bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Tomorrow: Reserves Growth: Torturous and Tortuous
Authors: Long Roy 
Published: February 2015

Editor's note: This is the fourth installment of a yearlong series designed to stimulate discussion in energy research and development. This article focuses on near-term resource potential and processes for developing technologies to successfully develop this potential. Comments on articles in the Technology Tomorrow series are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.
At the World Petroleum Congress in 2000, the U.S. Geological Survey (USGS) presented its World Oil and Gas Assessment, showing a global conventional reserves growth estimate (Table 1). The greatest significance of this estimate was the size. The U.S., in particular, is highlighted because the reserves growth estimate is more than twice the remaining reserves and at least comparable with the undiscovered resource estimate. As noted in the assessment, "In the U.S., which is one of the most intensely explored countries in the world, reserves growth is widely considered to be a major component of remaining oil and gas resources. It is hypothesized that reserves growth of similar proportions also could occur worldwide as exploration for new fields matures and the intense exploitation of existing fields becomes an increasingly viable approach to developing new reserves."
A number of arguments have been made regarding the potential weakness of that hypothesis, but the significant impact of reserves growth is becoming more accepted. Notable in this assessment, as in all resource assessments, is the lack of discussion of the technologies and practices required to develop these resources in a timely manner. The challenge lies in the details of how we get there.

The Torture
Despite the upside potential of reserves growth, the process of developing that potential can be quite painful without adequate technology to support development programs. Fig. 1 is a plot of development program costs in one of the most challenging environments in the world, the deepwater U.S. Gulf of Mexico (GOM), during the period before 2004 when oil and gas prices were beginning to rise. The driver for the cost estimates and overruns came from the days when deepwater drillships cost between U.S. $300,000 and $400,000 per day.
As bad an impact as an average 60% overrun might be on a $44 million AFE project, the real inhibitor of resource development in the GOM is the potential for spending more than three times the anticipated average AFE cost. This magnitude of risk might be referred to as "elephant torpedoes" in the deepwater search for elephant reservoirs with regard to the impact on exploration budgets. Today, those same deepwater ships cost closer to $500,000 per day, and the industry is charging forth again into deep water based on a $60+ per barrel "war chest," but with only limited advancements in new technologies since the early 2004 time frame to aid in risk reduction. Success this time obviously will depend on lessons learned and human resources.
Overview: Subsea Technology (August 2006)
Authors: Salies Jacques B. 
Published: February 2015

Once again, OTC thrived with projects, new technologies, and presentations that met the highest standards and expectations. This year, boosted by the steady increase in oil prices—having surpassed U.S. $70/bbl—attendance reached 59,236, the highest since 1982. Attendees from more than 110 countries were able to exchange their expertise on the development of offshore resources in the fields of drilling, exploration, production, and environmental protection. Subsea technology, more than ever, was a key factor in the huge success of this "Engineering Celebration."
As such, it is the focus of the papers selected for this feature, by means of which JPT seeks to present state-of-the-art technology in the quest to find and produce offshore oil and gas. Highlights include the development of two gigantic fields in western Africa and Brazil. These two fields will provide invaluable knowledge on how to use floating production, storage, and offloading vessels in the Gulf of Mexico (GOM), our next technological frontier. Another highlight is the technical challenges and opportunities for subsea processing and boosting. Several companies are investing in these technologies, aiming at applying them in the North Sea, GOM, Brazil, and western Africa. Such technologies, when put together, will be able to tackle the water-production challenge and will allow the production of new heavier-oil discoveries; they also will enable development of long tiebacks for oil and will play an important role in the subsea-to-shore challenge.
The efforts of our industry to overcome challenges in the development of subsea fields are well evidenced by the "Spotlight on New Technology Awards" at this year's OTC. From the 13 new technologies recognized with the award, one was for subsea boosting and another for subsea separation. In the near future, most certainly, new- or old-field developments will adopt a combined solution of sub-sea processing and boosting. The benefits seem very clear.
Therefore, I am especially pleased to invite you to read this impressive collection of topics for their scope, content, and effect on the industry. I hope you enjoy it.
Subsea Technology additional reading available at the SPE eLibrary: www.spe.org
SPE 100662 "Scale-Inhibitor Testing for Multiphase Pipelines in a Subsea-to-Shore Development With a Closed MEG-Loop System" by E.N. Halvorsen, Hydro Oil & Energy, et al.
Available at the OTC Library: www.otcnet.org
OTC 17810 "NDP Review of State of the Art in Riser Monitoring: Lessons Learned and Experiences Gained," by M. Chezhian, Det Norske Veritas, et al.
OTC 18318 "Evaluation of Low-Dose Hydrate Inhibitors (LDHI) for a Long-Distance Subsea Tieback in Ultradeep Water," by A. Singh, SPE, Total E&P U.S.A. Inc., et al.
Albacora Leste Field - Subsea Production- System Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18044, "Albacora Leste Field - Subsea Production System Development," by C.E.C.V. Longo, S.J.A. Neto, and M.T.R. de Paula, Petrobras; F.M. Lopes Jr., Technip; and C.A.F. Godinho, SPE, Prysmian, prepared for the 2006 Offshore Technology Conference, Houston, 1–4 May.
The Albacora Leste field-development plan comprises 30 horizontal wells tied back to a floating production, storage, and offloading (FPSO) platform moored by use of an innovative spread mooring system (SMS). All risers are flexible and installed in a free-hanging configuration. Environmental conditions and FPSO motion were factors in flexible-riser design. All flexible lines were anchored by means of torpedo piles. The full-length paper describes field development, including planning, design, qualification, manufacturing, and installation activities.

