bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced Heavy-Oil Recovery by Alkali/Surfactant Flooding
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110738, "Enhanced Heavy-Oil Recovery by Alkali/Surfactant Flooding," by J. Bryan, SPE, and A. Kantzas, SPE, University of Calgary and TIPM Laboratory, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed.
This study presents the results of laboratory core studies investigating the recovery mechanisms of alkali/surfactant (A/S) flooding in heavy-oil reservoirs. Specifically, mixtures of water and A/S systems have been injected into cores containing heavy oil. Salinity is varied to generate oil-in-water (O/W) vs. water-in-oil (W/O) emulsion systems, and the effects of generating different emulsions were compared. It was demonstrated that in heavy-oil systems, emulsion formation was necessary to produce the heavy oil.

Introduction
Several countries, including Canada and Venezuela, contain massive resources of unconventional heavy oil and bitumen. These oil sands are characterized as unconsolidated, high-porosity, and high-permeability reservoirs. The single biggest obstacle to successful recovery from the oil sands is the high oil viscosity. Heavy-oil reservoirs are a special subset of the oil sands, whereby the oil viscosity at reservoir temperature and pressure varies on the order of 50 to 50 000 mPa·s. While this oil is very viscous, it does have limited mobility at reservoir conditions. As much as 20% of the oil may be recovered by solution-gas drive, but in many cases, the recovery is much lower.
To recover additional heavy oil, a fluid usually must be injected to displace oil to the production wells. However, mobility-ratio concerns dominate displacement of viscous oil, and most enhanced-oil-recovery processes focus on reducing oil viscosity or improving the mobility ratio. Unfortunately, many of the heavy-oil reservoirs in Canada are relatively small and thin, making them poor candidates for expensive thermal processes. This work investigates the potential of A/S flooding for enhanced heavy-oil recovery.
Surfactants are a special class of molecule that is both hydrophobic and hydrophilic; thus, the most stable configuration for these molecules is at the oil/water interface. In surfactant flooding, these molecules generally are injected along with water to reduce the oil/water interfacial tension (IFT), which reduces capillary forces that may trap oil in rock pores. Alkali flooding is a special subset of chemical flooding whereby the surfactant is generated in situ through the reaction between the injected alkali and the acidic crude oil. It is likely that in actual reservoir applications, several processes are working together to improve oil recovery. This work considers the possible mechanisms that could be responsible for enhanced recovery of high-viscosity heavy oil.
Applying Science and Best Practices To Increase Production and Optimize Economics in a West Texas Gas Field
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 117538, "Applying Science and Best Practices To increase Production and Optimize Economics in a West Texas Gas Field - A Canyon-Sand Case Study," by Kelly Blackwood, SPE, (now with Encana Oil and Gas), and Kaylene Williamson, SPE, Highmount Energy; Terry Palisch, SPE, and Mark Chapman, SPE, Carbo Ceramics; and Mike Vincent, SPE, Insight Consulting, originally prepared for the 2008 SPE Eastern Regional/AAPG Eastern Section Joint Meeting, Pittsburgh, Pennsylvania, 11-15 Octo ber. The paper has not been peer reviewed.
Hydraulic fracturing is the most popular and successful stimulation treatment in the petroleum industry. Fracturing technology has opened numerous unconventional hydrocarbon frontiers that, were it not for this process, would be uneconomic to develop. However, designing the optimal hydraulic fracture is anything but an exact science. The industry relies on many simplifying assumptions that assist in making expedient decisions but can prevent reaching a truly optimized treatment. The full-length paper outlines the approach taken by one Canyon sand operator to apply sound science and best practices to meet their financial.

Introduction
A field trial comparing the performance of 20/40 economy-lightweight-ceramic (ELWC) proppant to 20/40 Brady sand was completed in 2006 and 2007 in the Canyon sand, Sutton County, Texas. The trial was initiated after modeling suggested that the current hydraulic fractures were conductivity limited. Twenty-one wells in close proximity to each other were included in the study. Production analyses were performed after all wells had at least 1 year of post-fracture production. Both raw production and production normalized to reservoir quality were analyzed, and both indicate that the wells stimulated with ELWC proppant significantly outperformed the offset wells that used Brady sand. Several economic yardsticks then were evaluated in the full-length paper.

