The U.S. fuels infrastructure has undergone significant changes in the last several years. These changes are in response to shifts in domestic production, imports and exports, processing and distribution. The objective of this analysis is to define and model the U.S. fuels infrastructure, from production, transportation, and processing of crude oil to the distribution, storage, and consumption of refined products, and assess resiliency to natural disasters. This has become a pressing concern in the wake of Hurricane Harvey's impacts on U.S. infrastructure and fuels markets.
The analysis was conducted through a detailed assessment of the petroleum infrastructure, including wells, pipelines, refineries, crude and product terminals, import and export facilities, natural gas storage and processing facilities, and other key components. Interdependencies between petroleum and other types of infrastructure were also evaluated. As part of this analysis, a wide range of natural disasters, including earthquakes, hurricanes, tsunamis, and wildfires, were considered. For each of these natural threats, the geographic risks, the severity and type of damage, the likelihood of that damage, and the time required for recovery were all established using the latest available research.
To complete the analysis several tools were developed and applied. These include a comprehensive geospatial system used to identify major markets and submarkets and to determine dependencies and vulnerabilities; models of the market supply/demand requirements; a national disruption model which details the major crude and product markets; and disruption models to predict the impact on crude and refined products from hurricanes, earthquakes, and tsunamis.
The analysis showed that the U.S. fuels infrastructure is vulnerable to being impaired by natural disasters. Furthermore, the interdependencies of the infrastructure, in terms of both type of infrastructure and geographic location, leave the U.S. vulnerable to cascading risks. As part of the study, potential mitigation efforts were determined to address regional and national vulnerabilities. The proposed mitigation efforts have been incorporated into the Department of Energy's recent Quadrennial Energy Review. This study provides an update and extension of work performed earlier.
The paper provides a detailed assessment of the U.S. fuels infrastructure and its vulnerabilities to natural threats. These include earthquakes, hurricanes, and other disasters. For each of these threats, the geographic risks, as well as the type, probability, and severity of damage, are discussed. Finally, case studies of recent disasters, including the impact of Harvey on the Gulf Coast, Midcontinent, and East Coast, are used to illustrate the fuels infrastructure vulnerabilities and the need for mitigation.
A tertiary alkaline/surfactant/polymer (ASP) multi-well pilot flood was carried out in the San Francisco field, Colombia. The pilot had mixed results, as the positive subsurface response was counterbalanced by serious operational issues, that in the end did not allowed the pilot to realize its full potential. The complexity of the flow paths in a multi-sand reservoir with irregular well spacing lead to large quantities of chemicals being recirculated, which trigger the operational issues, becoming a complex loop where these issues led to closing wells, which led to changing the flow paths and generating more operational issues. The paper presents the design of the pilot, the extensive work that was carried out to understand and improve the flow in the pilot area, the response of the pilot, the challenges that were faced during its operation, and the analysis and lessons learned from this pilot.
Izadi, M. (Ecopetrol S.A.) | Vicente, S. E. (Ecopetrol S.A.) | Zapata Arango, J. F. (Ecopetrol S.A.) | Chaparro, C. (Ecopetrol S.A.) | Jimenez, J. A. (Ecopetrol S.A.) | Manrique, E. (Ecopetrol S.A.) | Mantilla, J. (Ecopetrol S.A.) | Dueñas, D. E. (Ecopetrol S.A.) | Huertas, O. (Ecopetrol S.A.) | Kazemi, H. (Colorado School of Mines)
Surfactant-polymer (SP) flooding (also known as micellar flooding) is an enhanced oil recovery (EOR) process resulting from the interaction of three mechanisms: (1) oil solubilization, (2) interfacial tension reduction, and (3) aqueous-phase mobility reduction by polymer. Surfactant-polymer flooding has been studied both in the laboratory and field pilot tests for several decades. In SP flooding, traditionally a tapered polymer solution follows the injected surfactant slug. However, in recent years, co-injection of surfactant and a relatively high concentration of polymer solution has been used in several field trials. Despite a significant increase in oil recovery in several surfactant-polymer flood projects, the increased oil production period has been of short duration.
