Subash S. Jayawardena, Shell Global Solutions, et al. (See JPT June, 2008, page 64.)
First Metal-PCP SAGD Field Test Shows Promise for Heavy-Oil Hot Production
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110479," World's First Metal-PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case" by Jean-Louis Beauquin, SPE, and Felix Ndinemenu, SPE, Total E&P; Gilles Chalier, Total E&P Canada; Lionel Lemay and Laurent Seince, PCM; and Alex Damnjanovic, KUDU Industries, originally prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed.
Finding a reliable artificial-lift (AL) pumping system for heavy-oil thermal recovery has been a challenge, mainly because of the high operating temperatures (greater than 150ºC). Available options such as rod pumps and electrical submersible pumps (ESPs), which are well proved in the industry, are not well suited for thermal production. While rod pumps offer high-temperature service, they are limited in the flow rate they can deliver. ESPs can handle high volumes of low-viscosity fluids but are still limited in terms of maximum operating temperature. Metal progressing-cavity-pump (PCP) technology has been developed to meet the high-temperature requirement of steam-assisted gravity drainage (SAGD) and other thermal-recovery processes.

Introduction
Recovery of the world's large reserves of extraheavy oil (found mainly in the oil sands of Canada and Venezuela) by thermal processes has been increasing because of the high price of oil. Key to this recovery process is AL, which is required because of the very high density and viscosity of the crude and the relatively low reservoir pressures. Although gas lift remains an AL option when high pressure gas is available, pumping techniques are more popular because of their relatively higher efficiency and ability to generate more pressure at the surface for delivery to the treating plant. However, the main challenge with hot pumping is the high temperatures often required [as much as 260°C for SAGD and 350°C for cyclic steam stimulation (CSS)].
The dominant pumping technologies available are beam/jack pumps, ESPs, and elastomer PCPs. All these pumps have their peculiar limitations for hot production. While beam pumps offer high-temperature service, they are limited in the flow rate they can deliver. ESPs can handle high volumes of low-viscosity fluids, but they are still limited in terms of maximum operating temperature. For PCPs, the limitation is operating temperature of the elastomer (maximum 150°C).
Getting the Last Gasp: Deliquification of Challenging Gas Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper IPTC 11651, "Getting the Last Gasp: Deliquification of Challenging Gas Wells," by A.V. Bondurant, SPE, B.D. Dotson, SPE, and P.O. Oyewole, SPE, BP plc, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4–6 December. The paper has not been peer reviewed.
A common characteristic of "challenging" unconventional gas resources—namely, low-permeability sands, shale, and coalbed methane (CBM)—is that the ultimate recovery depends on economic removal of liquids accumulation, generally termed "deliquification." The problem affects thousands of wells, and the solution involves not only technology development but also knowledge management and building resource capability. Industry is working on a variety of deliquification technologies for challenging gas, with developments ranging from adapting existing oilfield technologies to developing gas-specific technologies to developing "on the horizon" technologies. Examples in each stage of development are presented.

Introduction
A distinguishing characteristic of North American land-based gas production is the large number of low-rate wells. In the continental US, the majority of gas wells produce less than 100 Mscf/D. The low rates reflect the maturity of North American gas production and the predominance of challenging production from low-permeability-sand (&lt;0.1 md), shale, and CBM reservoirs.
Low-rate gas wells almost always cease production because of liquid accumulation in the wellbore. Consequently, deliquification is of great importance. From a worldwide perspective, the current need for deliquification of low-rate wells is more modest. As production from high-rate wells declines, similar technical and economic challenges will be faced outside North America and will benefit from the solutions developed there.
For this study, a gas well is any well making 50 bbl/MMscf or less of stock-tank hydrocarbon liquids. An actively producing well is one having production reported in the second half of 2005. Production data from several eastern states, which tend to have very-low-rate gas wells, were not readily available and, therefore, were not included in this analysis. With these definitions, data were collected on 235,000 active producing gas wells in the major producing states for the second half of 2005.
Approximately 150,000 wells that produce less than 100 Mscf/D/well pro-duce approximately 7.5 Bcf/D collectively, 10% of the North American gas consumption. Most of these wells either are impaired by liquid accumulation or are producing with some form of artificial lift for deliquification. Deliquification in North America involves a very large well count, with generally a small incremental effect on each well.
Technology Focus: CO2 Applications (July 2008)
Authors: Gomersall Sam 
Published: February 2015

Technology Focus
In my view, carbon capture and storage* (CCS) will provide a significant global contribution to help mitigate climate change. However, the magnitude and timing of the contribution CCS can depend on several factors.

Making Action on Climate Change More Urgent.
While the science linking global warming with manmade CO2 emissions is clear, the pace of national and international political agreements for action requires time. As such, the framework for a post-Kyoto agreement is still unclear. While it is likely such an agreement will be reached, the exact nature will drive the level of urgency on climate-change action.

