Sand production is a major operational and economical concern in the oil industry due to the potential risk of well failure, limited productivity, erosion of facilities, and increased operating expense. Experimental studies play an important role in understanding the behavior of sand production under different conditions. However, the existing traditional sand production experiments such as thick-walled, cylinder approach or perforation collapse test are only able to predict the onset of sanding and cannot be used to analyze sand production performance over time. In this work, preliminary empirical sanding prediction was performed based on well log data and the formation mechanical properties. The steady-state core flooding tests and core swelling tests were applied to simulate and investigate how the volumetric sand production changes with different flow rates, water saturations and the salinity of injected water. The cores and crude oil samples from an unconsolidated sandstone reservoir in China were used in the tests. The sand flow rate, accumulative sand volume and relative permeability were measured during the sand production process.
The experimental results indicated that the sand production rose at the beginning and declined with the increase of flow rate. During the early water-free production stage, the skeleton sand was not destroyed under realistic reservoir/well flow conditions so that the oil production with sanding was preferred. However, as water saturations increased from 20% to 80%, the permeability decreased by 80% accompanied by dramatic increase in sand production. This is due to the high content of Kaolinite, Illite and Montmorillonite with weak cement in the core which swells significantly and blocks the porosity once it is subjected to the water influx. Therefore, sand control should be considered when water saturation is over 20%. The change of sand production rate demonstrated that both the transient and continuous sand production could be involved in this reservoir. In addition, it is expected that the lower salinity of injected water aggravates the sand production.
Solvent-based processes have demonstrated a significant potential to enhance heavy oil recovery. However, their applicability needs to be investigated for different solvents and operating conditions. In this study, a comprehensive experimental and reservoir simulation analysis was conducted on the feasibility of solvent-based, huff-n-puff method to enhance heavy oil recovery. Carbon dioxide (CO2), methane (CH4), propane (C3H8), and butane (C4H10) were tested under different operating conditions. A physical model with a1800-md permeability and 24% porosity Berea core mounted in a high-pressure core holder was designed. For all tests, the core was saturated with a Saskatchewan heavy oil with viscosity of 1423 mPa·s at 22 °C. Fourteen huff-n-puff experiments were conducted. The effect of operating pressure, soaking time, and solvent composition were investigated. According to the results, for all types of solvent the produced oil at elevated pressure was lighter (in terms of density and viscosity) and the recovery factor was higher. The highest recovery of 71% was obtained by injecting pure CO2 at near-supercritical conditions (7239 kPa at 28 °C), while pure CH4 at the highest operating pressure of 6895 kPa was 50%. Also, adding 19% hydrocarbon solvent to pure CO2 increased the recovery factor by 10% at aoperating pressure (e.g., 2317kPa). The governing mechanisms that contributed to the production were recognized to be solution gas drive, viscosity reduction, extraction of lighter components, formation of foamy oil, and to a lesser degree, the diffusion process. The oil viscosity was reduced to 62 mPa·s by injecting CO2 at 7239 kPa. The highest incremental recovery for CO2-based solvents and CH4 occurred at the 2nd and 3rd cycle, respectively. Longer soaking time improved the incremental recovery of the first cycles, though the final recovery did not noticeably change. The result of history matching with the simulated model was quite reasonable with maximum 10% discrepancy between recovery factors of these two approaches.
Among several non-thermal oil recovery methods, solvent-based processes such as vapor extraction (VAPEX) and cyclic solvent injection have demonstrated substantial potential in enhancing heavy oil recovery. The solvent can be carbon dioxide (CO2), flue gas, and light hydrocarbon gases such as, natural gas, methane (CH4), ethane (C2H6), propane (C3H8), and butane (C4H10). The solvents dissolve into the heavy oil via molecular diffusion and convective dispersion processes which reduce the oil?s viscosity. Moreover, oil swelling occurs due to solvent dissolution, which makes the residual oil more mobile and increases connected oil saturation which improves the relative permeability of oil (Grogan and Pinczewski, 1987; Farouq Ali, 2003; Yazdani and Maini, 2004; Tharanivasan et al., 2006; Yang and Gu, 2006). Recently, huff-n-puff process (cyclic solvent injection) has received a great deal of attention because it is a fairly easy process to implement and considered to be very cost effective (Liu et al., 2005). It is a single-well, enhanced oil recovery (EOR) method which was initially considered to be an alternative to cyclic steam injection for heavy oil. It is performed by injecting gas into a well (huff cycle), followed by a shut-in time to allow for solvent interaction with the formation oil, and then the well is returned to production after a soaking time (puff cycle).
There is an abundance of literature available in regards to the application of the huff-n-puff method in light oil reservoirs. However, only a few papers have been published with respect to cyclic stimulation techniques on heavy oil reservoirs (Sayegh and Maini, 1984; Palmer et al., 1986; Monger and Coma, 1988; Simpson, 1988; Brock and Bryan, 1989; Haskin and Alston, 1989; Miller, 1990; Thomas and Monger-McClure, 1991; Shayegi, 1996; Mohammed-Singh et al., 2006; Torabi and Asghari, 2010, Qazvini Firouz, 2011; Torabi et al., 2012).
Different enhanced oil recovery (EOR) techniques for heavy oil reservoirs were reviewed for their ranges of applicability using available reports and publications. EOR screening criteria found in the literature are reprinted and provided. After
reviewing more than 100 papers on the subject, it is apparent that there is a definitive knowledge gap on the effective sequence of EOR recovery strategies. While there are numerous studies on the application of heavy oil recovery techniques, there is a lack of comparison and categorization of the results.