The first objective of this paper is to present two field pilot tests which encountered productivity impairment, and the second objective is to describe the probable causes of the productivity impairment. The third objective of the paper is to present a methodology, using field and laboratory data, to anticipate the nature of long-term problems. To shed light on the issues, we will present two pilot tests located in the Illinois basin in the United States and San Francisco Field in Colombia. The results of the pilot tests and several laboratory experiments will be presented to address the productivity loss observed in the two pilot projects. Laboratory measurements to determine crude oil propensity for emulsions, with and without surfactants, are not part of the routine chemical EOR protocol in the industry. Nonetheless, understanding the cause and type of emulsion formation in crude oil, brine, and polymer at different salinities is critical and will be presented in the paper. In addition, in the paper, we will present the results of a numerical simulator to evaluate experimental laboratory results and the field test performance. In conclusion, because of the experience with numerous laboratory experiments and the conduct of associated field tests, we will be able to shed light on the complexity of surfactant-polymer EOR field applications.
Gutierrez, Mauricio (Ecopetrol) | Bonilla, Fernando (Ecopetrol) | Gil, Layonel (Ecopetrol) | Parra, Wilmer (Ecopetrol) | Campo, Pablo (Halliburton) | Orozco, Alex (Halliburton) | Garcia, Monica (Halliburton)
This paper presents the planning and execution process for a key matrix stimulation pilot project performed in the heavy-oil Chichimene field in the central Colombian province of Meta. An understanding of multiple aspects of formation damage, candidate well selection, laboratory testing, treatment fluid selection, onsite quality assurance/quality control (QA/QC), diversion considerations, and placement techniques was fundamental to achieving a successful treatment design. Results are presented in terms of a percentage increase in production rates, percentage decrease in decline rates, and skin value reduction.
Because of current oil and gas industry economics, it is crucial to evaluate the return on investment for any well intervention campaign and apply an assurance process to help quantify the desired improvement in production results. This approach is primarily based on a workflow that includes several key steps: understanding the nature of and characterizing formation damage, reviewing necessary laboratory testing, validating candidate well selection, determining economically viable placement and diversion techniques, and performing QA/QC on site and post-treatment.
Production results from the first five pilot wells are presented along with a review of the production decline and continuous improvement actions. Understanding the induced damage that can be caused by drilling operations, heavy-oil properties, and the potential for emulsion and wettability alteration, in addition to the need to ensure total fluid-fluid compatibility combined with low interfacial tensions (IFTs), can be crucial to achieving results above initial estimates. Aligned with current critical well intervention economics, a rigless operation with coiled tubing (CT) through the Y-tool of an electrical submersible pump (ESP) was selected instead of a traditional intervention with a workover (WO) rig. Because of long treatment intervals and large permeability variations, stages of foamed brine were included in the treatment schedule as a diversion method. A tuned frequency and amplitude tool was used to enhance the placement and effectiveness of the treatment as part of a CT bottomhole assembly (BHA). QA/QC sampling was valuable for treatment monitoring and enhancement.
This paper presents a valuable basis for future candidate well selection and stimulation treatment design. The workflow and its application are a good reference for analogue fields in Colombia and other areas.
This paper discusses successful damage remediation performed in more than 10 wells in a mature oil field producing under a developed waterflooding project in Colombia. The primary damage mechanism observed is associated with a detriment to production related to reduced relative permeability caused by wettability preferences.
A chemical treatment was proposed that consisted of crude oil with efficient and effective surface active additives, such as microemulsions (MEs) and/or formation mobility modifiers (FMMs) and associative polymers (APs) for a proper diversion. The treatment was proposed as an effective method to restore near-wellbore (NWB) permeability in or through the damaged zone in the formation, resulting in production recovery. All matrix-stimulation treatments were conducted rigless by means of an annulus without affecting the artificial lift method and resulted in a significant time and cost savings.
Laboratory data confirmed the ability of the MEs and FMMs to modify interfacial tensions (IFTs) and contact angles. These materials helped promote a change in the degree of wetting of the system, which is dependent on the adhesion tension (the product of the IFT by the cosine of the contact angle). During well treatments, surface pressure spikes during the diversion stages were associated with the arrival of the APs at the perforations and were clearly observed during the development of the treatments, revealing that effective diversion was achieved. Finally, post-stimulation treatment data have shown positive results, confirming the effectiveness of combining these technologies.
This paper discusses how the synergy of using surface active additives with diversion technologies can yield productivity increase in mature oil reservoirs and improve the level of sustainability of current field production.
