Shariat, Ali (University of Calgary) | Moore, Robert Gordon (University of Calgary) | Mehta, Sudarshan A. (University of Calgary) | Van Fraassen, Kees Cornelius (University of Calgary) | Rushing, Jay Alan (Apache Corp.)
This paper presents a comparative evaluation of gas-water interfacial tensions (IFT) measured using the pendant drop technique and computed using either the Selected Plane (SP) or the Computerized Image Processing (CIP) Methods at high-pressure/high-temperature (HP/HT) conditions. Both the SP and CIP Methods are based on solutions to the Young-Laplace equation. The SP Method, which is derived from an approximate solution originally developed by Bashforth and Adams (1883), is dependent on just two pendant droplet dimensions. Further, the solutions were generated for the air-water system at pressures and temperatures much lower than typically encountered in oil and natural gas reservoirs. However, these solutions are often extrapolated mathematically to HP/HT conditions.
Although it is relatively simple to use, the IFT computational accuracy using the SP Method is questionable since it is dependent on the precision to which the two pendant droplet dimensions are measured. However, improvements in computerized data acquisition and imaging systems have made it possible to digitize droplet shapes completely such that IFTs may be computed using the entire shape. So while the CIP Method is also an approximate solution (numerical solution which discretizes the droplet interface) to the Young-Laplace equation, it utilizes many more points on the pendant droplet and incorporates the actual fluid properties directly into the solution. Therefore, the question addressed in this study is: what is the accuracy of the SP Method for computing gas-water IFTs at HP/HT conditions?
To answer this question, we conducted a two-stage study. First, we used the pendant drop method and measured droplet dimensions for the gas-water system at pressures of 1,000 psia to 20,000 psia and temperatures of 122oF, 212oF, 300oF, and 400oF. We then compared gas-water IFTs computed using both the SP and CIP Methods. The comparative evaluation indicates the gas-water IFTs from the SP Method are generally and consistently lower than IFTs from the CIP Method. Differences between the two methods are dependent on pressure/temperature conditions, gas composition, droplet geometry and size, and the illumination when the droplet shape is photographed. However, the maximum absolute mean error for all evaluations was less than 3.5%, suggesting the SP Method is valid for computing gas-water IFTs at HP/HT conditions.
The commercial viability of the steam-assisted gravity-drainage (SAGD) process is affected negatively by several undesirable reservoir features, such as pronounced heterogeneity, low vertical permeability, thick and areally extensive shale barriers, and steam thief zones. The efficiency of SAGD projects is also affected by the presence of higher water saturation in the target zone. Although the presence of small mobile-water saturation is not considered harmful, reservoirs with high water saturation may be poorly suited for the SAGD process. Nonetheless, SAGD remains the only practical technology for in-situ extraction of oil from oil-sand reservoirs, even when mobile water is present. This raises the question of how much mobile water is prohibitive.
To investigate the effect of water saturation on SAGD performance, high-pressure physical-model experiments were carried out. Different levels of water saturations were established in the model by modifying the packing and saturating techniques. SAGD experiments were carried out by injecting superheated steam at controlled rates and producing the oil from the production well at constant pressure. The injection rate was selected to keep the pressure difference between the injector and the producer at a low level.
The oil-production behavior was analyzed to evaluate the effect of water saturation on the thermal efficiency of the process. On the basis of the results of low- (immobile) and high- (mobile) water-saturation experiments, it was observed that the oil-recovery factor dropped by 6.6% when the initial water saturation was increased from 14.7% to 31.8%.
Steam-assisted gravity drainage (SAGD) is a commercially viable recovery method for oil sands of Athabasca used where other methods have been unsuccessful. In one variation of SAGD, a small amount of a noncondensable gas is added to the injected steam to maintain pressure in the chamber while using the energy in place, reducing steam consumption and providing thermal insulation from overburden heat losses. The role of gas during steam-gas co-injection processes, in terms of its effects on chamber development, bitumen flow rates, and heat losses, is not fully understood, and therefore is the main focus of this work.
A new analytical model for gas injection in SAGD is derived, taking into account the three-phase flow of gas, oil, and water in the reservoir. The analytical theory is used to predict the fluid flow rates as well as phase mobility, relative permeability, and saturation profiles in the mobile oil region. The theoretical results are replicated by fine-grid numerical simulations. Methane was used as the noncondensable gas for the purpose of this study because it is the main solution gas in most reservoirs. It is, however, believed that the findings of this study are equally applicable to other noncondensable gases such as nitrogen, air, helium, and others. Fine-grid numerical simulations were performed to gain a visual understanding of gas distribution in a SAGD chamber and its effect on in-situ steam quality, overburden heat losses, phase saturations, and fluid-flow rates. The simulation results support the predictions of the mathematical theory.
