bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Deepwater Projects (May 2012)
Authors: Salies Jacques B. 
Published: February 2015

Technology Focus
No word defines deepwater projects better than “innovation,” and on 25 February 2012, one of the most innovative field-development projects came on stream: Cascade and Chinook (C&C) in the US Gulf of Mexico (GOM). One well is producing from Cascade to the first floating production, storage, and offloading (FPSO) vessel in the US GOM. The project brings several firsts and innovations that will be available to the entire oil industry in the near future. I would like to call attention to some of those innovations. First, the FPSO uses a detachable buoy that allows early installation of the buoy and all umbilicals before arrival of the FPSO. This feature will allow the FPSO to disconnect and sail away from hurricanes, avoiding damages to the facilities. C&C also presents the first freestanding riser in the US GOM. Subsea boosting will increase production and reduce workover costs. These examples are just a few that show innovation applied to a deepwater development. I believe strongly that C&C will lead the way for future development of Lower Tertiary plays in the GOM.
I selected one paper for this feature that describes the planning, logistics, and technology of the two largest deepwater high-pressure perforation jobs executed successfully in the GOM; certainly, this provides very interesting reading if your company is in the Tertiary play or is planning to be.
Drilling management in deep water has always been a great challenge because of several constraints, including high cost; well engineering (exploratory wells); logistics (remote locations); health, safety, and environmental (local and international laws); licenses; and personnel management. One of the papers presents a very objective and clear explanation of the well-management process, describing the design methodology and the well-execution procedures used by Petrobras International in a remote and challenging area. This methodology can be applied to any well and could bring huge benefits for any drilling operation.
Are you lost in a “cloud” of drilling data? You are not the only one! Drilling-data management is one of the biggest challenges in our industry today. One of the feature papers presents solutions, gives examples, and shows the benefits of a correct use of drilling data.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 145259 Drilling and Underreaming in the GOM Deepwater Ultradeep Lower Tertiary: History of a Record Run in the World’s Deepest Oil or Gas Well by Charles Ubaru, Baker Hughes, et al.
SPE 151487 Continuing Efficiency and Assurance Advances for Deepwater BOP Testing by C. Mark Franklin, SPE, IPT Global, et al.
OTC 21821 Versatility in Answering the Challenge of Deepwater Field Developments by Jackson D. Bullock II, Subsea 7, et al.
SPE 140954 Worldwide Pore-Pressure Prediction: Case Studies and Methods by Haixiong Tang, CNOOC, et al.
OTC 22092 Deepwater Drilling for Arctic Oil- and Gas-Resources Development: A Conceptual Study in the Beaufort Sea by N. Pilisi, Blade Energy Partners, et al.
Efficient Perforation of High-Pressure Deepwater Wells
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 21758, ’Efficient Perforation of High-Pressure Deepwater Wells,’ by William Sanders, SPE, Carlos Baumann, SPE, and Harvey Williams, SPE, Schlumberger, and Flavio Dias de Moraes, SPE, Jonathan Shipley, Martin Bethke, SPE, and Scott Ogier, SPE, Petrobras, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.
Thousands of perforating jobs are conducted successfully worldwide each month. However, for a small number of jobs, typically high-pressure deepwater wells, gun shock is a real and significant risk. The Cascade and Chinook projects presented the two largest deepwater high-pressure perforation jobs to date in the Gulf of Mexico (Fig. 1). These Lower Tertiary well completions have gross perforation intervals greater than 800 ft and downhole pressures higher than 19,000 psi. Perforating all intervals with long gun strings and then frac packing multiple zones in a single trip saves substantial rig time compared with performing conventional stacked frac-packed completions requiring multiple trips per perforated zone.
Introduction
Perforating several intervals in one run was required to complement a single-trip multizone frac-pack system in which all downhole packers, screens, and service tools are run at once and all zones are stimulated in a single trip. Planning, mobilizing, executing, and reviewing multizone perforating jobs at wellbore pressures higher than 19,000 psi and in water depths greater than 8,000 ft presents many challenges. Operational risks inherent to perforating multiple zones in a high-pressure deepwater environment were minimized by using a simple and reliable approach built on previous experience from high-pressure deepwater perforation jobs. Cost reduction is the main driver because of the very high daily cost of deepwater operations. With a one-way-trip time of 18–24 hours, eliminating just one trip in the well would save up to USD 2 million. Perforating three or four zones at once multiplies the savings.
Planning
Planning for these jobs began with evaluating the casing design configuration to ensure that the perforating bottomhole assembly (BHA) could be run in and retrieved from the well with no damage and that the casing could withstand the pressure requirements of the perforating operations.