Introduction
The Albacora Leste field is in the deep north area of the Campos basin approximately 120 km off the coast of Brazil. Water depths in this field range from 800 to 2000 m, and oil densities range from 17 to 21°API.
The field development comprises 30 horizontal wells (16 production wells and 14 injection wells, three of which are in a piggyback configuration) tied back to a host FPSO, P-50 by flexible risers and flowlines. Bending-stiffener and top riser accessories development and qualification represented an important and challenging success factor for the project. Three test benches were designed and assembled to perform the long-term fatigue tests for the gas-export flexible riser and to validate the new concept of the stiffener hanging systems.
The FPSO will be moored in 1230 m of water by use of an innovative differential-compliance anchoring system. The oil, after treatment and storage on the FPSO, is pumped to a shuttle tanker. The produced gas then is cleaned and compressed, and a fraction of the total volume is used for power generation, gas lift, and internal consumption; the remaining volume is exported to shore by way of Platform PGP-1 in the Garoupa field, Campos basin.
During the design phase, continuous gas lift and electrical-submersible-pump (ESP) artificial-lift methods were selected as potential candidates for the wells. However, at the time of the design phase, an ESP that could handle the high oil flow rates expected was not available, so the decision was made to use continuous gas lift as the artificial-lift method for the production wells. The approved gas lift design strategy eliminated pressure-operated valves and adopted a very simple and reliable well completion that included a single gas lift orifice valve. A high-discharge-pressure gas compressor was installed topside to guarantee continuous gas injection through the orifice valve at normal well-operation conditions and kickoff.
A Parametric Study of Horizontal and Multilateral Wells in Coalbed-Methane Reservoirs
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96018, "A Parametric Study on the Benefits of Drilling Horizontal and Multilateral Wells in Coalbed-Methane Reservoirs," by N. Maricic, SPE, Chevron Corp., and S.D. Mohaghegh, SPE, and E. Artun, SPE, West Virginia U., prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9–12 October.
The full-length paper attempts to identify the most appropriate drilling pat-terns for coalbed-methane (CBM) reservoirs of different thickness and with different characteristics. The comparison yardstick for this study is net present value (NPV). In this way, drilling cost is accounted for when comparing different horizontal and multilateral configurations. Dual-lateral, trilateral, quadlateral, and fishbone configurations were compared. Total horizontal well length as well as spacing between laterals (SBL) was studied.

Introduction
CBM Background. Coal represents an unusual reservoir rock because of its highly complex reservoir characteristics. Unlike conventional sandstone reservoirs where gas is found in a free state within the pore structure of the rock, the methane gas is adsorbed onto the internal structure of the coal, which allows a significant amount of gas to be stored in the coal rock.
A coal-seam system is a naturally fractured heterogeneous reservoir characterized by macropores (the fracture system, also known as the cleat system) and micropores (coal-matrix system). In general, the coal cleat system is orthogonal, with one direction cross-cutting.
CBM production depends on fracture spacing and fracture interconnection. If the cleat system is not sufficiently developed, gas production can be very difficult. This occurs as a result of the low porosity and permeability values of the matrix, making it almost impossible for gas to move from the matrix into the fractures. At the beginning, the coal system is in equilibrium and typically, water must be produced continuously from coal seams to reduce the reservoir pressure and release the gas. Gas from the coal can be produced only after initial system dewatering and lowering the reservoir pressure. The dewatering process can take anywhere from a few days to several months and depends on CBM-well configuration. Generally, water production declines until the gas rate reaches the peak value. This "time-to-peak-gas" is a critical parameter because gas production begins declining soon after reaching the peak.
Horizontal Wells. One of the main advantages of horizontal wells is that well direction, shape, and position can be controlled. With horizontal wells, an almost ideal well position can be determined and achieved with respect to principal permeability directions of the coal. Proper well positioning as well as borehole length drilled perpendicular to the main fracture system of the coal can contribute significantly to draining large areas.
Techbits: Symposium Discusses Talent, Technology, and Challenges
Authors: JPT staff _ 
Published: February 2015

