bluuebunny/crossref_metadata_2025_split huggingface dataset:
Materials Selection: A Systems Engineering Approach
Authors: Caldwell Eric , Annadorai Karthik , Gibson Grant , Jordan Lee 
Published: October 2011

Abstract
Subsea and topsides materials selection is becoming a vital part in the development and long term sustainability of deepwater oil and gas production facilities. Increasing challenges associated with capital and operating cost constraints, schedule compression, remote locations, and the need to deploy materials ever closer to their known limits makes fit for purpose materials selection a complex and difficult issue that crosses many different discipline boundaries. Materials selection is primarily governed by corrosion engineering principles and applied chemical inhibition practices, and then by project specifics. However, there are two different practices that are generally followed that dictate how materials are ultimately selected. The first is by a standard materials selection process using guidance such as that provided in NORSOK M-001, and the second is by using a more informal system with limited guidance that involves individually selecting materials for a specific project.
In actuality, the materials selection process is a combination of both. The selection process to identify which materials are considered appropriate is routine and straightforward and is dictated by various corrosion parameters and associated risks. Often this high-level assessment does not appropriately address project specifics, so causing the final material selections to be substantially different from those initially proposed.
One of the specific items that often drives this change in materials selection philosophy is the use of chemical inhibitors for corrosion inhibition and the perceived feasibility and level of risk associated with this. Use of a systems engineering approach to material selection can be used beneficially as a process that accelerates the determination and initial optimization of the materials, and the selection of chemicals and their injection locations, and associated monitoring methods and locations in a given topsides, subsea or water injection system design. This process can also be used to address management of change items more readily because alternate materials, chemicals, and injection locations are either already determined or can be rapidly identified by the selection process.
The use of a systems engineering approach to materials selection has been instrumental in reducing and/or eliminating risks to ensure maximum productivity and longevity of deepwater production and injection systems while accommodating the unique factors pertaining to each individual project.
Fracturing Fluid Comprised of Components Sourced Solely from the Food Industry Provides Superior Proppant Transport
Authors: Loveless David , Holtsclaw Jeremy , Saini Rajesh , Harris Phil , Fleming Jeff 
Published: October 2011

Abstract
The industry is seeing significant pressure from regulatory bodies concerning the chemicals that comprise typical fracturing fluids. It has long been the belief of the industry that to obtain the best performance of a fracturing fluid, it is necessary to use certain chemicals in fracturing-fluid formulations. However, this paper clearly illustrates that a fluid comprised solely of components sourced from the food industry can excel in maintaining proppant-transport performance.
This paper focuses on the proppant transport of a fracturing fluid that is comprised solely of components sourced from the food industry and approved for direct addition to foods as governed by the Code of Federal Regulations Title 21 (CRF 21). The proppant-transport capabilities of this fluid are compared to a borate-crosslinked galactomannan, a viscoelastic-surfactant (VES) fluid, and a linear-gelled system. The results illustrate that proppant-transport performance does not need to be sacrificed when using a fluid system comprised of components sourced from the food industry.
The ability to carry proppant into the fracture is one of the most fundamental attributes necessary for a successful fracturing fluid. This paper provides an evaluation of four types of fluids currently used as gelled fracturing fluids, employing five different methods to measure their ability to transport and support proppant. The methods used in the evaluation include traditional steady-shear viscosity, small-amplitude oscillation rheology, flow-through-a-slot model, a slurry viscometer, and static settling results.
The results show clearly that the testing methods and protocols do not necessarily agree on the best performance of a fluid system; a comprehensive examination of the limitations and benefits of each are examined. Some of the gels tested showed good proppant support under static conditions, while others showed good transport under flow conditions. The crosslinked gel that was sourced solely from the food industry showed a dramatic difference in that it was able to support proppant under static- and dynamic-shear conditions, leading to superior proppant-transport performance using the five test methods.
Applied Borehole Image Analysis in Complex Sedimentological and Structural Settings: A Single Well Case Study, California, USA
Authors: Amer Aimen , Glascock Michael , Schwalbach Jon , Khan Masood 
Published: October 2011