The results of the analytical and numerical study reveal that methane co-injection with steam is in general unfavorable in a SAGD operation. The injected methane tends to accumulate at the steam condensation front, which lowers the heat transfer rate of steam to the adjacent oil, resulting in lower oil production rates and slower growth of the chamber.
Air-injection-based recovery processes are receiving increased interest because of their high recovery potentials and applicability to a wide range of reservoirs. However, most operators require a certain level of confidence in the potential recovery from these (or any) processes before committing resources, which can be achieved with the use of numerical reservoir simulation.
In a previous paper, (Gutiérrez et al. 2009) it was proposed that after successful laboratory testing, analytical calculations and semiquantitative simulation models would be used for pilot design and further optimization of the actual operation. However, the specific steps for building the field-scale-simulation models were not addressed explicitly. This paper discusses a detailed workflow that can be followed to engineer an air-injection project using thermal reservoir simulation.
The first step of the simulation study involves the selection of a kinetic model that either can be developed specifically for the reservoir in question or taken from public literature. Second, the oil would be characterized in terms of the same pseudocomponents employed by the kinetic model, and relevant pressure/volume/temperature (PVT) data would be matched to develop a fluid model for the thermal simulator. This new fluid model is used in the field-scale-simulation model to history match the production history (i.e., before air injection) of the field. Third, relevant combustion-tube tests would be history matched to validate the kinetic model and refine the thermal data that would be entered into the field-scale model. Finally, the results and knowledge gained from the combustion-tube match(es) are applied to the field-scale model with the proper upscaling of some parameters. This simulation model would aid in selecting optimum well locations and operating strategies of the pilot. It would then be refined as the actual operation progresses to enhance its predictability and allow further optimization of the project.
Technical considerations, advantages, and limitations of each step of the workflow are discussed in detail. This paper also presents workflow variations and recommendations applicable to new and already-mature air-injection projects for which simulation models are being developed.
In Situ Combustion, ISC, is a process with strong potential to compliment Steam Assisted Gravity Drainage by extending the economic life of the SAGD pattern and hence improving the ultimate recovery. Implementing In-Situ Combustion, as a follow-up process to SAGD can improve recovery from the pattern by displacing residual oil from the steam chamber and more importantly by recovering oil from the wedge zones. Theoretically the temperature and residual oil saturation within the SAGD chamber are high enough to initiate and sustain the combustion process by switching from steam to air injection; however laboratory investigations of the hybrid process have shown that the in situ combustion behavior within the steam zone has some special features which must be considered.
Injection of air into the SAGD injection well is the desired option from an economic view point, however laboratory tests showed that the combustion zone tended to be more stable when air was injected at a location higher up in the chamber. This behavior relates to the fact that the combustion reactions were primarily occurring within the vapor phase, hence gravity plays a dominant role controlling the distribution of air flux within the chamber as well as the drainage of oil and water out of the combustion zone. Laboratory tests also confirmed the importance of promoting air flux across the walls of the original steamed chamber.
In oil producing regions like the US Mid-Continent, there are a large number of mature conventional oil fields that have reached or are approaching their production limit by conventional techniques, however, current strong oil prices and security issues justify additional EOR/IOR efforts. Air injection-based techniques (fireflooding or in situ combustion) have been demonstrated to provide commercially successful recovery from medium and light oils reservoirs. While the history of air injection-based EOR is littered with the perception of failed projects, many of the failures were associated with low oil prices. In other cases, failures were due to compressor problems, or incorrect concepts of how air injection processes operate. Ineffective ignitions, failure to inject enough air, and applications in reservoirs that had no hope of success explain the trouble with many past projects.
This paper reviews some of the successful air injection projects in higher gravity oil reservoirs and discusses the elements that are critical for success. These include the ability to ignite and continuously burn a fraction of the oil at reservoir conditions, the suitability of the reservoir for a gas-injection based recovery process, the availability and suitability of pre-existing infrastructure, and a reasonable prediction of how much air should be injected and how much oil recovery could be expected. The paper also discusses possible options for taking advantage of the product gas stream.
The purpose of this paper is to arm the petroleum engineer with the relevant information and the right set of questions to ask when considering the application of air injection in a given field.
