bluuebunny/crossref_metadata_2025_split huggingface dataset:
Thermal/Stress-Loading Analysis for Tubulars in HP/HT Wells
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24852, ’Importance of Thermal/Stress-Loading Analysis for Tubulars in HP/HT Wells,’ by Norman Shahreyar, SPE, and Douglas Finley, SPE, Halliburton, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed.
This paper provides an overview of an engineering-design methodology that can be followed for tubular-equipment sizing and selection for use in complex wells. A typical list of reservoir and well parameters required to set up the well model for thermal and stress-loading analysis is presented. Furthermore, a full well-casing and tubing-design-integrity analysis is performed on a complex, high-rate, high-pressure/high-temperature (HP/HT) example well with various anticipated operating loads.
Introduction
The purpose of tubular-design analysis and validation is to analyze tubing loads, design integrity, and buckling behavior under complex mechanical- and thermal- loading conditions, as well as fluid pressure effects. It is very important to perform thermal and pressure analysis for a well and then to use estimated temperature and pressure profiles in a tubular- stress analysis in well-completion designs. This is true for any well completion and is especially important in HP/HT wells, deepwater wells, and subsea wells (with emphasis on recognition of annulus fluid expansion). Thermal and stress analysis helps to estimate whether the proposed or existing completion for the well is fit for purpose when subjected to varying well-operating conditions during the life of the well. Therefore, for a proper completion design, it is critical that this analysis be performed while the completion is still in the planning stage.
Technology Focus: EOR Operations (June 2014)
Authors: Bonet-Cunha Luciane 
Published: February 2015

Technology Focus
Enhanced-oil-recovery (EOR) methods have been increasingly positioned into the mainstream of project planning these past years as conventional, highly productive, and large reservoirs have become more difficult to find. As a result, in recent years, various innovative EOR techniques seeking to maximize total reservoir recovery have gained renewed interest and attention. However, despite the wealth of knowledge already available and heavy investments made from a number of operators, it is certain that the potential of EOR solutions has not been fully realized.
One key area that can boost EOR projects’ results and challenge the professionals involved is the pursuit of EOR operational excellence. Although it can be seen as a trivial target, it is in fact a quite complex goal. Besides experienced management, it involves a well-prepared multidisciplinary team in the planning phase, definition, controlling of the contracts, and the safe and precise execution and monitoring of the operation. Integration is key to the implementation of efficient and safe operations with minimization of operational costs. Like a winning World Cup football team, victory will depend as much on a good coach as on well-prepared and integrated players. They have different roles to play during the game, but they all target the same goal.
Continuous Seismic Reservoir Monitoring of Thermal Enhanced Oil Recovery
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165428, ’Continuous Land Seismic Reservoir Monitoring of Thermal EOR in the Netherlands,’ by Julien Cotton, Laurene Michou, and Eric Forgues, CGG, and Kees Hornman, Shell Global Solutions International, prepared for the 2013 SPE Heavy Oil Conference Canada, Calgary, 11-13 June. The paper has not been peer reviewed.
A reservoir-monitoring system has been installed on a medium-heavy-oil onshore field in the context of redevelopment by gravity-assisted steamflood. The challenge was to monitor the lateral and vertical expansion of the steam chest continuously with seismic reflection. The high sensitivity of the buried acquisition system allows the tracking and monitoring of very small variations of the reservoir’s physical properties in both the spatial and calendar domains. A daily 4D “movie” of the changes allows proposing a scenario that explains the unexpected behavior of the production.
Introduction
The Schoonebeek field is in the northeast of the Netherlands with 1 billion bbl of stock-tank oil initially in place. Between 1948 and 1996, the oil was produced with several small-scale thermal enhanced-oil-recovery pilots with vertical wells. Today, the oil is produced by gravity-assisted steamdrive. A permanent seismic system including 2D and 3D phases was installed in 2010 to monitor the reservoir’s evolution during steam injection. The monitoring lasted 2 years. During this time, the propagation of the steam plume injected into a horizontal well located between two horizontal producer wells was tracked in order to understand the 4D behavior of the steam and possibly update the dynamic production model.