Abstract
Borehole images are typically used to obtain the structural dip of the formations penetrated by a well, identify thinly bedded reservoirs, and analyze fractures and faults (especially those of subseismic scale). In this paper borehole images are used as depositional environment interpretation tools to identify different elements of a deepwater system and to correlate features observed on borehole images to those exposed at outcrops that are analogs for these deposits. In addition, borehole images are used to verify structural interpretation near the well, which is particularly valuable in areas with poor quality seismic data.
The borehole images captured from a single well in the Ventura basin, California, contain excellent examples of sedimentary features such as groove casts, lenticular bedding, scours, graded beds, and. rip-up clasts. These features enable us to interpret depositional facies such as debris flows, channels, and amalgamated and layered turbidites to better understand the position of the well within the depositional system. We are also able to identify and verify overturned beds and repeat stratigraphic sections in the well because the image logs enable us to document the presence of reverse faults. The outcrop analogs we discuss are from the Pliocene Pico formation from the Ventura basin in California. Features observed on the outcrops are similar to features observed on borehole images and in cores, allowing us to extend our facies interpretation to larger areas of the field.
Detailed structural analysis of the image log from this well using manually-interpreted formation dips shows three large-scale thrust zones (at least 3000 ft each) associated with highly tilted and in one case overturned beds. This analysis enhanced our structural understanding of this compressional regime. This is an important tool in areas such as the Ventura basin, where seismic data is not easily acquired because of the rugged terrain and steeply dipping structural limbs. Combining the sedimentological and structural information from the borehole image interpretation provides a better understanding of the reservoir geometry and likely connectivity between reservoir units. This information is critical for choosing the next well location and planning future development strategy. This paper demonstrates the value of utilizing borehole images to understand local depositional systems and complex structures within an active field development program.
Effect of Relative Permeability Characteristics and Gas/Water Flow on Gas-Hydrate Saturation Distribution
Authors: Behseresht Javad , Bryant Steven 
Published: October 2011

Abstract
The descent of the base of gas hydrate stability zone (BGHSZ) through gas accumulated in a sediment is analyzed. A mechanistic model enables estimating hydrate saturation from initial distribution of gas phase saturation in sediment with known grain size distribution. The initial gas phase saturation is estimated from the profile of capillary entry-pressure with depth. The latter is estimated from grain size variations. A mechanistic model is proposed to determine the relative rates of methane and water transport into the HSZ during hydrate formation. The gas accumulation is assumed to be isolated so that methane transport occurs only within it. If water transport occurs only by co-current flow of gaseous and aqueous phases up to the hydrate stability zone (HSZ), it is not possible to create large hydrate saturations from large initial gas saturations due to limitations on water flux imposed by typical relative permeability curves. Thus the observed large hydrate saturations, such as that observed in Mt. Elbert, Alaska and Mallik, NW Territories and deep Indian Ocean, above the BGHSZ suggest another form of water flow: water moves down through accumulated hydrate from above. This requires the aqueous phase to remain connected within the hydrate-bearing sediment. The ratio of aqueous phase permeability in the hydrate-bearing sediment to the aqueous phase relative permeability at residual gas saturation determines hydrate saturation profile. The model is validated against field data from a hydrate-bearing sand unit in Mt. Elbert.
Analysis of Plunger Lift Applications in the Marcellus Shale
Authors: Kravits Matthew , Frear Ray , Bordwell Dave 
Published: October 2011

