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Meeting the growing global energy need is the biggest challenge for humankind in the 21st century. Worldwide energy consumption in the year 2001 was 404x1015 Btu ( 200x106 BOEPD). World population is increasing along with per capita income, especially in developing countries such as China and India. Because energy use increases with income, energy consumption is expected to triple in this century. As of 2000, oil accounted for 39% of all energy use; gas and coal provided 23% and 22%, respectively.
If all technological innovations produced by the oil and gas industry were added up, they would probably rival NASA's space program or the Industrial Revolution. Driving these innovations have been the increasing challenges of locating, accessing, and exploiting hydrocarbon reserves. As oil and gas gets harder to find and extract, the costs of extraction escalate, and this drives innovation that makes the process more efficient and cost-effective. Before we speculate on the technological future of the oil field, let us look at some fundamental questions, such as what drives innovation, what does it cost, who pays for it, and who performs it? In general, innovation relates to the application of new ideas, products, or techniques.
Summary The heavy-oil- and bitumen-recovery process by injection of a pure condensing solvent in a solvent vapor chamber provides an alternative to steam-based recovery techniques such as steam-assisted gravity drainage (SAGD). Because of the lower operating temperature between 40 and 80°C, the process uses a much lower energy budget than a steam process and thus results in significantly reduced greenhouse-gas emissions. This paper describes the route to a successful production function with the physical processes at play and using analytical tools. Physical relationships are derived for the solvent/bitumen (S/B) ratio, the bitumen drainage from the roof of the solvent vapor chamber, and for bitumen extraction from both sides of the solvent chamber by the draining condensed solvent. The fast diffusion of bitumen into this narrow liquid solvent zone is likely subtly enhanced by transverse dispersion. The speed of bitumen extraction from the roof of the solvent vapor chamber is constrained by the gas/oil capillary pressure. Extraction from the side of the chamber is approximately three times faster by the action of the thin gravity-draining liquid solvent film. Several equations are provided to enable creation of a heat balance for this condensing solvent process. Laboratory and field observations are matched, including the rates, the heat balance, and the S/B ratio. The model can explain constrained production performance by identifying the rate-limiting steps (e.g., when insufficient solvent condenses). The model predicts high solvent holdup during the rise of the solvent chamber. A method to estimate this solvent liquid saturation is provided. The S/B ratio depends on injector-wellbore heat losses, the (high) liquid saturation in the rising solvent chamber, and the process properties (operating temperature), reservoir properties (heat capacity, porosity, and oil saturation), and solvent properties (density and latent heat). In the existing body of literature, no satisfactory analytical model was available; this new approach helps to constrain production performance and to estimate solvent and heat requirements. The methods in this paper can be used in the future for subsurface project design and performance predictions.
California is known for being at the forefront of renewable technology adoption and greenhouse gas emissions curtailment. Even in an industry seen by many residents as archaic, oil producers are increasingly seeking out alternative sources of energy to use in operations. The high number of aging heavy oilfields, high quantity of sunshine, and state's environmental sensibilities make for an ideal proving ground for a technology that brings two divergent industries together: solar thermal enhanced oil recovery (EOR). In 2011, Berry Petroleum and solar energy provider GlassPoint started up a 300-kW thermal project at McKittrick oilfield in Kern County that ultimately produced 1 million Btus/hr of solar heat over its 5-year lifespan while reducing the field's gas consumption. That same year, Chevron Technology Ventures and BrightSource Energy launched a 29-MW thermal solar-to-steam facility as part of a 3-year pilot project at Coalinga oilfield in Fresno County.
Energy sources are vital to sustain and grow the world economy. As of today, the world mainly relies on fossil fuel as the source of energy for transportation, power generation, chemicals manufacturing, and other industrial applications. The conventional sources of hydrocarbon are steadily declining; however, the oil and gas industry has been successful in finding unconventional hydrocarbons, such as heavy oil and shale gas. There are distinct challenges in producing and processing the hydrocarbons from unconventional sources into usable end products. Reducing the footprint during the production of oil, refined products, and gas will benefit the industry by reducing the overall cost and improving the health, safety, and environmental impact.