Canyon Sand
The Canyon sandstone is productive in several fields, including the Sonora, Sawyers, Shurley, and Aldwell fields, with first production occurring in 1952. The Canyon-sandstone trend occurs basinward of the western margin of the Eastern shelf in west Texas. The sandstones were deposited from the Eastern shelf into the Val Verde basin. The reservoir is oil prone adjacent to the Midland basin and gas prone adjacent to the Val Verde basin. The vast majority of the sandstone members are fine- to medium-grained quartz lithic arenites.
Resolving Created, Propped, and Effective Hydraulic-Fracture Length
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12147, "Re solving Created, Propped, and Effective Hydraulic-Fracture Length," by C.L. Cipolla, SPE, E.P. Lolon, SPE, and M.J. Mayerhofer, SPE, Pinnacle Technologies, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 December. The paper has not been peer reviewed.
The full-length paper compares the strengths, weaknesses, and limitations of fracture modeling, production-data analysis (PDA), pressure-transient analysis (PTA), and numerical reservoir modeling in estimating effective fracture length and conductivity. The paper also evaluates how the complexities (in the hydraulic fracture) associated with non-Darcy flow, multiphase flow, and complex fracture geometries affect the results from the various techniques. The paper documents the significant differences in "effective" fracture length that, in many cases, can result from each technique.

Introduction
Reliable estimates of fracture length (i.e., created, propped, and producing or effective) are necessary to consider design changes in subsequent fracture treatments to optimize the performance of hydraulically fractured wells, particularly in low-permeability reservoirs. The created fracture length is the fracture length propagated during the fracture treatment, while the propped fracture length is the length supported by proppant after the fracture closes. The effective, or producing, length is the length that is open or contributing to hydrocarbon production after a fracture treatment. Increasing the effective fracture length usually means increased production.
Incorrect estimates of the effective fracture length can lead to less-than-optimal gas recovery and often contribute to modifications of fracturing designs that may not result in improved well productivity. It has been known that the fracture lengths determined from fracture modeling, PDA, PTA, and numerical reservoir modeling are not in agreement with the created fracture lengths obtained from fracture mapping.

Techniques for Determining Fracture Properties

Fracture Modeling.
Fracture modeling (i.e., net-pressure analysis) can provide information about fracture length, height, width, and conductivity. Fracture dimensions and conductivity can be estimated from fracture modeling by matching the observed fracturing net pressures (fracturing pressure minus minimum rock stress, or closure pressure). The limitations of this technique are that it typically provides nonunique solutions, can be unreliable if not calibrated, and requires baseline rock and stress data.
Net-pressure history matching can be implemented by adding new physics to fracture models. With the right assumptions and physics, inferred fracture geometry can be more reliable; however, inferred geometry from net-pressure matching does not always agree with directly measured geometry.
Case Study: Restoring Sand-Prone Subsea Wells to Production
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115058, "Case Study: Restoring Sand-Prone Subsea Wells to Production," by M. Vazir, SPE, and L.G. Acosta, SPE, BP, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed.
This case study describes intervention efforts that returned one dry-tree and two subsea wells to production after an extended shut-in in a mature BP-operated Gulf of Mexico deepwater field. The three wells had been shut in because of sand production. The production facility was not designed with any sand-management capability. Several operational challenges were faced during the planning and execution of this operation. They were carefully assessed, and the risks were managed effectively to return all three wells to production.

Introduction
Pompano is the oldest BP-operated facility in the Gulf of Mexico; first production was in 1994. The facility was developed with 33 dry-tree wells and a 10-well subsea-template tieback to the fixed-jacket platform. The template is tied to the platform through two subsea flow loops, one 8-in. insulated loop for normal production and one 3-in. uninsulated loop for well testing and well servicing (Fig. 1). Pompano-field production peaked at 65,000 BOPD in 1999. By July 2007, total field production was approximately 11,500 BOPD.
Low-cost high-return well-intervention work was key to maximize field value. The challenge for the Pompano team was to identify and implement unique and creative production-enhancement activities. At the forefront of this search was a rigorous effort to revisit and recover production from shut-in wells.

Well Histories
This project focused on three shut-in wells, one dry-tree well (A-03) and two subsea wells (TB-03 and TB-07). Well A-03 was producing 290 BOPD, 52 BWPD, and 1.04 MMscf/D of gas before shut-in. The well was shut in August 2000 because of solids observed in the shake-outs during the monthly testing of the well.
Well TB-03 was shut in initially because of Hurricane Katrina in September 2005. The well remained shut-in for almost 5 months as a result of this event. Before this shut-in, the well was producing 930 BOPD, 480 BWPD, and 1.09 MMscf/D of gas. A startup was attempted in January 2006, and the well produced approximately one-half cup of solids in 8 hours. Shake-outs during this period showed between a trace amount and 10% solids in the flow stream. The well was shut in pending analysis of the produced solids.
Laboratory analysis of the produced solids showed them to be fine grained and that they could have been produced through the type of frac-pack completion in Well TB-03. This information indicated that the integrity of the completion might still remain and that the well could be restored to production.
Q&A with James Farnsworth
Authors: Farnsworth James , Donnelly John 
Published: February 2015

What do you think of oil prices near U.S. $50/bbl? Is that price here to stay?
If past history is any guide, it seems unlikely. There does appear to have been at least a medium-term shift in prices, largely driven by increased demand, particularly in China. Despite this, we still test our projects at U.S. $20/BOE to ensure they are robust throughout the duration of field life.