Abstract
Field testing was performed on plunger lift systems in horizontal Marcellus shale wells. Plunger lift software from Echometer Company, Total Well Management, or TWM was used on certain wells to monitor acoustic trace, casing pressure, and tubing pressure throughout the plunger cycle.
The plunger lift testing program addresses the challenges presented in shifting from vertical to horizontal well plunger lifting. The plunger lift testing addresses the feasibility of running plunger lift on wells with X and XN-profiles. These nipples are used to provide safe snubbing operations. The most valuable insight from the testing involves the possibility of running plunger lift to deviation angles of 70° and greater.
The results of the plunger lift testing yielded several conclusions. An important result was that all plungers successfully passed through the X-profile, contrary to industry doubt. Another conclusion was that all plungers fell down to their bottom deviation angle with the deepest falling of 70°. Testing also showed the importance of performing TWM investigations on every plunger lift well to optimize plunger cycles. The most notable result was the phenomenon that plungers fell faster below kickoff point. This phenomenon suggests the possibility of plungers travelling to 90°. The observed trends of 53 TWM traces suggest that current plungers in horizontal Marcellus shale wells can theoretically reach a final deviation angle of 74°.
Plunger lift systems have been used across the United States for decades to unload small amounts of liquid (water, oil, and/or condensate) as gas rates fall below the minimum critical rate to continuously unload fluids. The Marcellus shale is a vital asset to natural gas production in the United States. Development has transitioned from a vertical well science program to a proven horizontal well development program. Plunger lift has become common among some operators in the Marcellus shale for wells which have fallen below their critical gas rate. Our plunger lift program shows promise to maintain production after wells reach unstable flow up the tubing. Marcellus shale production can potentially benefit significantly if plungers eventually reach deviation angles of 90° since it will allow for production of fluid left in the horizontal lateral.
Understanding and Predicting Fayetteville Shale Gas Production Through Integrated Seismic-to-Simulation Reservoir Characterization Workflow
Authors: Ramakrishnan Hariharan , Peza Eva , Sinha Shekhar , Woods Miriam , Ikeocha Christopher , Mengel Flemming , Simon Yves , Pearce Paul , Kiester Jeff , McKetta Steven , Jeffers John 
Published: October 2011

Abstract
This paper describes a comprehensive workflow that incorporates geologic, seismic, and production data in an effort to understand and predict the performance of gas wells in the Fayetteville Shale play. A reservoir model was developed by integration of all available well, log, petrophysical, sonic, image, core, stimulation, production, microseismic and processed surface seismic data. This static reservoir model was used to history match the short- and long-term production performance and its variations across the exploration area. History matching production profile from multiple wells is a critical step toward understanding the key production drivers in unconventional shale gas formations. This workflow involves extensive use of surface seismic to develop a velocity model and to distribute reservoir properties. This paper highlights the multidisciplinary knowledge that was applied in the project and the lessons learned.
The reservoir characterization and dual-porosity simulation model developed was used to predict production performance of future wells in the Fayetteville Shale formation. Key production drivers—such as matrix quality, natural fractures, net gas porosity—and ways to identify and exploit these parameters during the development phase of the reservoir are discussed. The ability of the models to predict production performance is also discussed. This workflow is useful in selecting drilling locations, identifying best landing points, optimizing well spacing, and guiding completion practices.
Is There Evidence of Super Cycles in Oil Prices?
Authors: Zellou Abdel M. , Cuddington John T. 
Published: October 2011

Abstract
A number of authors have claimed that the strong upward movement in commodity prices since 2000 represents the early phase of a ‘super cycle’ (SC) driven by industrialization and urbanization in the BRIC countries (Brazil, Russia, India and China), especially China. Moreover, Heap (2005), Cuddington and Jerrett (2008), Jerrett and Cuddington (2008) and others have found evidence of SC (20-70 years in length from peak to peak or trough to trough) in metals prices associated with earlier industrialization episodes in Europe, the U.S., and Japan. These cycles are much longer in duration than the typical business cycle, defined as 2-8 years. The purpose of this paper is to address the question: is there evidence of super cycles in crude oil prices?
Our approach to the empirical question posed in the title applies the asymmetric Christiano-Fitzgerald band-pass filter to real crude oil prices from 1861 to 2010 in order to extract a cyclical component with a period between 20 and 70 years.
Our results suggest the existence of SC in energy commodities with a strong correlation between the SC of coal and oil prices after World War II. The SC analysis is carried out using both nominal and real prices in order to determine whether these SCs are an artifact of the price deflator used. There appear to be three obvious SCs in oil prices, the first one between 1861 and 1884, and the last two from 1966 to date. The period 1884-1966 is harder to interpret and has been aggregated into one SC. These results are consistent with the recent work performed by Dvir and Rogoff (2009) on the changes in real oil price persistence and volatility.
There has been renewed interest in commodity prices over the past decade. Evidence on the presence of SCs in energy commodities is valuable for national and state governments, financial institutions and oil and gas companies. At the government level, countries that rely on the import or export of energy commodities need to take SCs into account when formulating resource extraction as well as revenue and expenditure policies. At the firm level, the exploration-development-production-distribution-research-and-development cycle of energy projects often spans several decades, as do SCs. Hence the investment decisions made by oil and gas companies should take into account the presence of these SCs.
The Design and Execution of Frac Jobs in the Ultra Deepwater Lower Tertiary Wilcox Formation
Authors: Haddad Ziad , Smith Mike , De Moraes Flavio Dias , Moreira Oswaldo 
Published: October 2011

