The production of oil and gas, and the various processes required to make these products suitable for transportation, is an energy-intensive operation. Provision of electrical power, process heat and mechanical power usually requires the combustion of fossil fuels with resultant CO2 emissions to atmosphere. Flaring of hydrocarbon-based waste gases also creates additional CO2 emissions at production facilities.
In many instances, taking a more global approach to facility design can greatly improve energy efficiency and hence reduce CO2 emissions. Employing Cogeneration technologies to generate both power and heat, or to recover waste heat from processes to generate electricity, can both reduce site emissions and help ensure security of electricity supply. It may also be possible to use waste-gas streams as a fuel for a Cogeneration plant, reducing the amount of premium fuel required and simultaneously eliminating gas flaring, or to sell any surplus electricity generated, turning a waste into a potential revenue stream.
There are numerous ways to configure a Cogeneration plant, depending on the ratio between the power and the heat required by the facility, the available fuels or waste heat sources, the form of process heat required and the actual electrical power demand. This paper will examine some of the different well-proven potential Cogeneration configurations based on Gas Turbines, Steam Turbines and Gas Engines, as well as looking at how the newer technologies of Organic Rankine Cycles and Concentrated Solar Power can be employed in Cogeneration applications.
With potential overall fuel efficiencies in excess of 75%, Cogeneration can offer significant CO2 reduction over separate generation of power and heat, from either an on-site or off-site facility, or imported power from a remote third-party power plant. The paper will discuss potential CO2 savings for certain common plant configurations and fuels.
For the last two decades major oil companies in Canada have been paying much attention to heavy oil which is an alternative unconventional reservoir (Canada and Venezuela have some of the largest bitumen deposits in the world). Main reasons for development could be the high price of oil, and improved technology to extract heavy oil, with a high recovery factor (up to 60% of the oil in place). Injecting steam is the most distinctive technique of heating up the formation rock and assisting in oil flow. Controlling steam injection and its distribution, and achieving economical recovery in an effective manner, has been a continuous mind-boggling issue for the heavy oil producers, and has been a great challenge.
High-temperature water and oil swellable packers have been developed to aid, and optimize, cyclic steam stimulation and Steam Assisted Gravity Drainage (SAGD) applications in heavy oil reservoirs. Simplicity is one of the great advantages of the swellable packers, which provide an ease of operation. The packer allows uniform or selective placement of steam along the entire length of horizontal section, and is designed to handle high temperature 575°F (302°C), and more than adequate differential pressures, associated with steam injection. Screens or slotted liners are run in hole to allow steam to be pumped in between the well pairs. Steam breakthrough, or diversion, has been experienced in numerous wells due to sand erosion and/or plugging of the slotted liners, which creates problems for continuous production. Swellable packers can be installed in conjunction with screens or slotted liner in order to distribute steam and provide zonal isolation. In the event of steam breakthrough, swellable packers can be deployed to isolate the affected zone(s). This intervention technique will assist in efficient continued production, elimination of sand production and steam breakthrough.
The technique of steam injection has been improving over the years, but still has room for refining of the processes. Some older wells have encountered with issues of steam channeling through the cemented casing & breaking out at the surface; which has been seen to create a threat to the environment. A horizontal well completed with slotted liner, or recently with specially designed type of screens, provides a far better method than perforated casing for injecting steam into the formation.
This paper presents solutions for SAGD wells with a unique technique for resolving wasted steam injection at the toe section of the well, and repair of steam breakthrough in production legs. Every operator is coming across new learning experience almost every day, although most of this information is proprietary, we are proposing a different solution path to overcome some of these issues.
Placement and timing of steam injectors is critical for optimal performance of the Steamflood at Round Mountain Oilfield; a dipping, highly permeable reservoir with a very strong water drive. Diligent reservoir management to conserve steam is a necessity in any steamflood, especially if a strong water drive is present.
In the Round Mountain Field, with primary water cuts of 99.5%, steam injection was instituted at an up structure position (Row 0) in 1998. Water was produced with high volume lift electric submersible pumps (ESPs) in wells two rows down structure (Rows 1 & 2) from the injectors. These down structure wells intercepted encroaching aquifer and reduced reservoir pressure; imperative for steam front expansion. As the steam front advanced, wells that were formerly water intercept wells (Row 1) began to heat up and produce oil at low water cuts. These wells were placed on beam units, and new water intercept wells (Row 3) were drilled one row further down structure.
Heat losses to Overburden, Underburden, and by hot fluid withdrawal over time decreased the rate of steam front expansion. This paper discusses the "Steam Injector Relocation?? strategy devised to specifically tackle the problem. By this strategy, once the down structure row of producers (Rows 2 & 3) experience slower steam front expansion and the up structure wells decline in production, the up structure row (Row 1) is converted to injection. This leads to a more favorable expansion of steam front, significant improvement of production, and lower heat losses. This process has been repeated four times, and at present the steam front is approaching the original oil water contact in some areas of the field.
The lessons learned from this project emphasize the need for careful and continuous surveillance of production, pressure, flow line temperatures, and heat losses in order to move both injectors and producers at critical times.