Real-Time Optimization of a Highly Complex, Integrated Gas System
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150109, ’Successful Real-Time Optimization of a Highly Complex, Integrated Gas System: Intelligent Energy in the Real World,’ by Derek Gobel, SPE, Shell; Jan Briers and Frank De Boer, IPCOS; and Ron Cramer, SPE, Kok-Lam Lai, SPE, and Martijn Hooimeijer, SPE, Shell, prepared for the 2012 SPE Intelligent Energy International, Utrecht, the Netherlands, 27-29 March. The paper has not been peer reviewed.
Real-time optimization (RTO) was used by Shell Malaysia E&P on the integrated gas-production system in Sarawak. Models for real-time monitoring and optimization of wells and facilities were implemented on a gas-production network spanning more than 100 wells on more than 40 platforms across several production-sharing contracts (PSCs). Digital technology enabled field-based data to be used to support decision making and led to actions that ensure that production is optimized continuously.
Introduction
Traditionally, aspects of gas-supply security relate to reservoir management, development planning, and sustaining plant availability and integrity. With increased computing capabilities, increased attention is given to noncapital-expense-intensive ways to provide additional smaller-scale improvements to the performance of an asset. Production-system optimization (PSO) falls into this category.
The Sarawak asset has experimented with ways to improve continuous optimization of its production through model optimization. Implementation of a mixed-integer nonlinear programming model rendered valuable results for medium- and long-term planning. However, network complexity and the volume of required optimization calculations obviated application in the real-time domain. Subsequent unsuccessful approaches included use of rigorous process-engineering simulation and optimization tools linked to the data historian. Two commercial soft-ware packages were trialed, but neither produced results fast enough or was sustainable by local staff.
Context
The Sarawak integrated gas asset is in the South China Sea off the coast of Sarawak, Malaysia. It comprises three onshore liquefied-natural-gas (LNG) plants at the onshore LNG complex in Bintulu, four onshore customers and an LNG cargo-export facility, 50+ offshore hubs and jackets, 100+ wells, and numerous connecting pipelines. Sarawak is covered by five PSCs and has several active operators.
The asset produces offshore natural gas of variable composition that is blended in the source-system pipelines and liquefied in the onshore LNG plants in Bintulu. Associated condensates are collected and processed in the Bintulu complex. Constraints in the system are physical, planning, and contractual/commercial in nature.
Possible Optimization Approaches
Financial—Impractical. This approach constitutes the monetary bottom line: total profit after royalty, tax, and interest. The revenue is generated from gas and condensate sales at the going rates minus taxes and the costs of investments and operations.
Technology Focus: Multilateral/Extended Reach (May 2012)
Authors: Negrao Alvaro Felippe 
Published: February 2015

Technology Focus
Mitigating Risks in Development Projects
Our industry has been involved in incidents that demonstrated the need of a new approach for evaluating and mitigating the risks in well construction.
The “what’s worked well in the past” conservative approach is not possible anymore, in face of the damaged trust of the public about upstream activity. Though the criticism soars against exploration and production activities, the industry has allocated substantial investments in research for new technologies aimed to preclude risk events of recent years. New procedures and technologies, in addition to existing ones, will be deployed in the near future to eliminate blowouts or underground contamination from upstream operations.
The initial results can be seen in field operations such as the application of managed-pressure drilling (MPD) for offshore and onshore, the use of long horizontals or extended reach in the shale plays, and new fluids and techniques for fracture treatments that minimize the amount of water required in such operations.
The effects of drilling operations in the shale plays of the USA are clear, but recent research will result in a consistent reduction of environmental damage. Research is minimizing fluid losses into reservoirs and helping with mitigation of well-control situations when applying the MPD technique.
The use of nanotechnology will provide fluids that improve fracture treatments through the control of fluid losses, with a subsequent reduction in the amount of fresh water required. Today, an average fracture treatment in the Barnett shale requires 235,000 bbl of water. These treatments are essential to reduce the number of wells and to improve the performance of the fracture treatments for environmental-impact reduction.
The use of extended-reach drilling or long horizontal wells, combined with multilaterals, will reduce the number of wells without impairing expected production. This will mitigate the effect on aquifers or shallow formations with a reduction in surface infrastructure. Some of the papers featured or listed for reading show advances in the technology of extended-reach and multilateral wells that will help achieve such objectives.