Creating a Commercial Value for Carbon.
The key to action in a commercially driven world is a valid cost on CO2 emissions. While a CO2 tax provides a predictable cost for industry, it does not provide governments with clear emissions-reduction levels. Conversely, CO2 cap-and-trade systems can provide governments with clearer emissions-reduction levels, but they leave industry with uncertain carbon prices. Therefore, industry often "favors" a tax-based approach and governments favor a cap-and-trade approach. The challenge for CCS is to have a sufficiently high price to justify the major capital investment. Experience indicates that the cap-and-trade approach takes many years to introduce and many additional years to adjust caps to create a market price that could justify investment in CCS.

Establishing Early Uptake of CCS.
Long-term investments in CCS are hampered by the lack of long-term political agreements and an appropriate carbon price, as outlined above. Early uptake of CCS, however, is required to prove the technology and ensure that supporting legislation can be put in place. Several projects are in advanced stages of engineering in Europe, the US, and Australia. Making these projects happen is crucial. With such early action, CCS has the potential to mitigate global CO2 emissions by 28% or more by 2050.
*CCS involves capturing flue-gas CO2, initially from large point sources such as power stations, and compressing the CO2 for transport before injecting it into the deep subsurface for indefinite storage. Most of the technologies required are available, but not all have been implemented commercially at the required scale. The situation is different for most currently operating projects, which involve separating CO2 from produced methane and then reinjecting that CO2 for long-term storage.
CO2 Applications additional reading available at the SPE eLibrary: www.spe.org.
SPE 108924 • "Geoengineering and Economic Assessment of a Potential Carbon-Capture-and-Storage Site in Southeast Queensland, Australia" by Y. Cinar, University of New South Wales, et al.
SPE 114028 • "CO2 Storage in Low-Permeability Formations" by Y. Cinar, University of New South Wales, et al.
SPE 108540 • "Simulations for CO2-Injection Projects With Compositional Simulator" by S. Hurter, SPE, Schlumberger Carbon Services, et al.
EU Policy Options for Regulating Carbon Capture and Storage
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 111824, "Policy Options in the EU for Regulating Carbon Capture and Storage," by David J. Williamson and Paul Zakkour, Environmental Resources Management Ltd., originally prepared for the 2008 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Nice, France, 15-17 April. The paper has not been peer reviewed.
Carbon capture and storage (CCS) represents a potentially useful tool to enable the European Union (EU) to manage its emissions of carbon dioxide (CO2) as it transitions from a fossil-fuel to a renewables energy strategy. The full-length paper examines the regulatory requirements for effective operation of CCS by identifying the issues and risks associated with the capture, transport, and storage of CO2, and reviews the regulatory options available and their applicability to the operation, management, and control of CCS.

Introduction
CCS is a widely recognized opportunity to enable EU member states to lower emissions of CO2 by the capture of carbon from large-scale emitters (e.g., power stations) and provide for the long-term, safe storage of this material in underground reservoirs. The EU has set targets for member states to reduce their total volume of CO2 emissions by 20% of 1990 levels by the year 2020. Achieving these targets in the time scales involved by reducing overall energy consumption or by transferring generation capacity to noncarbon-emitting alternatives is not a feasible option, and, therefore, alternatives must be sought.
While the EU will seek to provide a legislative framework that will enable and encourage the development of the infrastructure required to operate CCS effectively across its sphere of influence, there are particular challenges to be faced in drafting policy and regulation related to the unique nature of the CCS process.

Approach
The CCS process must be described and reviewed to outline the various technical tasks that must be carried out to achieve the goals of the process. In this case, there are three main areas that must be reviewed:CO2 capture.CO2 transport.CO2 storage.
Each of these parts of the process represents varying health, safety, and environmental (HSE) risk profiles. Each of these areas has regulatory analogs in which similar or related processes are subject to current EU and member-state regulation.
Ghana's Jubilee Celebration Nears
Authors: Sheehan John 
Published: February 2015