Integrated solar thermal steam generation and heavy-oil recovery projects have garnered interest because of their ability to decrease the variability of steam generation costs arising from fluctuations in natural gas prices as well as life-cycle carbon dioxide emissions. The viability of a solar thermal steam generation system (with and without natural gas back-up) for thermal enhanced oil recovery (TEOR) in heavy-oil sands was evaluated in this study. Using the San Joaquin Valley as a case study, the effectiveness of solar TEOR was quantified through reservoir simulation, economic analysis, and life-cycle assessment of oil-recovery operations. Reservoir simulation runs with continuous but variable rate steam injection were compared with a base-case Tulare Sand steamflood project. Reservoir properties and well geometries were drawn from the literature. For equivalent average injection rates, comparable breakthrough times and recovery factors of 65% of the original oil in place were predicted, in agreement with simulations in the literature. Daily cyclic fluctuations in steam injection rate do
not greatly impact recovery for this reservoir setting. Oil production rates for a system without natural gas back-up to moderate injection rates do, however, show seasonal variation. Economic viability was established using a discounted cash flow model incorporating historical prices and injection/production volumes from the Kern River oil field. This model assumes that present day steam generation technologies could be implemented fully at TEOR startup for Kern River in 1980,
for the sake of comparison against conventional steam generators and cogenerators. All natural gas cogeneration and 100% solar fraction scenarios had the largest and nearly equal net present values (NPV) of $12.54 B and $12.55 B, respectively, with production data from 1984 to 2011. Solar fraction refers to the steam provided by solar steam generation. Given its large capital cost, the 100% solar case shows the greatest sensitivity to discount rate and no sensitivity to natural gas price because it is independent of natural gas. Because there are very little emissions associated with day-to-day operations from the solar thermal system, life-cycle emissions for the solar thermal system are significantly lower than conventional systems even when the embodied energy of the structure is considered. Here, we estimate that less than 1 g of CO2/MJ of refined gasoline results from the TEOR stage of production if solar energy provides all steam. By this assessment, solar thermal based or supplemented steam generation systems for TEOR appear to be a preferred alternative, or supplement, to fully conventional systems using natural gas (or higher carbon content fuels), especially in areas with large solar insolation.
Kembaiyan, Kumar (GE Water & Process Technologies) | Miller, William D. (GE Water & Process Technologies) | Kluck, Robin W. (GE Water & Process Technologie) | Collins, Stephen M. (GE Water & Process Technologie) | Leach, Mathew (GE Water & Process Technologie) | Phillips, Mark (United Refining Company)
Zhong, Liguo (Northeast Petroleum University) | Zhang, Shoujun (China National Petroleum Corporation) | Wu, Fei (China National Petroleum Corporation) | Lang, Baoshan (China National Petroleum Corporation) | Liu, Heng (Liaohe Oilfield Company)
Horizontal wells are widely drilled to produce heavy oil because of their large reservoir contact. For example, there are more than 500 horizontal wells operated in cyclic-steam-stimulation (CSS) or steam-assisted gravity-drainage (SAGD) processes in Liaohe oil field. The length of these horizontal wells usually ranges from 100 to 500 m. But it is challenging to recover oil along a horizontal well proportionally by conventional steam-injection processes because of poor steam conformance along the horizontal well, which is derived from reservoir heterogeneity, large horizontal-well length, and steam properties. Field investigation shows that only half of the reservoir along the horizontal well is well steamed and recovered, and that the average ratio of oil production to steam injection (OSR) is less than 0.28. In this paper, a separated-zones steam-injection process is introduced to improve steam conformance along the horizontal well; in this process, in which packers, outlets, pressure-sensitive valves, and ball sealers are involved, steam could be injected to the selected zone, separated dual zones in sequence or at one time, or separated multizones simultaneously. In order to investigate steam conformance along the horizontal well and feasibility of separated-zones steam injection, primary laboratory experiments with a sand-packaged model, numerical simulation, and field testing are carried out. These show that steam injected to separated zones could be regulated with sealed packer(s) based on the principles of steam crossflow and superimposing the effect near the packer; therefore, steam conformance along the horizontal well could be considerably improved by separated-zones steam injection. Field testing of 76 wells stimulated by separated-zones steam injection shows that up to 70% of the reservoir along the horizontal well is well steamed on average, and steam conformance is significantly improved.
According to the US Geological Survey, the world has over 430 billion barrels of technically recoverable heavy oil. There are several hurdles that hinder the large scale development of heavy oil. These include; high energy consumption for thermal recovery; poor recovery in cold production; environmental issues, transportation issues, refineries upgrade and high investment costs.
Over the past decade, multiphase pumping has emerged as a best practice in the many of the oil producing areas around the world. It has been used successfully in pumping both light and heavy crude oil. Multiphase pumping offers many advantages in heavy oil production. Multiphase pumps provide a single system for gas, steam and produced fluids. They reduce the back pressure or the well head flowing pressure, which results in higher production. Multiphase pumps have been used to recover annulus gas in cold oil production. Thermal vent energy is transferred to the produced fluids and thus reduces the overall energy consumption.