Finally, the combined use of extended-reach and multilateral wells, nanotechnology fluids, and MPD will result in a more environmentally-friendly operation with a cost-effective development plan, which is essential for improving the industry’s image.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 145400 Achieving Brazilian Extended-Reach-Drilling Records on the Polvo Project With Ultrahigh-Torque Connection by Nathan Biddle, Devon Energy do Brasil, et al.
IPTC 14258 Burgan Multilateral Campaign: A Success Story in Development of a Complex Siliciclastic Reservoir in Kuwait by Javed Ahsan, Kuwait Oil Company, et al.
IPTC 14823 Review of Ultrashort-Radius Radial System by S.K. Putra, Pertamina Upstream Technology Centre, et al.
More-Effective Plug-and-Abandonment Cementing Technique
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148640, ’Novel Approach to More-Effective Plug-and-Abandonment Cementing Techniques,’ by Thomas E. Ferg, Hans-Jacob Lund, and Dan Mueller, ConocoPhillips; Morten Myhre, Arne Larsen, and Patrick Andersen, SPE, HydraWell Intervention; Gunnar Lende, SPE, Halliburton; Charlie Hudson, SPE, M-I Swaco; and Cato Prestegaard, SPE, and David Field, Halliburton, prepared for the 2011 SPE Arctic and Extreme Environments Conference & Exhibition, Moscow, 18-20 October. The paper has not been peer reviewed.
The effectiveness of a permanent abandonment plug is measured by its ability to bridge the wellbore cross section, both vertically and horizontally, including all annuli, with a plugging medium that can withstand the harsh environment to which it is exposed (Fig. 1). A new method is presented that creates a permanent abandonment plug by use of a system that perforates uncemented casing, washes the annular space, and then mechanically places the cement across the wellbore cross section in a single run.
Introduction
Traditional methods of creating an annulus barrier in uncemented casing require removal of a section of casing by milling, cleaning the created open hole to remove swarf (i.e., metal filings or shavings produced by a cutting tool) and other debris, underreaming the section to expose new formation, and then setting a balanced cement plug. These operations can be time consuming and difficult to execute safely and effectively.
Fluids for use in section milling must have sufficient weight to keep the open hole stable and sufficient viscosity to suspend and transport swarf and debris to surface. The required fluid-viscosity profile for milling operations can generate equivalent circulating densities that exceed the fracture gradient of the exposed open hole, leading to losses while circulating, swabbing and well-control problems, poor hole cleaning, and packing off of the bottomhole assembly (BHA). The problems occur because not all swarf and skimmed casing remnants can be cleared from the wellbore. Swarf and casing debris can become strung out along the wellbore, lodging in the annular and ram blowout-preventer equipment, seriously effecting function. At the surface, handling equipment must be positioned and installed within the return flowline beyond the bell nipple and in front of the shakers to separate and capture the generated metal returns from the active mud system. An example of metal brought to surface during milling operations is shown in Fig. 2.
Achieving Deepwater Success
Authors: Pai Satish 
Published: February 2015

Guest editorial
Despite some uncertainty in the global economy, the long-term outlook for energy demand remains strong and the industry will continue to be challenged to meet hydrocarbon supply over the next decade. In its latest outlook, the International Energy Agency estimates that approximately 32% of oil production needed by the end of this decade has yet to be discovered or developed, and by 2035 it will be closer to 50%.
In response to this challenge, the exploration and production (E&P) industry has become more ambitious in searching out new frontiers, with some notable successes over the past few years, particularly in deep water. More than half of all oil and gas reserves discovered worldwide over the past 10 years have been offshore and the majority of large finds have been in water depths of more than 500 m (1,640 ft). We are reminded that 10 years ago pre-salt reserves offshore Brazil were still not proven, and that deepwater discoveries in areas such as French Guiana, Tanzania, and Ghana were not even on our industry’s radar screens.
It is estimated that approximately 200 new deepwater fields will enter production over the next 4 years. By 2020, production from deepwater fields will represent about one-third of total offshore production, representing about 10% of total global oil supply. Deepwater well capex is expected to grow from USD 47 billion to approximately USD 128 billion by 2020, with 71% of this growth taking place in the Atlantic basin—particularly in Brazil, Angola, Nigeria, the US Gulf of Mexico (GOM), and Nor-way. Other countries with solid deepwater activity include Australia, Egypt, and India. To achieve this significant growth, an increase in the number of floater rigs is forecast, from 200 in 2008 to more than 400 by 2020—an average of more than 20 new rigs per year. This estimate is consistent with mid-term forecasts of new deepwater rigs and suggests that the trend will be maintained until the end of the decade.