Analyzing, Optimizing Frac Treatments By Means of a Numerical Simulator
Authors: Soliman M.Y. , Grieser W. 
Published: February 2015

Technology Update
Hydraulic fracturing and refracturing has become an integral part of completing wells, especially in unconventional reservoirs such as tight gas formations, shale, coalbed methane, and tight oil reservoirs. Practicing reservoir and production engineers now require access to a well-completion simulator. This completion simulator should have the ability to simulate productivity of complex reservoirs and wells, not only to design an optimum fracturing treatment but also to analyze production results. For a practicing engineer, the prediction of productivity of fractured wells requires a balance between accurate representation of the physical process of reservoir fluid flow and the time required to simulate that process. Because unconventional reservoirs and associated wells can be complex, analytical solutions are usually not capable of providing an adequate prediction of the well performance. The need for a comprehensive, yet easily accessible, numerical simulator for well-completion processes has become a necessity.
The basic philosophy behind such a simulator is that it would
Emphasize prediction of a small number of wells, including the capability of predicting single-well production and performing related analysis.
Provide higher speed in both simulation and turnaround rate. This goal can be achieved through the use of a graphical user interface. Some of the more complex features may be accessible to more sophisticated users by means of special file handling to enhance analysis capability.
Automate the simulation of specialized features that may be crucial to stimulation. These features include the following:
Consideration of the fracturing-fluid filtrate as a separate aqueous fluid
Linkage to a commercially available proppant library
Ability to import fracture geometry and properties, including proppant concentration and type, fracture width, and amount of fluid leakoff into the formation for each fracture grid from commercially available fracture-design simulators—specifically, the 3D design programs StimPlan (NSI Technologies) and GOHFER (Barree and Associates)
Statoil: A Journey Across Energy Frontiers
Authors: Sheehan John 
Published: February 2015

Editor’s note: This is the first in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.
As the Norwegian Continental Shelf (NCS) matures, Statoil is trying to earn maximum value from its home patch, while at the same time repositioning itself for future growth internationally.
Originally formed in 1972, Statoil merged with rival Hydro in 2007 to create StatoilHydro, before the Statoil name was reclaimed last year when the company was rebranded. The new Statoil adopted a star-shaped logo, inspired by the starry skies of the north, to symbolize its aspiration to be a “pathfinder” in oil, gas, and other energy forms.
The merger of the two Norwegian energy giants strengthened the new company organizationally, technologically, and financially, says company Chief Executive Officer Helge Lund.
“We are a larger company, more competitive in an international context. Since the merger we have been able to attack more business opportunities in more countries,” he said. “Entering the Shtokman partnership in Russia, taking over as operator of Peregrino in Brazil, acquiring a substantial shale-gas position in the US, and delivering a winning bid in Iraq are some of the business opportunities we have captured since the merger.”
Statoil is the largest operator on the NCS, with approximately 60% of its total production. It also operates oil and gas fields in Algeria, Angola, Azerbaijan, Brazil, Canada, China, Iran, Libya, Nigeria, Russia, the United States, and Venezuela.
In the long term, as well as garnering maximum potential from the NCS, Statoil is looking to its international asset base to allow it to grow and become more diversified, both in geographical terms and in types of production.
The company also has ambitions to develop profitable midstream and downstream positions as well as a strong renewable base, particularly in wind power. In offshore wind, Statoil is in a partnership to develop the Sheringham Shoal project in the UK, with 88 turbines coming on stream in 2011. The Forewind consortium, in which Statoil participates, was awarded the largest development area in the UK’s third licensing round for offshore wind farms. Meanwhile, off the western coast of Norway, Statoil is testing a prototype of the world’s first full-scale floating wind turbine, Hywind, designed for operation in deeper waters.
