bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Real-Time Data's Value Explored in Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
A one-day workshop held in June in Houston focused on “The Value of Real-Time Data.” Jointly sponsored by the SPE Gulf Coast Section (GCS) and the SPE Real Time Optimization Technical Interest Group (RTO TIG), the workshop compiled published reports on the value of real-time data and also gave the 150 attendees the opportunity to discuss the challenges that remain.
“Some years ago, the industry was challenged with large targets achievable from the creation of digital oil fields,” said Roger Hite of Business Fundamentals Group and chair of the workshop committee. “Since then, we have all been busy with various projects—building infrastructure, writing software, adapting work processes, and training staff—all with the goal of capturing this promised value.”
The value of digital-oil-field initiatives has received extensive coverage in technical papers, as a quick search in the OnePetro literature database demonstrates. A literature search using the keywords “real time” and “value” yields a list of almost 3,500 papers, Hite said. “This is a bit more than most of us have time to review. We wanted to create a compilation that would be useful to SPE members. The goal was to find and document as many case studies as possible to provide quantitative data on the value actually realized from the use of real-time data.”
Literature Review
In preparing for the workshop, SPE volunteers consisting of subject matter experts narrowed the list down to a manageable number of papers. And while they did their best to locate the best papers, Hite acknowledges that some have likely been overlooked. “If JPT readers know of any papers we should have included, we will greatly appreciate your letting us know,” he said. “We intend to keep this list evergreen, possibly using wiki technology.”
The volunteers carefully reviewed each of the selected papers using a special form to capture relevant information. From these reviews, more than 40 case studies were identified as “good sources,” meaning that most of them included hard numbers that could be used to validate value, while a few provided valuable summaries and insights. “In some areas, we included references to papers that are ‘possible sources’ of information,” Hite added. “These lack hard data, but provide valuable overviews.”
R&D Investment Trends and the Rise of NOCs
Authors: Thuriaux-Aleman Ben , Salisbury Sam , Dutto Paolo R. 
Published: February 2015

Management
The global energy industry has been facing a variety of challenges in recent years: high price volatility, the decline of “easy oil” and a shift of production to emerging markets, shortage of talent, pressure to reduce the carbon footprint, and a surge in petronationalism. These challenges have shifted power toward national oil companies (NOCs) and have raised questions about the current business model of the international oil companies (IOCs).
In dealing with increasingly complex oil fields, some have argued that the IOCs can maintain a competitive advantage by leveraging their internal technology competence and their experience in leading and coordinating technology-driven project skills to transform pioneering E&P approaches into commercially viable approaches. Much of this rests on the IOCs’ technology leadership based on their strengths in R&D and technology. However, recent trends in R&D spending (Fig. 1) suggest that the IOCs’ dominance in R&D is being challenged both by a leading group of NOCs and by the international service companies.
NOCs Now Lead in R&D Spending The top five IOCs by revenue increased R&D with an average year-on-year growth of 9.8% in the period 2003–2009. Total has shown the smallest R&D growth since 2003, but it had a high starting point compared to the other IOCs, especially when adjusting for size of operations (Fig. 2). Chevron has increased its spending on R&D 18% year on year since 2003 but remains behind the leaders. Starting in 2006, Shell has pushed to develop technologies for more difficult assets. In doing so, it has become the top spending IOC in terms of absolute R&D expenditure. BP appears to spend relatively little on R&D but this masks the fact that a lot of its technical efforts are centered on piloting and field trials.
In contrast to the IOCs’ moderate growth, a small group of leading NOCs has been investing heavily in R&D. Petrobras’ R&D spending has increased at a rate of 23% a year since 2003 and is now on par with Total and ExxonMobil. But the most impressive growth in R&D has been for CNPC/PetroChina, which saw an annual increase of 31% during the same period. In 2009, PetroChina overtook Petrobras and Shell as the leading spender both in absolute levels of R&D spending and on a per-BOE basis.
Akpo: A Giant Nigerian Deep Offshore Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20989, ’AKPO: Early Completion of a Giant Nigerian Deep Offshore Development,’ by Francois Rafin, SPE, and Allain Lacne, Total S.A., originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
Akpo field was discovered in January 2000 and production started ahead of schedule in March 2009 in Block OML 130, 200 km offshore Nigeria in 1400-m water depth. The Akpo project faced the challenges of combining gigantic scale, new technological frontiers, world-scale industrial execution, scarcity of resources in booming years for the offshore industry, and setting new records of local content in an unstable Niger delta.