A number of reservoirs in the Vienna Basin in Austria might benefit from polymer solution injection. In November 2011, a
polyacrylamide polymer injection pilot commenced for the 8th Torton Horizon reservoir to reduce the uncertainties related to
To further improve the understanding of the polymer solution injection, laboratory experiments and numerical simulations
The results of the injection test and laboratory experiments show that two phases can be distinguished: first, a phase of
polymer solution injection below the Formation Parting Pressure (FPP) can be observed. This phase is characterised by high
flow velocities in the near-wellbore area, resulting in severe degradation of the polymer, and a slower rise of the pressure
than expected for undegraded polymers. In the second phase, the FPP is reached and fractures are generated. In this phase,
the polymer solution exhibits shear-thinning behaviour in the fractures. Owing to significantly lower flow velocities in the
formation, degradation of the polymers is limited. Phase one is usually short in comparison to phase two.
To achieve sufficient polymer solution injection rates for an economic project without degrading the polyacrylamide
polymer, inducing fractures by injection is required for the reservoirs in the Vienna Basin. Hence, screening of fields has to
include geomechanical properties of the reservoir sands and surrounding shales. Also, the risk of fracturing outside of the
formation has to be assessed. In addition, the values of the FPP of the reservoir sands and surrounding shales and the
direction of induced fractures should be determined. Furthermore, the injection water quality in terms of fines and oil content
has an impact on the fracture growth and should be evaluated.
Abbiati, M. (Università di Bologna) | D’Errico, G. (Università Politecnica delle Marche) | Piva, F. (Università Politecnica delle Marche) | Onorati, F. (Istituto Superiore per la Protezione e la Ricerca Ambientale ISPRA) | Maccaferri, S. (Università di Bologna) | Isidori, S. (SAIPEM) | Habashi, N. (SAIPEM) | Ambrosini, P. (SAIPEM) | Regoli, F. (Università Politecnica delle Marche,)
Currently, many reservoirs in the region approach the end of primary recovery phase where new techniques are needed to enhance recovery. Therefore, the need to optimize oil recovery from the current resources is very well understood by regional oil companies. To enhance oil recovery from current oil resources, field operators need to overcome the forces responsible for oil entrapment. Enhanced Oil Recovery techniques (EOR) introduce new energy into oil reservoirs to reduce the influence of these forces. Most of these resources contain light oil and are considered suitable candidates for either miscible or chemical EOR techniques. The first technique is challenged by the availability of suitable miscible gas. While, chemical EOR techniques are challenges by the high salt concentrations in the maturing oil reservoirs. The high salinity conditions encourage deficiencies in the performance of chemical EOR processes. Therefore, minimizing the effect of in situ salt on the injected chemical would impose tremendous improvement that leads to higher oil recovery. One way to diminish salt effect is to condition the oil reservoirs by injecting a slug of preflush water prior to chemical injection.
In this paper, the performance of polymer flooding, after preflush slug, in high salinity reservoir is investigated by numerical simulation means. The injected slugs, both preflush and polymer, are driven by water. The objective is to identify the relationship between preflush, polymer, and drive water characteristics and oil recovery. Seven parameters were considered: preflush slug size, preflush salinity, polymer slug size, polymer concentration, polymer slug salinity, and drive water salinity. The results show that these parameters have various degree of influence on oil recovery. For example, increasing the preflush slug size would results in more oil recovery especially during the early time. Detailed findings will be presented in the paper.
Laboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions.
Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate due to degradation of the polymers during the injection process. In addition, polymers exhibit non-Newtonian behaviours resulting in different viscosities of the polymer solutions depending on the shear rate in the reservoir.
For the Austrian reservoir, water injection fall off tests were available. A simulation model was calibrated with these tests, and used to simulate injections of polymer solutions followed by fall offs. Simulation results indicate that water injection and fall off tests followed by a series of polymer injection and fall off tests can be interpreted to determine the in-situ viscosity of polymer solutions and the radius of the polymer front with reasonable accuracy, even in the case of non-Newtonian shear-thinning behaviour.
Being able to determine the in-situ viscosity allows modifying the injection programme ( changing pumps, modifying perforations) if the degradation of the polymer viscosity is found to be significant, and adjusting the polymer concentration to improve stability and efficiency of the displacement process.
Gee, Ryan (National Oilwell Varco) | Ramirez, Tibor (National Oilwell Varco) | Barton, Steven Paul (NOV Downhole Tools & Pumping) | Souza, Julio (Petrobras) | Da Fonseca, Carlos Eduardo (Petrobras) | Cote, Brad (BBJ Tools) | Valmorbida, Decio (National Oilwell Varco)