Upstream Priorities
Traditionally, Statoil’s focus has been on its upstream activities and the company has identified four priority growth areas moving forward: deep water, gas-value chains, harsh environments, and heavy oil.
Technology Focus: Reservoir Simulation (July 2010)
Authors: Crick Martin 
Published: February 2015

Technology Focus
At the 2009 SPE Annual Technical Conference and Exhibition held in New Orleans, I discovered at the Editorial Committee meeting that this Reservoir Simulation feature led the league table in terms of numbers of papers to review. This is a great indicator of the dynamism and innovation going on in our discipline, even if it did also make a pretty daunting task for your reviewer! We, therefore, agreed to spin off a separate feature on History Matching, which appeared in the April issue of JPT: Go back and check it out if you missed it. Despite this, I still had a large number of papers to choose from.
Developments in our discipline cover a wide frontier, ranging from the physics of shale-gas reservoirs, to many approaches for improving computational efficiency, through workflow approaches for keeping models up to date and consistent. The underlying aims can be summed up best on the one hand as the relentless pursuit of more-predictive models through better physics and accuracy of reservoir description, and on the other hand as trying to achieve this aim ever more efficiently in terms of engineering and computational resources.
As I mentioned last year, optimization continues to be a major topic, not just in history matching but also in prediction workflows. This is hardly surprising: Making optimal reservoir-management decisions is the main reason for doing reservoir simulation. Applying automation to the task can reduce the drudgery involved in trying many scenarios manually. Some operators are working toward a vision of integrating simulation models into systems that make operational decisions automatically or semiautomatically. Other operators prefer to gain general insight from more-general representative models and then make their decisions relying on engineering judgment.
Whichever approach you take, the pressure to make every well pay in the current downturn means that there is renewed interest in many companies in applying higher levels of engineering and science. The challenge to us as reservoir engineers is to ensure that increased sophistication of engineering remains relevant and contributes to better field-management decisions.
Reservoir Simulation additional reading available at OnePetro: www.onepetro.org
SPE 127853 • “Uncertainty Evaluation in Emerging Gas Projects in North Africa Using Geological Modeling, Reservoir Simulation, and Experimental Design” by M. Vicente, Repsol YPF, et al.
SPE 125568 • “Ensuring Water-Saturation Consistency Between Static (Fine-Grid) and Dynamic (Upscaled) Models—A Case Study of the North Kuwait Jurassic Complex” by Kassem Ghorayeb, Schlumberger, et al.
SPE 125559 • “Upscaling in Partially Fractured Oil Reservoirs Using Homogenization” by Hamidreza Salimi, SPE, Delft University of Technology, et al.
Modeling CO2 Storage in Aquifers: Assessing Key Contributors to Uncertainty
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123582, ’Modeling CO2 Storage in Aquifers: Assessing the Key Contributors to Uncertainty,’ by W. Sifuentes, SPE, Schlumberger; M.J. Blunt, SPE, Imperial College; and M.A. Giddins, SPE, Schlumberger, prepared for the 2009 SPE Offshore Europe Oil and Gas Conference & Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed.
The influence of different physical properties on the effectiveness of CO2 storage in aquifers was studied. A numerical sensitivity analysis based on experimental design was used to quantify and compare the contribution of the most important parameters to the trapping of CO2. The work focused on the effects of dissolution and residual trapping. Reservoir simulations with properties and geometries representative of the Stuttgart formation in Ketzin, Germany, demonstrated how different trapping mechanisms are influenced by gravity segregation, fingering, and channeling.
Introduction
This focus was on CO2 storage in aquifers because this storage option is emerging with great potential, having a high estimated capacity to store CO2 in geological formations (estimates range from 400 to 1000 Gt of CO2). Several CO2-storage projects are under way or planned (pilot, research, commercial projects), and many of the commercial projects are related to major gas-production facilities, at which gas-production streams contain high levels of CO2 (e.g., Sleipner in Norway, In Salah in Algeria, and Gorgon in Australia). The first commercial project related to CO2 storage in aquifers was the Sleipner project in Norway, where approximately 1 Mt/a of CO2 captured from the gas-production stream has been injected since 1996 in the Utsira saline formation.
