|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.
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.
During the circulation (startup) phase of steam-assisted gravity drainage (SAGD), high-quality steam injected through the injector and producer wells heats the reservoir between the wells. The viscosity is thus lowered, making fluids mobile at approximately 50 to 100 C and creating interwell fluid communication. This paper uses a simulation model to evaluate and compare the thermal efficiency of five different completion design cases during the SAGD circulation phase in the Lloydminster formation in the Lindbergh area in Alberta, Canada. The results show that completion-design configuration affects the heat transfer and thermal efficiency of the circulation process. The SAGD process is the most commonly used thermal method of in-situ recovery for extracting heavy oil and bitumen resources in Alberta and can yield recovery factors of greater than 60%.
This paper describes both design and economic considerations that lead to the selection of vacuum-insulated tubing (VIT) or vacuum-insulated casing (VIC) for the completion of thermal wells. The results shared in this paper are some of the parameters considered during thermal-well design: temperature on the casing and the tubing, and heat loss. Knowing these parameters, well integrity can be studied and the overall efficiency of the process estimated. The most common thermal enhanced-recovery methods are cyclic steam stimulation, steamflooding, and steam-assisted gravity drainage, which is widely used in Canada. The role of these thermal-recovery methods is to convey heat into the reservoir, mainly by convection.
Summary In this paper we present a large-scale experimental study of the compositional effect on produced bitumen properties in steam-assisted gravity drainage (SAGD). The SAGD experiment used a sandpack in the cylindrical pressure vessel that was 1.22 m in length and 0.425 m in internal diameter. The pore volume of the sandpack was 58 L, and the porosity and permeability were 0.33 and 5.5 darcy, respectively. The sandpack was initially saturated with 93% bitumen and 7% deionized water. The SAGD experiment after preheating was operated mostly at a steam injection rate of 35 cm/min (cold-water equivalent) at 3,600 kPa (244°C). The produced fluids (gas, oil, and water) were analyzed; for example, 10 oil samples were analyzed in terms of carbon number distribution (CND), the asphaltene content, density, and viscosity to investigate the compositional change of the produced bitumen. After the experiment, the sandpack was excavated, and samples were taken for analysis of solid, water, oil, asphaltene, and sulfur contents. Experimental data (e.g., propagation of a steam chamber and production of oil and water) were history matched using a numerical reservoir simulator. The produced bitumen was lighter and contained 1- to 5-wt% less asphaltenes than the original bitumen. Also, the remaining oil inside the steam chamber contained 6-wt% more asphaltenes. As a result, the produced bitumen was 1- to 6-kg/m less dense than the original bitumen. This is an increase in API gravity from the original 7.9° to 8.6°. In the actual operations, bitumen is diluted with condensate to decrease the oil viscosity for pipeline shipping. This decrease in bitumen density corresponds to a decrease of the diluent cost by 5 to 10%. The produced bitumen became less dense with increasing steam-chambervolume. Results were history matched with a simulation model that considers capillary pressures to properly model the mixed flow regimes of oil/water countercurrent and cocurrent flow with an expanding steam chamber. The history-matched simulation indicated that the progressively decreasing density of the produced bitumen can be attributed to the vaporization of the relatively volatile components in the remaining oil and condensation of those components near the chamber edge.
Abstract Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. It is believed that the heavy oil resource volume is in the 50 to 70 billion bbl range which makes it a world class resource. This work briefly summarizes the reservoir properties of these formations and provides an overview of the primary CHOPS recovery mechanism which only recovers on average 8% of the original oil in place. Therefore, the target for Enhanced Oil Recovery (EOR) processes are substantial. For instance, if an additional 2% (25% of the primary) oil can be recovered, this means an additional 1 to 1.5 billion bbls of oil production which can sustain the oil industry for many years in this area providing jobs and contributing significantly to government royalties. A number of EOR processes are reviewed in this study from the conventional water flooding technologies to more state of the art processes such as Horizontal well Hot Oil Circulation. It is shown that part of the resource with viscosities less than 5,000 to 10,000 cp can be a target for water/polymer flooding. While steam injection in heavy oil reservoirs can be very successful, more than 95% of the resource in Lloydminster is less than 10 m thick and, thus, is not amenable to steam injection due to excessive heat losses to the surrounding formations. However, EOR processes involving mild heating or no heating can be feasible in these thinner formations. A number of mild heating technologies are discussed. Two of these technologies have been piloted in the field: Hot Water Vapour Process and Horizontal Well Hot Oil Circulation. Field results from these pilots are presented and discussed in this paper. It appears that these technologies can offer significant commercial potential in post-CHOPS reservoirs as well as in areas where CHOPS or horizontal primary production wells have not been successful.