In-Situ Reflex (ISR) is a novel solvent-based process that utilizes resistive electric heaters to vaporize solvent and recycle mobilized water downhole. ISR promises a significant reduction in greenhouse gases emissions through the elimination of steam generation and water handling facilities at the surface as well as effectively vaporizes the injected fluid along a wellbore. However, the economic viability of this process is highly dependent on the in-situ refluxing of the solvent which requires an in-depth understanding of the process and associated challenges numerically and analytically. In modeling the SAGD process, optimal operating conditions rely on a relatively constant temperature profile across the major portion of a steam chamber that leads to an excessive energy input requirement. However, ISR optimal operating conditions tend to exhibit different temperature profiles as a result of changing thermal recovery to a solvent diluting mechanism. As such, employing a SAGD analytical model results in misunderstanding the ISR fundamental thermodynamics and hindering further optimization of the process.
This paper is the first time that an unsteady-state semi-analytical model has been developed for predicting ISR performance and shared publicly. The developed model has been validated using numerical simulation data and is capable of properly predicting a temperature distribution in a steam-solvent gaseous chamber in the presence of a fixed source of heat in an injector. This model includes fixed heat sources in both injectors and producers to represent the resistive heater concept, capture the reflux concept, and evaluate the contribution of refluxed solvent to reducing the solvent usage. In addition, the model helps better understand the phase behavior and the effectiveness of various solvents in further analyzing and determining the optimum downhole operating conditions and improving the overall ISR performance and its economic viability.
The proposed model brings an insight into analytical modeling of the ISR process with the aim of increasing an understanding of the heat transfer mechanism, along with identifying the advantages and limitations of using the bottom-hole resistive heater technology. This will lead to a higher predictability of successful field implementation, lower upfront capital cost, higher energy efficiency, and environmentally sustainable development.
Fouling of Produced Water Coolers has been problematic in SAGD production since the earliest pilot plants. Mostly this fouling causes inefficiencies in heat transfer from produced water to boiler feed water downstream of the inlet separation as the produced water effluent transitions to the de-oiling process. Previous studies reported or speculated that fouling is dependent upon numerous factors, for instance: inlet separation infrastructure, chemical programs for breaking emulsion, dissolved organic material, water chemistry, heat exchanger design and operation. Producers employ several approaches (for example: bake-outs, caustic cleaning, and physical cleaning) to clean the coolers but each method has a cost. This study explores further the relationship of SAGD production to the nature of the deposited material and approaches that have been taken to alleviate or prevent the problem. Anti-foulants can help prolong produced water cooler run times as long as the cause of the fouling is properly identified. A case study of the use of an anti-foulant at a SAGD facilities in Alberta is discussed where runtimes of the coolers have been extended from days to weeks or longer.