The efficiency of long-term storage in aquifers is related directly to the efficiency of each of the trapping mechanisms involved. In the context of CO2 storage, particularly in aquifers, there are four major trapping mechanisms.
Hydrodynamic (structural or stratigraphic) trapping—caprock prevents mobile CO2 from flowing back to the surface.
Residual or capillary trapping—capillary forces and relative permeability effects contribute to converting the CO2 injected into an immobile phase.
Solubility trapping—CO2 dissolves in the aqueous phase.
Mineral trapping—chemical reactions between CO2 and rock minerals form a solid carbonate.
During the injection phase, structural or stratigraphic trapping is the main contributor preventing CO2 from escaping to the surface. Mineral trapping is the safest long-term way to trap CO2 because it transforms CO2 into an immobile solid. However, this process can be very slow. The focus here was on capillary and dissolution trapping, which are likely to be effective on an intermediate time scale.
Europe Gears Up for the Shale Gale
Authors: Sheehan John 
Published: February 2015

The European shale gas revolution is still in its infancy and though its commercial potential could rival that of North America, significant challenges lie ahead. France has put a moratorium on shale gas activity while a comprehensive study into its environmental impact is being carried out, and its National Assembly has voted in favor of a ban on hydraulic fracturing.
The potential for shale gas production in Europe is undoubted, as consultancy IHS CERA estimates that Europe’s total shale gas in place could be 6,115 Tcf. Among the key challenges that will determine the ultimate productivity in Europe is a regulatory environment that is currently ill-suited to unconventional gas, the company said. “Regulations designed for traditional exploration and production in Amsterdam. “We expect Europe to be a significant part of future activity.”
Poland Leads the Way
Poland plays host to Europe’s largest known reserves of shale gas. Leasing activity in the country’s three main basins—the Baltic Basin, the Podlasie Basin in the east, and the Lublin Basin to the south—is well under way. The country is keen to push forward with shale gas production as it looks to break away from its reliance on Russian gas supplies.
The US Energy Information Administration (EIA) estimates that Poland has 792 Tcf of risked shale gas in place, with 514 Tcf in the Baltic Basin, 222 Tcf in the Lublin Basin, and the remainder in the Podlasie Basin. Chevron and ExxonMobil have been joined by a large number of smaller players such as DPV Service, Cuadrilla, EUR Energy, and Mazovia Energy in securing acreage across the country.
Talisman is carrying out seismic acquisition on con-cessions in the Baltic Basin and it is on track to spud its first two shale gas wells in the fourth quarter of this year, the company said. It moved into the Polish plays through a farm-in arrangement with San Leon Energy for a 60% interest in San Leon’s three concessions. Talisman is committed to drilling a minimum of three wells—Gdansk-W, Braniewo-S, and Szczawno—which cover 600,000 acres. Three optional wells with horizontal sections will be drilled after a successful first phase of testing. San Leon is also engaged in a five-year exploration and development program on its two concessions, Nowa Sol and Wschowa in the Permian Basin South. Both concessions are on trend with prolific Rotliegendes gas and Zechstein oil production.
Nexen recently entered into an agreement with Marathon to jointly explore 10 concessions in Poland’s Paleozoic shale play and it says it will pump USD 100 million into shale-related activities. Nexen will acquire a 40% working interest in the concessions, which encompass more than 2 million acres. Marathon is acquiring 2D seismic this year and plans to drill one or two wells in the fourth quarter and potentially seven or eight wells during 2012.