The practice of in situ combustion has traditionally been based on the concept that extinction of the process occurs when the air flux falls below the level where bond scission reactions can no longer sustain the advance of the combustion front at the temperatures required for effective mobilization of the oil. Very important economic parameters such as sweep efficiency and design parameters such as air injection rate and spacing between the injection and the production wells are directly dependent on the level of the air flux at exhaustion. The most common method for estimating the minimum air flux is based on the work of Nelson and McNeil who proposed that for a radial burn the minimum combustion front velocity is 0.038 m per day (0.125 feet per day). Based on this minimum velocity and assuming air requirements falling in the 100 to 350 sm3/m3 range, the minimum air flux would be expected to fall in the range from 0.1 to 0.6 sm3/m2·h. This range of minimum air flux has a significant level of uncertainty in terms of both combustion front velocity and air requirement parameter. In an attempt to address this uncertainty, a conical combustion cell was constructed with the goal of directly determining the minimum flux for specific oils under conditions which are representative of a field scale operation. To date, tests involving core from a typical Athabasca Oil Sands reservoir have operated at air fluxes (based on the air injection rate and area at the downstream front location) of under 1 sm3/m2·h. This paper describes the nature of the combustion zone under this low air flux condition and it provides important information on the nature of reactions and the physics of the process which must be considered when attempting to predict combustion front exhaustion using a numerical simulator.
Shariat, Ali (U. of Calgary) | Moore, Robert Gordon (U. of Calgary) | Mehta, Sudarshan A. (University of Calgary) | Van Fraassen, Kees Cornelius (U. of Calgary) | Newsham, Kent Edward (Apache Corp.) | Rushing, Jay Alan (Apache Corp.)
Disposal of carbon dioxide (CO2) in permeable, porous subsurface rock formations (i.e., geological sequestration) has been identified as a viable option for reducing greenhouse gas emissions into the Earth's atmosphere. Potential subsurface systems considered for geological sequestration include depleted oil and gas reservoirs, coalbed methane and shale gas reservoirs, and deep aquifers. Though each of these disposal systems has their advantages, deep aquifers (mostly filled with non-potable or brackish waters) have the greatest potential for large CO2 sequestration programs primarily because of their relative abundance in most sedimentary basins and their large effective capacities.
Successful selection of potential of CO2 deep aquifer sequestration sites, however, requires an understanding of all physical and chemical trapping mechanisms by which CO2 may be retained. Principle retention mechanisms in aquifers include structural/stratigraphic (CO2 immobilization or trapping below an impermeable confining layer), residual fluid (trapped as immobile fluid phase in aquifer pore spaces), solubility (immobilized as fluid phase dissolved in in-situ water), mineral
(immobilized as solid carbonate minerals formed from reaction with aquifer rock), and hydrodynamic (CO2 dissolved in slow-moving water) trapping. While all of these mechanisms contribute to CO2 sequestration, the structural/stratigraphic and residual fluid mechanisms have the largest and most immediate impact on trapping or retaining CO2 in aquifers.
The effectiveness of both structural/stratigraphic and residual fluid trapping mechanisms is dependent on the capillary pressure characteristics of the aquifer seal and formation, respectively. And, the capillary pressure characteristics are strong functions of the interfacial tension (IFT) properties of the carbon dioxide-water (CO2-H2O) system. Unfortunately, there is a general lack of understanding of the CO2-H2O IFTs, particularly at high-pressure/high-temperature (HP/HT) conditions typical of many potential deep aquifer sites. The vast majority of published CO2-H2O IFT data were obtained at pressures less than 10,000 psia and temperature less than about 250oF. Additionally, there are often inconsistencies among the existing data published in the literature, thereby making it difficult to create predictive models.
To address these inadequacies in the existing technical literature data base, we conducted laboratory studies to measure CO2- H2O IFTs using a pendant drop method at pressures between 1,000 and 18,000 psia and temperatures up to 400 oF. Rather than relying on correlations or previously published data, we also measured water-vapor-saturated CO2 as well as CO2- saturated water densities directly at each pressure and temperature. General observations from our laboratory study include:
• CO2-H2O IFTs demonstrated a strong dependence on temperature (decreasing with increasing temperature);
• For a given temperature, CO2-H2O IFTs were relatively insensitive to pressure with values between 10 to 23 dynes/cm; values never fell below 10 dynes/cm for all temperatures up to 400oF;
• Full miscibility between CO2 and H2O never occurred at any pressure and temperature evaluated in the study;
• CO2-saturated water densities showed a strong dependence on pressure and temperature, while water-vapor-saturated CO2 densities showed little change from the CO2 density with no vapor content.