Over the period 2013-2020, deepwater well costs are expected to slightly increase in real terms. While efficiency gains are expected in regions such as the US GOM, thanks to next-generation rigs entering the market and the continued integration trend of new drilling technologies, these will be offset by increasingly complex and deeper wells. Exploration and appraisal activity is set to continue along the same trends for the rest of this decade, with further expansion in basins with recent discoveries such as the Mexican GOM, Equatorial Atlantic, east Africa, and the eastern Mediterranean. Activity will also be strong in basins with less-recent discoveries but where technology and/or access drivers have opened additional opportunities, such as Brazil, west Africa, and the US GOM.
California's Monterey Formation Zeroing in on a New Shale Oil Play?
Authors: Beckwith Robin 
Published: February 2015

Monterey Shale, California's Primary Petroleum Source Rock, Unlocking Its Complexities
The golden state’s Monterey Formation has been garnering a great deal of attention as a possible emerging liquids-rich shale resource that not only rivals plays such as the Bakken and Eagle Ford but towers above them in potential. Where did this news originate, what does it mean, and how does the Monterey’s future seem to be unfolding?
An Intriguing Report
In July 2011, the US Department of Energy’s (DOE) Energy Information Administration (EIA) issued a report titled “Review of Emerging Resources: US Shale Gas and Shale Oil Plays.” The introduction to the report clarifies that it is presenting a review of such resources only within the US lower-48 onshore area. The information presented in the review is based on a report, with the same title, which was prepared by INTEK, Inc. for the DOE, and is dated December 2010.
The report identifies 19 significant shale gas plays in the US onshore lower-48 area—plays labeled, in a table, as “unproved discovered technically recoverable resources.”
It also named four significant shale oil plays in the US onshore lower-48 area—plays labeled, in a second table, as “technically recoverable resources” (i.e., not “unproved and discovered”). These shale oil plays are identified as the Eagle Ford; the Avalon and Bone Springs (within the Permian Basin); the Bakken; and the Monterey/Santos.
The Monterey/Santos play was estimated, according to the report, to contain 15.42 billion bbl of technically recover-able shale oil resources, amounting to around 64% of the total resources in the four shale oil plays examined. This estimate has generated significant interest, due to its vastness, particularly when weighed against current heated shale oil activity in the three other shale oil plays cited.
Overall US crude oil production has risen steadily since the month the report was issued, from a July 2011 average of approximately 5.6 MMB/D to a December 2012 average of 7 MMB/D. According to EIA monthly statistics, which are derived from a combination of estimates and actual data reported by federal and state agencies (with estimates supplanted by actual data as reported data gradually become available over time), increasing oil production in North Dakota (the Bakken) and onshore Texas (Eagle Ford and Permian Basin) drove the surge in overall US crude oil production.
Increased oil production stemming from the Monterey/Santos play has yet to materialize.
First IPTC in China Examines Future Upstream Opportunities
Authors: Donnelly John , Rassenfoss Stephen , Beckwith Robin 
Published: February 2015

Conference review
The development of unconventional resources, China’s increasing importance on the global energy map, and turning E&P challenges into opportunities were among the topics discussed at the International Petroleum Technology Conference (IPTC) held 26–28 March in Beijing.
The first IPTC held in China officially opened with welcome addresses from the conference’s Executive Committee Cochairmen Zhou Jiping of China National Petroleum Corp. (CNPC) and Mark Albers of ExxonMobil, and from IPTC Chairman of the Board Mahmoud Abdulbaqi.
Zhou, who is president of CNPC and vice chairman and president of Petro-China, underscored the growing importance of both IPTC and China on the global energy stage. “IPTC has already become a highly influential conference in the oil and gas industry,” despite its relatively short history, he said. Of particular importance is IPTC’s collaboration across states, types of companies, and industry associations, offering a multidisciplinary approach to industry issues and challenges, he said. IPTC is organized by the American Association of Petroleum Geologists (AAPG), European Association of Geoscientists and Engineers (EAGE), Society of Exploration Geophysicists (SEG), and SPE.
Albers, senior vice president at Exxon Mobil, noted that “it is only fitting that IPTC take place in China” given the country’s rise to prominence on a global scale. More than 3,500 delegates from 65 countries attended the conference. More than 2,000 technical paper abstracts were received, the most in the history of the conference, which alternates between sites in Asia Pacific and the Middle East.
CEOs Examine Future Needs
When it comes to the future of the oil and gas business, all roads seem to lead to China. The country that is home to 1.6 billion people is a driver of global demand and is determined to be a partner in the worldwide search for the oil and gas and the new technology needed to continue expanding supplies, according to five chief executive officers who spoke at the CEO Plenary on the opening day of the conference.