How have major operators, and in particular BP, reacted to the recent surge in oil prices? Are operators putting more money into exploration, technology R&D, or both?
Many of the projects that result from BP’s exploration success require several years to develop, and, because of their size, they frequently will be produced for decades. Because of this, we work very hard to maintain discipline in our exploration investment, not substantially increasing or decreasing on the basis of price but, rather, opportunities. It is becoming clear, however, that some of our competitors are significantly increasing their investments in exploration as cash flow has increased and reserves replacement has proved difficult.
On technology investment, BP has chosen to invest significant amounts in R&D in some focused areas, which we refer to as Technology Leadership Areas, where we see a real need, a competitive advantage, or perceive a gap in what the service industry is providing.

How much does BP spend on upstream R&D now compared with a decade ago? What accounts for that change?
The spending for BP in this area is roughly similar, but it is much more focused based upon the nature of our evolving portfolio. Obviously, the continued growth of deep water is an example of this. Another is the continuing need for enhanced seismic imaging, moving from simply imaging complex structures to resolving reservoirs in complex structures.
GTL: An Attractive Route For Gas Monetization?
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88642, "GTL: Is It an Attractive Route for Gas Monetization?," by Osama Abdul Rahman and Mohamed Al-Maslamani, SPE, Qatar Petroleum, prepared for the 2004 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 10-13 October.
The gas-to-liquid (GTL) conversion of natural gas into synthetic fuel is an active area of development. Many companies are involved in research, pilot plants, or demonstration units with the objective of reducing capital and operating costs of this technology. Major factors affecting the economics of the GTL process are gas price and capital cost. The GTL process could be an attractive way to monetize stranded gas reserves where the application of pipeline or liquefied-natural-gas (LNG) technology is not technically or economically feasible because the gas is either too far from a market or the gas reserves cannot support an LNG plant.

Introduction
The GTL process involves the conversion of natural gas into a clean source of energy, mainly diesel and naphtha. As the sulfur and aromatics specifications for diesel oil become tighter and complying with exhaust/emission requirements becomes more difficult, the GTL diesel market expands. Production of refinery diesel with ultralow sulfur content from crude oil will be expensive. The production cost of GTL diesel oil, which contains near-zero sulfur and less than 1% aromatics, will become competitive.
Simplified Wellbore Flow Modeling of Gas/Condensate Systems
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89754, "Simplified Wellbore Flow Modeling in Gas-Condensate Systems," by C.S. Kabir, SPE, ChevronTexaco, and A.R. Hasan, SPE, U. of Minnesota-Duluth, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Predicting long-term reservoir performance with realistic wellbore models is fraught with uncertainty because of the complexity of two-phase flow. Even a calibrated two-phase-flow model departs from its expected performance trend when changes in flow conditions occur. The full-length paper explores the possibility of using simplified approaches to computing bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates, gravity of producing fluids, and tubular dimensions. Statistical results from BHP computations on three independent data sets comprising 167 gas/condensate-well tests show that the homogeneous model compares quite favorably with mechanistic two-phase-flow models.

Introduction
Two-phase-flow modeling of gas/condensate wells has not received as much attention as that of oil wells. The popular Gray correlation appears to do a good job in most gas/condensate wells. However, applicability of this correlation outside the bounds of its specified parameters remains unclear.
A user must specify one computational approach for flow in pipes when long-term integrated reservoir/wellbore/flowline performance is sought over a field’s producing life. Declining condensate/gas ratio (CGR) and increasing water production with time have the potential for complicating any modeling effort.
Besides the two-component gas/liquid Gray correlation, other approaches have emerged for modeling gas/condensate flow. The semimechanistic model of Govier and Fogarasi represents the multi-component approach with flash calculations. In contrast, the wet-gas concept offered by Peffer et al. suggests extreme pseudoization with single-component gas.
Computational Approach and Results Data from the literature and those from a few west African fields with medium- to high-CGR production were used. In all, 167 tests were examined. The methods used were the homogeneous model; the steady-state OLGA; those of Gray, Aziz et al., and Ansari et al.; and the wet-gas approach, advanced by Peffer, in which the gas gravity is weighted to include the density of the produced liquid.
Overview: Reservoir Simulation and Visualization (April 2005)
Authors: Smart Tom 
Published: February 2015