After more than 100 years of oil exploration and the drilling of 90 wells, the Republic of Ghana is now on the verge of truly benefiting from its offshore oil and gas riches. The partners in the country's Jubilee field—one of the most exciting developments offshore west Africa in recent times—are on track to produce first oil in the second half of 2010.
The speed of progress on the USD 3 billion development has been exceptional since the initial discovery was made with the Mahogany-1 well in 2007. The field, which is being developed with a conventional subsea system with 17 wells initially, tied back to a turret-moored floating production, storage, and offloading (FPSO) vessel, is located 60 km offshore in 4,101 ft (1250 m) of water and straddles two deepwater blocks—Tano and West Cape Three Points offshore Ghana.
Partner Tullow said this month that conversion of the Ohdoh VLCC tanker into an FPSO to tap the field and the fabrication of subsea equipment are well advanced. Five development wells have been drilled on the field, with a further seven wells planned for the remainder of this year.
The need for speed means that everything for the development is being kept as simple as possible, said Dave Hanley, Tullow's subsurface manager for Ghana. "Due to the compressed time frame for the development of phase 1 on Jubilee we are using designs for everything that are off the shelf. We are not really pushing the boat out in terms of technology. I do not think we could claim that we are on the cutting edge.
"We have a very tight time frame for construction and installation, which really prevents us from doing that. We are doing a tanker conversion for the FPSO to a design that is off the shelf and all the other equipment is well proven and readily available for this sort of water depth. Future phases may of course use more technology, based on learning from phase 1, but everything we are doing is well proven and has been done many times before."
Experimental Design Reduces Risks of a Siberian Development Having Subsurface and Financial Uncertainties
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115575, "Experimental Design Reduces Risks of a Siberian Development With Subsurface and Financial Uncertainties," by David E. Tipping, SPE, TNK-BP; Franz X. Deimbacher, SPE, and Dmitry Kovyazin, Schlumberger; Alexey Medvedev, SPE, Landmark; and Randy Valencia, TNK-BP, prepared for the 2006 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 28-30 October. The paper has not been peer reviewed.
Experimental-design methodologies were used to evaluate development options in a Siberian field having major uncertainties in geological, reservoir, and financial parameters. The approach demonstrated that an inverted seven-spot injection pattern would yield 11% more oil than a conventional linedrive method. For decision making, the analysis predicted that the expected net present value (NPV) of the seven-spot pattern would be 46% more than that of the linedrive pattern.

Introduction
The primary reservoirs in this Russian field consist of stacked fluvial, delta-distributary-channel, and mouth-bar sands. Exploration tests confirmed oil rates exceeding 120 tonnes/d. Recognizing this risk to project success, an experimental-design technique was developed for quantifying the uncertainties in oil-rate predictions.
The experimental-design techniques, integrated with advanced computer technology, reduced evaluation times from months to weeks. More importantly, they provided unbiased probabilities of production profiles and NPV so that downside risks can be quantified.

Development Context
The proposed development area encompasses two oil-bearing zones. The shallow zone consists of sand-stones with thicknesses varying from 0.5 to 3 m with numerous interbedded siltstones. The deep zone is in an underlying incised-valley-fill complex surrounded by impermeable siltstone.
Although the 2D seismic could delineate the boundaries of the incised valley, its resolution did not permit differentiating the sand bodies from the surrounding siltstone within the valley fill. A subsequent sedimentological review of core data revealed promising reservoir sands. Well tests of the valley-fill sand bodies yielded promising initial oil rates that exceeded 120 tonnes/d. However, major uncertainties existed.
Although the well tests confirmed the presence of an oil/water contact (OWC), given the thin nature of the sand bodies, the OWC response on the wireline logs was suppressed by surrounding siltstones. As a result, an OWC uncertainty of 4 m existed with potential adverse effect on the estimated oil initially in place.
Seismic data also revealed anomalies, possibly indicating faults acting as flow barriers. The seismic did not have sufficient resolution within the incised valley to differentiate sand bodies from the surrounding siltstones.
Results of the Brugge Benchmark Study for Flooding Optimization and History Matching
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119094," Results of the Brugge Benchmark Study for Flooding Optimization and History Matching," by E. Peters, TNO; R.J. Arts, TNO and Delft University of Technology; and G.K. Brouwer and C.R. Geel, SPE, TNO, prepared for the 2009 SPE Reservoir Simulation Symposium, The Woodlands, Texas, 2-4 February. The paper has not been peer reviewed.
In preparation for the SPE Closed-Loop Reservoir Management Workshop held in Bruges, Belgium, in June 2008, a unique benchmark project to test the use of flooding-optimization and history-matching methods was organized in the form of an interactive competition during the months preceding the workshop. In total, nine groups participated and presented their results during the workshop.

Introduction
Before the Bruges workshop, participants were allowed to conduct a closed-loop waterflood-optimization case study. TNO prepared a high-resolution reservoir model, dubbed the Brugge field, which served as the truth, and a data set was made available in January 2008. The data set consisted of the first 10 years of the production history of the field (including measurement errors), inverted time-lapse seismic data in terms of (uncertain) pressures and saturations, 104 scaled-up realizations of a 3D geological model, all the input for creating a reservoir model, and economic parameters (price and discount rate) for oil and water to calculate net present value (NPV).
The goal for the participants was to optimize the field NPV for the last 20 years. To do this, they first had to create a history-matched model or set of models from the data provided. Next, they had to optimize the waterflood strategy for the 30 wells for the next 10 years. All 10 injectors and 20 producers could be operated with three separately operable completions. The optimization strategy for years 11 through 20 then could be sent to TNO for testing on the Brugge field. The response could be used to improve the history match and the optimization for the last 10 years. The control strategy for the last 10 years could again be sent to TNO for testing on the Brugge field.
The full-length paper presents a summary of the results presented at Session 2 of the workshop. Because several participants continued working on the problem after the workshop, a summary of those results also is provided in the paper. To make the exercise more representative of a true closed-loop optimization, the exercise was repeated with one participant with a higher frequency of feedback. These results also are presented in the paper.