Shale Gas: Promising Prospects Worldwide
Authors: Beckwith Robin 
Published: February 2015

Shale gas is everywhere. China's estimated technically recoverable shale gas resources, at 1,275 Tcf, are almost 50% greater than those touted in the US. Argentina, with 774 Tcf, contains 150 Tcf more than all of Europe. These numbers were spelled out in “World Shale Gas Resources: An Initial Assessment,” a study released April 2011 under the auspices of the US Energy Information Administration (EIA), which commissioned the study from Advanced Resources International (ARl).
China, in fact, ranks first in shale gas resources, followed by the US, Argentina, Europe, Mexico, South Africa, Australia, and Canada. Although the study is preliminary and excludes areas like Russia and the Middle East, there is no doubt shale gas resources exist in abundance worldwide. The numbers ARl arrived at are rough. With more extensive data and more time to assess it, ARl stated, the amounts would be higher.
However, Donald L. Gautier, chief of the US Geological Survey (USGS) World Petroleum Project, introduced a note of caution regarding the EIA study's figures. The USGS is in the midst of its own assessment of global continuous accumulations, including technically recoverable gas from source rock systems such as gas shales. Initial results from the first basins assessed will be released within the next few months. According to Gautier, the USGS approach, which is geologically based, probabilistic, and emphasizes application of well performance data from analog shale plays in North America, is quite different from that of ARI. “I wouldn’t be at all surprised if the results are as different as the methodology,” he said.
Shale Gas Economic Requisites
While shale yields approximately 20% (4.8 Tcf in 2010, according to the EIA) of US natural gas consumption, this resource has yet to contribute more than negligibly in regions elsewhere. Yet many countries, buoyed by and in some cases participating in US shale gas exploitation, appear poised to initiate shale gas development within their borders. However, with a lack of shale drilling and completion services, as well as gas production and transportation infrastructure, promising shale gas reservoirs need at least five to 10 years before production would be economic.
Three Steps to a Risked Revenue Forecast
Authors: Schulz Rodney , McCormack Don 
Published: February 2015

Management
For many reasons, different assets have different levels of risk/uncertainty associated with a decline curve forecast. Failing to quantify these differences in uncertainty is the equivalent of disregarding a significant piece of the business equation because one must include risk and uncertainty when forecasting production.
Similarly, failing to quantify the risk associated with a product price forecast—or arbitrarily assuming “high,” “medium,” and “low” cases—is also ignoring a piece of the equation that is not only scientifically/statistically possible to assess, but also quick and easy to calculate. Moreover, to understand and plan for the business situation based on decline curve forecasts, one needs to combine the uncertainties of both the decline curve forecast and the product price forecast.
Using low-cost personal computer software, one can quantify the uncertainty spread surrounding the situation to determine the risk associated with a revenue forecast. Because decline curves represent physical systems from the reservoir through the sales meter or stock tank, different decline curves have differing amounts of volatility. Hence, assuming the physical system around the asset does not change, one can systematically quantify the differing degrees of certainty in the forecast (Figs. 1a and 1b).
Having quantified the uncertainty associated with the production forecast (Step 1), the professional or manager then turns to the uncertainty associated with product prices (Step 2). Previous analysis and research indicate that oil and natural gas markets are “efficient,” i.e., prices reflect all available public information almost instantaneously and price movements follow a “random walk” model (Figs. 2a and 2b). The random walk premise also suggests that the best forecast of tomorrow’s price is today’s price. Therefore, using a given starting price, one can easily quantify the product price uncertainty going forward.
Price volatility ebbs and flows over time. However, looking at historical price volatility will give one a reasonable estimate of the future volatility that one’s organization should be prepared to accommodate. Hence, rather than assuming a price and basing the business model on it, one can proceed with a known price—today’s price—and proceed with a price volatility estimate that is reasonable and scientifically/statistically derived.
Having quantified the uncertainty associated with the production (Step 1) and with product prices (Step 2), it is a matter of using statistical analysis to quantify the uncertainty associated with forecasting revenue (Step 3), which is the product of the two. Doing this will yield a revenue forecast that may be alarming when one sees the uncertainty.