"The Challenges and Excitement Ahead: Talented People and Evolving Technologies" was the theme of the SPE Saudi Arabia Section's Annual Technical Symposium held 7–8 May at Dhahran, Saudi Arabia. The symposium has become a central E&P technical gathering for regional and international professionals, providing a valuable opportunity for professionals in the industry and researchers in academia to exchange and disseminate knowledge.
Symposium Chairperson Saud Al-Fattah, giving his welcoming speech, noted "the importance of talent and technology in meeting the challenges and demands of an energy-hungry world." Expertise and state-of-the-art technology, he stressed, form a powerful combination for advancing engineering and scientific work to improve the discovery and recovery of energy reserves.
Keynote speaker Khalid A. Al-Buraik, Chief Petroleum Engineer, Saudi Aramco, discussed the symbiosis, or interdependent relationships, of people, technology, and energy in bringing economic development and an improved standard of living to the world.
Following this, 2007 SPE President Abdul-Jaleel Al-Khalifa spoke on unleashing the industry's potential. The oil industry, he noted, has served mankind for the past 150 years and must examine how it can sustain prosperous growth through the coming 50 to100 years. The pressing challenges, according to Al-Khalifa, include the impact of skepticism today about the level of reserves, security of supply, stability of demand, cost inflation, the changing industry landscape between international and national oil companies, climate-change issues, and the industry's human-resources scarcity. Due to a lack of critical mass in human resources, Al-Khalifa said, industry personnel focus 80% of their attention on immediate drilling and production issues and have at most 20% of their attention to give to the important concerns of reservoir recovery.
Citing recent SPE survey data indicating that only 57% of industry professionals are fully engaged by their work, Al-Khalifa noted the large potential that the industry could unleash by fully engaging all of its professionals. The key elements for achieving this include providing a work environment of fairness, trust, and integrity; improving leadership development; adopting a people-first business model; and mitigating the impact of cyclical business fluctuations on the workforce. The productivity improvement attainable through achieving these goals could be as high as 30%, Al-Khalifa said.
Joe Sandy, Vice President, Technology, Halliburton, spoke on the role of technology in maximizing hydrocarbon production. Sandy emphasized the importance that the eastern hemisphere will play in technology implementation over the next 5 to 10 years. Major drivers for this technology will be deep water, small reserves, difficult reservoirs, difficult hydrocarbons, sustainable development, and constraints on capital, human resources, supplies, and material.
Smart-Well Technology at the SACROC CO2 EOR Project
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 100117, "Application of Smart- Well Technology to the SACROC CO2 EOR Project: A Case Study," by J. Brnak, SPE, Kinder Morgan Production Company, and B. Petrich and M.R. Konopczynski, SPE, WellDynamics, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April.
Application of smart-field technologies to the SACROC Unit carbon dioxide enhanced oil recovery (CO2-EOR) project in Scurry County, Texas, was studied. A five-well pilot project in early 2005 demonstrated the ability of intelligent-well downhole flow-control valves to restrict or isolate the production of CO2 from breakthrough zones in production wells and to control the distribution of CO2 injection in injection wells. The objective is to reduce unnecessary cycling of CO2 between injectors and producers, improve sweep efficiency, increase oil production, and improve ultimate oil-reserves recovery. This is done with cost-effective, fit-for-purpose intelligent-well systems.

SACROC Field
The SACROC Unit in Scurry County, Texas, is the seventh largest oil field onshore in North America, with 2.8 billion bbl of original oil in place. Its main producing formation is the Canyon Reef, a Pennsylvanian-aged limestone carbonate and part of a reef complex called the Horseshoe Atoll. It is a highly heterogeneous formation. Permeability within a single well can range from less than 1 md to hundreds of millidarcies. Likewise, porosity can vary drastically. Net and gross thickness can change significantly over short distances. However, average reservoir properties are as follows.Depth = 6,700 ft.Thickness = 259 ft.Porosity = 7.6%.Permeability = 19.4 md.