Multiple types and sources of water streams are encountered in oil and gas operations; the two primary ones are produced and surface water. Produced water is the brine that comes from the oil reservoir with the produced fluids; surface water encompasses fresh (river or lake) and saline (seawater) sources. Water sources are treated for disposal, injection as a liquid, or injection as steam with three types of facilities. Produced water is treated in offshore operations for overboard disposal or injection into a disposal well, but when onshore, it is treated for surface disposal, liquid injection, or steam injection. In all instances, the produced water must be cleaned of dispersed and dissolved oil and solids to a level suitable for environmental, reservoir, or steam-generation purposes. Surface water is treated offshore for liquid injection and onshore for liquid- or steam-injection purposes. In all instances, the surface water must be cleaned of dispersed and dissolved solids to a level suitable for reservoir or steam-generation purposes. In oil-producing operations, it is often desirable to inject water or steam into the formation to improve oil recovery. Water injection for this purpose is called a waterflood; when properly implemented, it will maintain reservoir pressure and significantly improve the oil recovery vs. primary production. Steam injection, known as a steamflood, will reduce the viscosity of oil and further enhance the oil recovery. See the chapter on Steam Injection in the Reservoir Engineering and Petrophysics volume of this Handbook. In offshore areas, governing regulations specify the maximum hydrocarbon and solids content in the water allowed in overboard discharges. Some studies have estimated that during the life of a well, 4 to 5 bbl of water are produced for every barrel of oil, making this fluid the largest volume of produced product in the oil and gas industry. This chapter discusses the equipment and design criteria used in common water-treatment systems for disposal or injection. In addition to the removal of dispersed or dissolved hydrocarbons and solids, the water-treatment engineer may be concerned with chemical treatment, material selection, and solids disposal, which are also covered. Produced water typically enters the water-treatment system from a two- or three-phase separator, free-water knockout, gun barrel, heater treater, or other primary-separation-unit process. This water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. Because the water flows from this equipment through dump valves, control valves, chokes, or pumps, the oil-particle diameters will be very small ( 100 μm). Treatment equipment to remove dispersed oil from water relies on one or more of the following principles: gravity separation (often with the addition of coalescing devices), gas flotation, cyclonic separation, filtration, and centrifuge separation.
Abstract Thermal Enhanced Oil Recovery (EOR), is considered the most applied EOR method, which contributes to around 66% of the global EOR. Steam Injection is normally employed on the reservoir to reduce the viscosity of heavy oil and enhancing its mobility, at high temperatures. One of the common issues arising with continuous steam injection, is reservoir heating, causing produced fluid temperature to increase, exceeding the temperature limitations of the downstream facilities. The objective of this study is to develop and provide an optimum surface cooling facility to minimize the impact of production and avoid the need for major modifications to the facility. The methodology used involve; surface process simulation using UNISIM simulator, subsurface dynamic heat modelling using CMG Stars software, materials selection, economical and costing studies. The parameters used were; existing and future well counts, individual wells gross production rates, and maximum expected produced fluid temperatures. Different solutions have been considered such as water dilution, super grade materials, Mechanical Refrigeration, Wet Surface Air Coolers, Draft Air Coolers and Heat Recovery Exchangers. The selected options have been evaluated based on technical, economical, environmental and operability criterions. Dilution with water and super graded material options were discarded, due to lack of external water supply, and significant life cycle cost respectively. All the Heat Exchanger options were also discarded due to the inability to meet cooling mediums specification, as well as the presence of economical and operational difficulties. The optimum selected technology is to provide Air Coolers at the individual Wellheads, although this solution is theoretically and economically convincing, there are some operational and maintenance challenges to overcome considering the remote locations of the steam injection wells. However, some parameters such as cost, simplified technology, maintainability, availability, will play a key role in demining the optimum technology. Unlike most published studies, the outcome of this study has been validated with existing field data (operational learnings), as well as being the first of its kind to implement, benchmarking with other major oil and gas producers, also saving significant capital costs by 69%.
This 1-day course is an introduction to thermodynamics and pressure-volume-temperature (PVT) and tuning parameters to fit laboratory data. Different analytical models for oil rate predictions such as Butler-Mokrys (1989) and Dunn-Nenniger-Rajan (1989) models will be discussed. Introduction to thermodynamics and pressure-volume-temperature (PVT): basic law such as: Clausius-Clapeyron Equation, Dalton's law, Henry's Law and Raoult’s law are explained and practical examples such as temperature reduction in chamber due to NCG injection, and temperature reduction at Azeotropic point in ES-SAGD process will be solved numerically. Pure Solvent Modelling: processes such as VAPEX and Nsolv will be explained, and different theories explaining the pure solvent oil rates such as Butler-Mokrys (1989) and Dunn-Nenniger-Rajan (1989) models will be explained and compared to physical models. Concepts such as onset of asphaltene precipitation will be discussed.