Introduction
A unique hybrid gas-injection/gas-export development scheme was chosen to maximize hydrocarbon recovery with massive pressure maintenance and the extensive use of intelligent and selective completions and subsea multiphase-flow measurements.
The wellhead shut-in pressure of 430 bar and temperature of 116°C represented new frontiers for the deepwater industry.
To deliver a 72-slot, 44-well, 10-manifold, 14-steel-catenary-riser (SCR) subsea development in West Africa, the project strategy was to use generic and qualified systems and equipment. The Akpo field characteristics required several technological innovations and the development of existing technology such as:
All-electric floating production, storage, and offloading (FPSO) vessel with a centralized control room on each topside module
Inconel-clad SCRs with high-pressure/high-temperature flex joints
One fully integrated control and safety system from wellbore to FPSO topside provided by a single contractor
An internally flow coated 155-km-long gas-export line that increases the flow capacity by 20%, enabling (because of a reduced diameter) the use of seamless pipe
Crushable foam and bursting disk to control the well annulus-pressure buildup, because no casing steel is available to withstand the stress at Akpo pressure and temperature conditions
First 10¾-in. frac-pack runs in a single trip
First use of 7-in. expandable screens for a subsea application
Intelligent completions with downhole monitoring and control from the FPSO control room
Automatic ultrasonic testing system for Akpo subsea pipelines, capable of detecting defects smaller than minimum acceptable
FDPSOs: The New Reality and a Game-Changing Approach to Field Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20482, ’FDPSOs: The New Reality, and a Game-Changing Approach to Field Development and Early Production Systems,’ by W.D. Harris, SPE, H.J. Howard, SPE, and K.C. Hampshire, SPE, Murphy West Africa; J.A. Moore and K.J. Bayne, SPE, Doris Inc.; and Jean Pepin-Lehalleur, Doris Engineering, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
The Azurite field development, installed in the Republic of Congo in 2009, employed the industry’s first floating drilling, production, storage, and offloading (FDPSO) vessel to develop the field. While the FDPSO concept has been a subject of interest within the industry for some time, the Azurite project team took the FDPSO from concept to reality. The concept has tremendous potential as a “game changer” for field developments.
Introduction
The Azurite field lies within the Mer Profonde Sud (MPS) Block offshore the Republic of Congo, just north of the border with Cabinda Block 14. Water depths across MPS range from 1100 to 2000 m. Azurite field was discovered in January 2005 with the AZRM-1 well. The field was appraised in late 2005 and early 2006 with the drilling of the AZRM-2 and AZRM-3 wells. Each of the latter two wells was sidetracked (ST). AZRM-2ST also was cored and tested. Aquifer support was found to be essentially nonexistent along the producing trend, necessitating water injection to support reservoir pressure.
Concepts Considered
The Azurite integrated project team began the task of identifying and evaluating field-development alternatives. Multiple development schemes were identified and evaluated. The four main alternatives evaluated were:
Subsea tiebacks to third-party facilities
Subsea tieback to infield floating production, storage, and offloading (FPSO) vessel
Dry-tree unit (DTU) producing to FPSO
Infield FDPSO
A subsea tieback to third-party facilities in the Republic of Congo or Angola was considered and deemed technically feasible, with the aid of subsea boosting. However, tiebacks to third-party facilities in the Republic of Congo or tiebacks to third-party facilities in Angola, with the associated cross-border issues, would have introduced too much schedule and political risk. Hence, tieback schemes involving third-party facilities were not selected.
A subsea tieback to an infield FPSO was considered. However, strong market demand for deepwater floating rigs exposed the project to significant schedule delays. Likewise, their associated day rates adversely affected project economics.
Probabilistic Modeling for Decision Support in Integrated Operations
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127761, ’Probabilistic Modeling for Decision Support in Integrated Operations,’ by Martin Giese, University of Oslo, and Reidar B. Bratvold, SPE, University of Stavanger, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, Netherlands, 23-25 March. The paper has not been peer reviewed.