Abstract
A considerable amount of effort goes into designing one of the deepest frac jobs in the world. For the past several years, Petrobras has been working on developing the Cascade and Chinook fields which are located in the Gulf of Mexico (GOM), 250 miles south of New Orleans in ultra deepwater depths between 8200 ft and 8900 ft. The oil producing reservoir is in the Lower Tertiary Wilcox formation with a gross sand thickness of 1200 ft. The reservoir mid-point is at an average depth of 25, 600’ TVD with a bottomhole pressure of 19, 500 psi and a bottomhole temperature of 260°F. The reservoir is comprised of vertically stacked thin beds of sand and fine grained siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in a paper written by Moraes el al (2010).
Multiple limitations were considered during the initial design phase of the frac pack program. The fracs were designed taking into account the use of a Single-Trip Multi-Zone sand control system. Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operation stand point due to a continuous, multi-stage frac operation. Some of the operation limitations included service tool erosion limitations due to maximum pump rates and proppant volumes, overall frac vessel capacity, boat-to-boat fluid transfers and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool spacing limitations and still maximize contact with net pay.
This paper addresses the approach taken to develop a fracture stimulation program for the Lower Tertiary formation in the Cascade and Chinook fields. Some of the major questions addressed during this process include the following: how many fracture treatments are needed, what is the optimum fracture geometry, what is the desired conductivity, how to effectively position the perforation intervals, what is the desired pump rate and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations.
Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (due to depth and in-situ stresses) where fracturing is required for both stimulation and potential formation collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.
A Practical Method to Calculate Polymer Viscosity Accurately in Numerical Reservoir Simulators
Authors: Sharma Abhinav , Delshad Mojdeh , Huh Chun , Pope Gary A. 
Published: October 2011

Abstract
Polymers play a key role in several EOR processes such as polymer flooding, surfactant-polymer flooding and alkaline-surfactant-polymer flooding due to the importance of mobility control in achieving high oil recovery. Numerical simulations are used to predict the performance of these processes and in particular the injection rate of the polymer solutions since the economics are sensitive to the injection rates. It is important to model the polymer viscosity accurately so that accurate predictions of injection rate can be made. Because the viscosity of the non-Newtonian polymer solution is a strong function of shear rate, the calculation of shear rate must be accurate. The shear rate depends on the local velocity in the reservoir. As the gridblock size increases, the calculation of this velocity is less accurate, especially close to the wells. We present a method to calculate the effective shear rate for the gridblock sizes that are practical for large field simulations. We also present improvements in the polymer viscosity model. At high temperature, the rate of hydrolysis of polyacrylamide polymers is significant over reservoir time scales. A simple scheme was developed to account for the hydrolysis and the corresponding change in viscosity as the polymer flows through the reservoir. This study demonstrates that accurately computing polymer viscosity is important for the proper representation of not only the well pressure, but also for the pressure distribution substantially away from the wellbore, thereby significantly influencing the performance of chemical EOR processes that use polymer.
Design of Simultaneous Enhanced Oil Recovery and Carbon Dioxide Storage Applied to a Heavy Oil Field Offshore Trinidad
Authors: Sobers Lorraine E. , Blunt Martin J. , LaForce Tara C. 
Published: October 2011

Abstract
We have developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are based on PVT-matched properties of oil found in an unconsolidated deltaic, sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region oil density ranges between 940 and 1 010 kg/m3 (9-18 degrees API). We use counter-current injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir and gas is injected in the lower portion. The two water injection rates investigated, 100 and 200m3/d, correspond to water gravity numbers 6.3 to 3.1 for our reservoir properties. We have applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals. Eight simulation runs were conducted varying injection gas composition for miscible and immiscible gas drives, water injection rate and injection well orientation. Our results show that water over gas injection can realize oil recoveries ranging from 17 to 30%. In each instance more than 50% of injected CO2 remained in the reservoir with less than 15% of that retained CO2 in the mobile phase.