Abstract Oil sand reservoirs play an important role in the economy of Canada due to their significant recoverable reserves. Due to the high viscosity of the oil in these reservoirs, conventional methods cannot be used for production. The steam-assisted gravity drainage (SAGD) method is an efficient way of producing oil from these reservoirs. Predicting oil production and steam injection rates is required for planning and managing a SAGD operation. This can be done by simulating the fluid flow with flow simulation codes, but this is very time consuming. The run time for a 3D heterogeneous model with one well pair can exceed 2 days. In this paper, a SAGD approximate simulator for predicting SAGD performance with 3D heterogeneous models of geologic properties is developed. This approximate simulator can handle different types of operating strategies. The approach is an approximate solution using a semi analytical model based on relevant theories including Butler's SAGD theory. The approximate simulator or proxy is much faster than the full simulator and it gives accurate estimated oil production and steam injection rates at different time steps. Theoretical and numerical research has been undertaken to develop the proxy, implement it in fast code, demonstrate the accuracy of prediction and apply to realistic examples. This proxy is used for other applications such as transferring uncertainty for reservoir realizations and well trajectory optimization.
In-situ combustion (ISC) is the oldest thermal-recovery technique. It has been used for more than nine decades with many economically successful projects. Nevertheless, it is regarded as a high-risk process by many primarily because of the many failures of early field tests. Most of those failures came from the application of a good process (ISC) to the wrong reservoirs or the poorest prospects. An objective of this chapter is to clarify the potential of ISC as an economically viable oil-recovery technique for a variety of reservoirs. This chapter is a summary containing a description of ISC, a discussion of laboratory screening techniques, an illustration of how to apply laboratory results to field design, a review of performance-prediction methods, a discussion of operational practices and problems, and an analysis of field results. For a more complete review, the work of Sarathi, Prats, and Burger et al. should be consulted. ISC is basically injection of an oxidizing gas (air or oxygen-enriched air) to generate heat by burning a portion of resident oil. Most of the oil is driven toward the producers by a combination of gasdrive (from the combustion gases), steam, and waterdrive. This process is also called fire flooding to describe the movement of a burning front inside the reservoir. Based on the respective directions of front propagation and air flow, the process can be forward (when the combustion front advances in the same direction as the air flow) or reverse (when the front moves against the air flow). This process has been studied extensively in laboratories and tried in the field. The idea is that it could be a useful way to produce very heavy oils with high viscosity.
Abstract The quest for cleaner sources of energy in the world today has paved way for scientists and researchers to delve into renewable energies like the geothermal energy. Researches on the enormous potential that a geothermal reservoir could posses are currently underway. However, there is limited information on the quantity and quality of geothermal reserves in Nigeria. Extraction of this geothermal heat will improve power generation and the availability of scarce electricity in Nigeria. This work is aimed at using a mathematical model to estimate the quantity of recoverable heat by first estimating the total heat in place and then the heat losses associated with heat transfer in a wellbore. In this work, we were able to ascertain the heat in place as well as recoverable geothermal heat for geothermal regions in Nigeria having a temperature-at-a depth range of 50°C – 110°C and also a higher temperature-at-a depth range of 150°C – 250°C. Heat losses were considered for pipe tubings with 1 inch, 2 inches and, 3 inches diameter. A higher recoverable of 92% was gotten when the 1 inch pipe diameter was used. 87% and 76% recoverable were also gotten when the 2 inches and 3 inches diameters were used respectively. Nigeria has the potential of generating 74Megawatts of electricity from just one geothermal reservoir which could provide electricity for villages and small towns.
For any steamflood process, no matter how efficient, the major cost is always that of generating the process steam. Whether the product of oilfield steam generators, industrial boilers, or electrical/steam cogeneration plants, steam must be delivered through a network of pipes and through pipes down a wellbore to the oil bearing formation. It is imperative that the unavoidable heat losses in this distribution system be minimized with some type of insulating system. The rate of heat loss in surface lines is usually calculated at steady-state conditions because transients disappear quickly in surface pipes. The terms in Eq. 2 are the coefficients of heat transfer for each of the layers of an insulated pipe as shown in Figure 1.