SACROC CO2 EOR Project
The SACROC Unit was discovered in 1948 as the Kelly-Snyder field. The field produced under primary depletion with solution-gas expansion as the main drive mechanism. Reservoir pressure declined rapidly, and in 1952, the Kelly-Snyder and Diamond M fields were unitized. In 1954, the operator implemented a crestal waterflood in which water was injected along the center (the spine) of the field. In 1972, CO2 injection was initiated. With limited CO2 supply, the oil-production response to CO2 injection was limited. During water and CO2 flooding, H2S was introduced to the reservoir from sources outside the unit. As shown in Fig. 1, shortly after CO2 injection was initiated, the unit's oil production peaked with rates exceeding 200,000 BOPD. During the following decline, several projects were attempted to halt the decline, but they had little effect. In 1995, a CO2-flood pilot consisting of five-spot patterns was started. This pilot used large CO2-injection volumes at miscible conditions, and the decline of the unit's oil production was halted. In 2001, project acreage under CO2 flooding began to expand rapidly. In response, oil production increased to more than 31,000 BOPD.
Field Surveillance: Enhanced Monitoring and Smart Alarms Produce More Oil
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 102091, "A New Approach for Field Surveillance: Enhanced Monitoring Associating Smart Alarms To Produce More Oil," by A. Lentini and G. Fumia, Eni E&P; H. Malonga and F. Okassa, Eni Congo; and J.P. Le Cann and J. Lessi, SPE, Geoservices, prepared for the 2006 SPE Russian Oil and Gas Technical Conference and Exhibition, Moscow, 3–6 October.
Managing wells produced with electrical submersible pumps (ESPs) must take into account limited pump-run life and production losses from ESP failures and shut in wells. Monitoring production and pump parameters is common, but real-time monitoring systems enable improving production conditions with rapid access to data that allows engineers to plan effective and timely remedial work. A system was field tested at an unmanned platform of a brown field with producing wells that use ESPs. The advanced information provided to the decision makers resulted in early production recovery and improved well inflow and outflow performance knowledge.

Introduction
The evolution of information technology has provided various new tools and opportunities to help maximize oil recovery while optimizing operational costs. Real-time data can increase the asset value only if the associated information can be analyzed fully in a timely and effective manner. The technology described here uses automated "smart alarms." It is intended to exploit the potential in the huge amount of information available from real-time monitoring of wells having ESPs.
This surveillance system was implemented on an offshore satellite platform in Congo. The existing instrumentation was used and the data made available in real time to every location within the company's Congo network by use of terminal-server technology. During a first monitoring and optimization phase, an optimal setting was found for each well. Then, in a second surveillance phase, smart alarms were built to detect deviation from the optimal behavior by comparing current data with a signature specific for each well and based only on wellhead parameters.

Background
Data-collection systems can provide very large amounts of data from different sources. The drawback of such a situation is the risk of losing the relevant information because of data overload and the lack of appropriate, coherent, and consistent processing of these data. It is important to focus on parameters that are key to optimizing well production and avoiding production losses. If correctly processed, these parameters can be used efficiently to trigger alarms that can draw the operator's attention, enabling immediate appropriate action.
The first step is to define processing that, when applied to specific data, will detect abnormal well behavior. The second step is to implement software that uses the data to trigger alarms. This software relies on "smart logic" to avoid any false alarm caused by a non-relevant situation, such as a planned shut-in of the well.
Overview: Subsea Technology (August 2007)
Authors: Salies Jacques B. 
Published: February 2015

Once again, OTC thrived with projects, new technologies, and presentations that met the highest standards and expectations. Boosted by oil prices, attendance reached more than 67,000, a 25-year high. Nearly 2,400 companies from more than 30 countries participated in the show. It was a great opportunity to exchange expertise in the development of offshore resources worldwide. Subsea technology, more than ever, was a key factor in the huge success of this "Engineering Celebration."
Last year I highlighted challenges for subsea processing and boosting. Today, I believe even more that the great technical challenges bring huge opportunities for subsea processing and boosting. Such technologies, when put together, will be able to overcome the water-production challenge and will enable the production of increasingly heavier oil discoveries. Also, they will enable development of long tiebacks for oil and gas and will play an important role in the subsea-to-shore challenge.
Aligned with these principles, this year I picked papers that describe solutions adopted for subsea-compression systems (Ormen Lange), and integrated subsea separation, boosting, and injection (Tordis). I also picked a classical subsea development (Dalia) with great learning opportunities for all. Another subject that has generated much attention is the all-electric subsea tree. It is a great innovation with impressive results. I hope that next year we will be able to see another paper with the learning experience of the first system.
Therefore, I am especially pleased to invite you to read this impressive collection of topics for their scope, content, and effect on the industry. I hope you enjoy it.
Subsea Technology additional reading available at the OTC Library: www.otcnet.org
OTC 18749 "The Tordis IOR Project" by Ann Christin Gjerdseth, FMC Technologies, et al.
OTC 18969 "Ormen Lange Subsea Compression Pilot" by Bernt Bjerkreim, Hydro, et al.
OTC 18819 "First Application of the All-Electric Subsea Production System—Implementation of a New Technology" by Laurent Bouquier, Total, et al. (See JPT, June 2007, page 52.)