A system was designed to assist operational decisions on the basis of real-time sensor readings in a typical scenario: While drilling close to the transition to a high-pressure formation, gas influx is observed. The technology used Bayesian networks and influence diagrams (IDs) to apply the method of decision analysis. The resulting ID was tested with a simulation.
Introduction
An assumption of integrated operations is that all information provided by the technology will help to make better decisions faster. But for this to happen, information must be presented in an accessible, useful, and decision-relevant format. Decision-analysis tools provide decision makers with logical and consistent recommendations based on the available data. This decision-analysis method was applied to a real case, representative of a typical scenario in drilling operations. The tool enabled good decisions consistently. However, effort is required and challenges exist in the modeling process along with problems regarding the way decision making is treated in the industry.
Modeling and Solving
A decision tree provides a graphical illustration of all the uncertainties, decisions, and payoffs associated with a decision situation. Although application of decision trees is intuitive for simple problems, the method loses its appeal for complex decisions. A symmetric decision tree grows exponentially with the number of variables in the decision domain, which often makes its use impractical. For complex decisions, the ID can provide a level of insight and transparency that cannot be achieved with the equivalent decision tree.
The ID is a compact graphical-model representation for reasoning under uncertainty and was developed to assist structuring and analysis of complex decisions. The ID has two advantages—structuring and probabilistic evaluation. The structuring provides a graphical representation of the inter-relationships among the decision-basis elements (i.e., alternatives, information, and preferences), while the evaluation appraises the resulting decision structure and provides an assessment of its expected utility given the quantified decision basis.
The representational framework of an ID captures the probabilistic relationships among decisions (alternatives), key uncertainties (information), and utilities (values or preferences). The ID model comprises four types of nodes. Decision nodes specify a set of alternatives. Chance nodes represent the key uncertainties in the decision domain. Deterministic nodes represent either constants or intermediate calculations. Value nodes represent the criteria used to make the decisions.
Channel Fracturing - Paradigm Shift in Tight Gas Stimulation
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140549, ’Channel Fracturing - A Paradigm Shift in Tight Gas Stimulation,’ by J. Johnson, SPE, M. Turner, SPE, and C. Weinstock, SPE, Encana; and A. Pena, SPE, M. Laggan, SPE, J. Rondon, and K. Lyapunov, Schlumberger, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed.
The hydraulic-channel-fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, providing highly conductive paths for fluid flowing from the reservoir to the wellbore. The Lance formation in the Jonah field near Pinedale, Wyoming, was selected for this study. Results indicate that implementation of the channel-fracturing technique increased initial gas production and estimated recovery over conventional fracturing methods. Positive features during this campaign included reduced net-pressure-increase estimates from pre- and post-fracture-treatment shut-in-pressure measurements, reduced tendency for vertical fracture growth, and elimination of near-wellbore screenouts.
Introduction
Natural gas plays a major role in the assortment of energy resources that sustain the USA. The imbalance between future energy demands and reduced availability of gas from conventional sources dictates the need to increase gas recovery from unconventional sources such as tight gas reservoirs, shale-gas reservoirs, and coal seams. Hydraulic-fracturing treatments in tight gas formations during the 1970s consisted of pumping large quantities of a propping agent and carrying gelled fluids and emulsions at pressures in excess of the formation-fracturing pressure. Beginning in the 1980s, this fracturing technique included various combinations of nitrogen gas and/or liquid carbon dioxide pumped in combination with fluid and proppant for stimulation purposes. Low-viscosity slickwater treatments, in which proppant is pumped at low concentrations within a high-rate water stream, became popular in the 1990s for stimulating tight gas reservoirs. All these techniques rely on filling the fracture with the propping agent to maintain an open fracture. The proppant pack placed within the fracture also serves as a conductive medium for gas flow to reach the wellbore. The effective area of the fracture covered by proppant varies according to the technique used. Typically, completion efficiency is low for slickwater treatments, and it often improves with the use of viscous carrying fluids and fibers, among other methods.