The success of reservoir development and reservoir management can be summed up in one statement: The explosion of data available to today’s reservoir engineer mandates the use of advanced simulation and visualization technology.
With ongoing technological advances, our capability to measure and acquire more and more data will continue to increase. This increase in data will stretch the limits of our capacity to gather, manage, and use this information effectively. Our appetite for data will increase further, because as we learn to analyze this data efficiently, we realize additional data are needed. That is, the more we know, the more we realize what we do not know.
Advances in collaborative visualization, along with efficient asset-team organization, are having a profound effect on our ability to make proper use of this wealth of data. Software tools that facilitate true integrated work processes are emerging, providing asset teams the ability to characterize, model, and simulate reservoirs in a multidisciplinary manner. This ability for all asset-team members to communicate by use of visualization throughout the reservoir-management process provides more fit-for-purpose reservoir models, which in turn leads to better drilling choices; improved reservoir development and performance predictions; and, ultimately, better economic decisions under uncertainty.
Additionally, significant advances in reservoir-simulation technology continue. Many of these advances represent approaches to take advantage of the growing mountain of data. More data leads to larger and more-complex reservoir models. Despite ever-increasing computation power, improved methods for scaling up models are needed. Streamline simulation, integrated with dynamic data, has become an effective tool for use in screening, scaling up, and history matching these models. With increased model complexity comes the need to use reservoir-simulation models that maintain that complexity. A new generation of reservoir simulators is emerging that captures the complexity through unstructured gridding, advanced formulations, and integrating surface and reservoir modeling.
Going forward, visualization and reservoir-simulation technology will continue to advance in an attempt to keep pace with the ever-increasing volume of data. In the future, look for advances in real-time data acquisition leading to the need for ever-improving visualization and reservoir-simulation techniques to contribute to the optimization of daily reservoir-management operations.
Additional Reservoir Simulation and Visualization Technical Papers
Available at the SPE eLibrary: www.spe.org
SPE 93080 - Development and Field Application of a High-Performance Unstructured Simulator With Parallel Capability
SPE 90009 - Dynamic Flow-Based PEBI Grids for Reservoir Simulation
SPE 93339 - A New Upscaling Approach for Highly Heterogeneous Reservoirs
Streamline-Based Production-Data Integration in Naturally Fractured Reservoirs
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89914, "Streamline-Based Production-Data Integration in Naturally Fractured Reservoirs," by Mishal Al-Harbi, SPE, Hao Cheng, SPE, Zhong He, and Akhil Datta-Gupta, SPE, Texas A&M U., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Streamline-based models have shown great potential in reconciling high-resolution geologic models with production data. Use of streamline-based production-data integration has been extended to naturally fractured reservoirs. A dual-porosity streamline model was used for fracture-flow simulation by treating the fracture and matrix as separate continua connected through a transfer function. The sensitivities that define the relationship between reservoir properties and the production response in fractured reservoirs were computed analytically. The production-data integration was carried out with a generalized travel-time inversion.

Introduction
Natural fractures play a significant role in subsurface flow and transport of fluids. Seismic imaging and horizontal drilling have revealed the extent of fractures in many reservoirs and enabled operators to use novel ways to use fracture connectivity to enhance recovery. The number of reservoirs that are considered naturally fractured has risen significantly, increasing the need for robust fracture-characterization methods that integrate both static and dynamic data.
Discrete-fracture-network (DFN) techniques map fracture planes in 3D space by use of statistical properties of fracture swarms, fracture-network geometry, and flow characteristics. DFN models can incorporate complex-fracture patterns by use of field-data sources such as cores, well logs, borehole images, seismics, and geomechanics. Although the DFN models can reproduce very realistic fracture geometry, these models must be conditiond to dynamic data (such as well-test, tracer, and production data) to reproduce the flow behavior in the reservoir. Such conditioning is particularly important for fractured reservoirs because only a few of the fractures in the DFN model might carry most of the fluid flow.
Streamline models have shown great potential in integrating dynamic data into high-resolution geologic models. Streamline models can determine the sensitivity of the production data to reservoir parameters such as porosity and permeability. These sensitivities are partial derivatives that quantify how the production response will be affected by changes in reservoir properties. Typically, integrating dynamic data into reservoir models involves solving an inverse problem in which sensitivities play a key role. Streamline-based sensitivities were used in conjunction with a generalized travel-time-inversion method to integrate production data into geologic models.