This paper presents an overview of the application of multiphase pumping technology in heavy oil production.
As conventional light crude oil reserves start to decline, the strategic importance of heavy oil is increasing. There are heavy oil deposits in various parts of the world with major reserves in Canada, Venezuela, the US, Russia, China and the Middle East. According to the United States Geological Survey, the technically recoverable reserves of heavy oil in the world are estimated at 434 billion barrels and the Middle East contains 78 billion barrels of those reserves .
The definition of heavy oil varies slightly in different parts of the world. In general, "heavy oil?? refers to oil which has API gravity below 22. The table below is based on the definitions given by the US Geological Survey .
Formation integrity is a critical confinement factor in any injection process such as waste injection, CO2 capture and storage, and thermal/pressure injection in oilfields. Rock can fail in tensile, shear or in combination of complex modes. In situ stresses variation caused by injection may shear the caprock posing continued risk of containment breach. We developed an integrated approach to predict the alteration of in situ stresses and shear failure potential by combining data from sonic logs, image logs, mini-frac test data, formation pressure measurement, and rock mechanical core test data. In this approach, three-dimensional Mechanical Earth Models containing the reservoir, overburden, under-burden and side-burden were constructed. Coupled simulations were then run between dynamic reservoir model and geomechanical model to quantify stresses change induced by injection. The resulted formation shear and surface heave will then be calculated regarding the location and timing of occurrence during the planed injection operations.
The methodology has been applied to several steam injection case studies in Northern Alberta oil sands area, Canada. Our analysis indicated that three years of steam injection would cause up to 2 MPa stresses contrast; formation shear failure was forecasted to occur earlier than formation tensile failure at a same time step; the calculated surface heave due to steam injection was around three 3 cm. The simulation results enabled the optimization of injection scheme and proactive monitoring plans to avoid catastrophic events.
It is widely understood that injection activities can induce additional stress fields that will couple with the original in situ stress field. An increased shear stress may cause serious formation shear issue, which will in turn compromise the integrity of caprock or/and casings. In Northern Alberta, Canada, caprock unintegrity is an important environmental concern in heavy oil thermal production. Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are the two most popular thermal oil recovery methods in heavy oil reservoirs where the oil in the form of bitumen is essentially immobile [Butler, 1991, Clark, 2007].
Steam injection triggers complex thermal and hydraulic processes which can dramatically alter the formation pressure and temperature leading to various changes within the reservoir as well as in the surrounding rock. As steam is injected into reservoir, the pressure and temperature in the reservoir rise. The increased temperature and pressure cause changes in in situ stresses, rock properties, porosity, permeability, etc. High temperature and injection pressure can reduce rock strength, induce fractures. This poses a continued risk of breaching the containment of caprock, which can provide pathways for bitumen and steam to flow to aquifers or to the surface causing significant risk to safety and the environment. Therefore, ensuring caprock integrity is critical in any subsurface injection process such as SAGD and CSS.
Conventionally, fracture pressure typically measured/interpreted from mini-fracturing (mini-frac) test is considered as the upper limit of the net injection pressure. However, some cases of compromising the integrity of caprock have been reported despite keeping the net injection pressure below the fracture pressure. These cases clearly indicate that designing the injection pressure scheme solely based on mini-frac test is not sufficient. Because, fracture pressure estimated from mini-frac test considers tensile failure only. Rock can fail in tensile, shear or in combination of complex modes. Consideration of shear failure in addition to tensile failure must be an essential part of caprock integrity analysis.
Coal-fired power plants need to respond to changes in electricity demand on diurnal, weekly, seasonal, and yearly time scales. The scale and frequency of these responses are forecasted to increase as levels of variable renewable energy sources become a larger part of the electricity supply. To respond to climate change concerns, it is also anticipated that the coal-fired power plants of the future will incorporate carbon capture and sequestration (CCS) technologies. Therefore, it is important to understand the dynamic response of coal-plants with CCS.
A variety of engineering studies have been published that investigate the energy penalty and design requirements for coalfired plant running at static power output and carbon capture rate of 90 percent; however, few of these studies explore the ability of the capture unit to respond to changes in load and capture rates. Noting that amine absorption is considered the most advanced near-term technological solution for carbon capture, this paper provides an analysis of the dynamics of a
MEA capture unit. This analysis enables the evaluation of the ability of coal-fired CCS power plants to provide load following support at different ramp rates and at varying levels of capture.
A dynamic kinetic model of an MEA capture plant was developed using Aspen Dynamics®. The model is used to determine the dynamic characteristics of the capture plant for load following by simulating various ramp rates of flue gas flow from the power plant to the capture unit. These results are used to determine the ability of the capture plant to control power output to the grid and the impact on performance parameters such as the capture rate and energy consumption. The results shown that the capture plant operates on similar time scales of a coal-fired power plant. The capture plant will not prohibit the ability of the coal plant to adjust output.