Technology Focus: Sand Management and Frac Pack (October 2011)
Authors: Azeemuddin Mohammed 
Published: February 2015

Technology Focus
With world population increasing and industrialization demanding newer and harder-to-reach sources of hydrocarbon, the demand for energy is constantly on the rise. Development of hydrocarbons from harsh environments often leads to narrow safe drilling-mud-weight tolerances (or windows) that accompany ultradeepwater subsalt plays and high-pressure/high-temperature developments. These narrow mud-weight windows also can be found in highly compartmentalized developments that encounter severely depleted and/or unconsolidated reservoirs. Technology to tap these reservoirs must meet the growing challenging conditions and produce hydrocarbons both safely and cost effectively.
Sand production and fines migration have long held the attention of industry professionals in developing a means to predict them, manage them, and devise innovative ways to avoid or minimize them by use of proper field-development practices and newer downhole completion tools and technologies. Most recently, progress was made in predicting the rates and amounts of sand produced for the purpose of optimizing sand-management strategies and choosing the correct completion/production strategy for the expected sand volumes. Every reservoir-rock formation, and corresponding field-development plan, provides a unique set of challenges with associated learning opportunities that may favor one completion method over another. The final decision of which completion method to use lies in an in-depth understanding of the geology, reservoir conditions, in-situ stresses, fluid and rock properties, equipment considerations, sand-management options, and costs.
The papers selected for this feature come from varied geographical locations involving different geological settings that highlight the importance of studying the unique conditions at hand, in detail, and applying a fit-for-purpose technology to maximize production and cost effectiveness. Other interesting case and modeling studies, by no means less important, are listed in the additional-reading group.
Sand Management and Frac Pack additional reading available at OnePetro: www.onepetro.org
SPE 139360 • “A Unique Sand-Control Screen That Enhances Productivity” by G. Woiceshyn, Absolute Completion Technologies, et al.
SPE 143941 • “Formation Loading and Deformation of Expandable Sand Screens” by Colin Jones, Weatherford, et al.
SPE 144047 • “Controlled Use of Downhole Calcium Carbonate Scaling for Sand Control: Laboratory and Field Results, Gullfaks” by N. Fleming, SPE, Statoil ASA, et al.
Reducing Fines Migration by Use of Nanofluids Injection - An Experimental Study
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144196, ’Reduction of Fines Migration by Nanofluids Injection - An Experimental Study,’ by A. Habibi, SPE, M. Ahmadi, and P. Pourafshary, SPE, University of Tehran, and Sh. Ayatollahi, SPE, Shiraz University, prepared for the 2011 SPE European Formation Damage Conference, Noordwijk, The Netherlands, 7-10 June. The paper has not been peer reviewed.
Formation damage because of fines migration is a major reason for productivity decline. Many studies have characterized fines and their migration effect on permeability reduction. Nanofluids that contain nanoparticles (NPs) show specific properties including a high tendency for adsorption and being a good candidate for injection into the near-wellbore region because of the very small NP sizes. The study indicates that fines could adhere to the matrix grains, hindering their migration, when the porous materials are soaked with nanofluids.
Introduction
Fines are loose unconsolidated particles (smaller than 37 µm) that move with fluid flow and cause formation damage because of the filtering action of the porous media. The biggest drawbacks of this process are pore plugging and productivity-index reduction. Various surface forces have been found to be responsible for fines detachment and release from the pore surfaces. London/van der Waals attraction, double-layer and Born repulsion, and hydrodynamic forces are the dominant forces in the detachment of fines from porous media. When the total interaction energy between fines and pore surface becomes positive, the repulsive forces are bigger than attractive forces and fines detachment occurs.
NP size ranges from 1 to 100 nm, and NPs have high specific surface area and unique properties, such as very high adsorption potential and heat conductivity. NPs have been used for formation-damage control, enhancing oil recovery, and wettability alteration. In the proppant packs, NPs strengthened the attractive forces and fixed the suspended fines in the porous media. In this experimental study, porous media were soaked with nanofluid for 24 hours and then the suspended fines were passed through porous media to determine the most efficient component. In the next step, a glass-bead-packed column containing uniformly distributed fines in the bed was flooded with distilled water. To investigate the main parameters in this process, the NP concentration and fluid-injection rate were investigated. The zeta potential of the treated models was measured, and the total interaction energy was calculated to verify the results. Finally, scanning-electron-microscope (SEM) images of the surface were obtained for qualitative observation of fines attachment to the pore surfaces.