For Canadian reservoirs, the first recovery method that is implemented first is either waterflooding, cold production or in some cases steamflooding. Chemical flooding and other emerging technologies are mostly coupled with these methods. In most reports, conversion of producers to injectors and introducing line drive and edge drive will improve the waterflooding performance. However, coupling waterflooding with horizontal wells, the addition of water mobility control agents and steam stimulation did not improve the waterflooding performance in some cases. In the case of fractured limestone reservoirs, it seems that immiscible gas injection is a suitable EOR method to implement, but because of the reservoir complexity, a clear understanding of the recovery mechanism and reservoir geology is needed. In-situ combustion and steamflooding are among the most efficient heavy oil recovery methods with a large range of applicability, and next to waterflooding, can become the most widely used heavy oil recovery method. Fireflooding methods can be more profitable if they are coupled with simultaneous or intermittent water injection with air.
The results obtained from this paper not only will help the petroleum industry to apply each technique to the right candidate fields, but also it will prevent researchers from duplicating unsuccessful research projects.
Among several oil recovery techniques, hot waterflooding through thermal displacement processes could potentially increase oil recovery by decreasing oil viscosity, thus decreasing the mobility ratio at a relatively low cost compared to other thermal methods such as SAGD or in-situ combustion. These methods can also be applied in specific in-situ conditions such as formation sensitivity to fresh water. This paper examines the performance and feasibility of hot waterflooding and compares the performance with a conventional recovery scheme of a heavy oil reservoir with an oil gravity of 10.6 °API and viscosity of 13,400 mPa·s (at 22 °C) from the Lloydminster area (Canada); the approach includes numerical thermal simulation and economical analysis of each process. First, the performance of a hot waterflood on a generic model consisting of a 5-spot injection pattern was investigated. Then four field designs were recognized from several previously analyzed patterns. The effect of well spacing, horizontal well configuration,injection parameters, as well as the impact of incremental temperature adjustment of waterflood on heavy oil recovery were studied. More than 220 models were built on the final patterns and the most economic configuration was found to have four horizontal producers and four horizontal injectors with a well spacing of 67 m. This arrangement resulted in a recovery factor of more than 30 % of the oil originally in place (OOIP). The most economic injection rate was determined to be 400 m3/day of water at optimum injection temperature of 80 °C. It was also observed that by increasing the temperature of the injected water, the oil viscosity could be reduced to less than 100 mPa·s. This improved the oil recovery and production rate, delayed injection breakthrough, and reduced water cut. From the results, the highest injection temperature of 100 °C could be recommended; however, the incremental oil versus the amount of heat and facilities required would not be justifiable from an economic point of view.
CO2 capture and sequestration is inevitable. The concentration of the CO2 in the atmosphere is increasing continuously which will cause global warming among other consequences. Among storage options, the underground storage in depleted oil and gas reservoirs and unminable coals are considered the most economical storage options. On the other hand, natural gas consumption, which is considered to be a clean fuel, has increased significantly during the past years. Therefore seeking for new unconventional energy resources, especially gas seems to be inevitable. This goal is followed not only because of economical benefits but also because of environmental issues we are encountering these days.
The purpose of this study is to develop an Artificial Neural network (ANN) tool to predict the important performance indicators such as methane recovered and CO2 injected, which are critical in CO2 storage projects in coal seams. We have combined the simulation method with artificial intelligence tools to predict the complex behavior of coal bed methane (CBM) reservoirs.
In the first step a simulation is done using CMG software. A dual porosity model, which accounts for the optimum conditions during CO2 sequestration and consequently the optimum methane recovery from coal bed reservoirs was developed. Then the data extracted from the simulated CBM reservoir was employed to train the ANN model. Different parameters related to the coal seam such as porosity, permeability, initial pressure, thickness, temperature and initial water saturation are considered as the input for the network. The outputs are the CO2 injected and the recovered methane, which show the performance of the
CO2 injection project. The Back-Propagation learning algorithm was used and different transfer functions and numbers of hidden layers were tried to find the best model with the least error. The tested neural network predictions were plotted versus the real data available and also different error analyses were carried out to prove the accuracy of the model. The R-Squared for the predicted values for the CO2 injected and the recovered methane were 0.92 and 0.94; the average percent arithmetic deviations were 4.8% and 4.5% respectively.
Geological storage of carbon dioxide has been recognized as one of the most effective options for mitigation of industrial emissions. Deep saline formations, otherwise called saline aquifers, are among the potential sequestration targets. To enhance the confidence regarding some of the key issues, such as site selection, planning, injection itself and long term monitoring of sequestration site, management of uncertainties is an essential step.
This paper consists of two main parts. In the first part, CO2 storage in Mt. Simon sandstone in Ohio State, USA, is modeled using two compositional simulators - TOUGH2-ECO2N and CMG-GEM, which results provide an initial assessment for storage capacity of this site and discuss possible safety issues. In the second part, objective is reached using combination of experimental design and response surface methodology. Experimental Design (DOE) is an unbiased, rapid approach for obtaining probabilistic results. The purpose of Response Surface Methodology (RSM) is to fit simulation results to a response surface using analytical or numerical functions. In this study, DOE and RS methodologies were jointly applied to investigate the effect of uncertainties of key saline aquifer parameters on long-term CO2 storage in the form of solubility trapping and on the total storage capacity. The selected parameters in this study are: absolute permeability, global porosity, end point saturations, irreducible liquid saturation, temperature, aqueous phase salinity, vertical to horizontal permeability ratio, diffusion coefficient of CO2 in brine and relative depth of perforation interval.
Mt. Simon is expected to be a safe, secure CO2 storage formation within selected site due to several factors such as regionally extensive caprock and seals including Eau Claire Formation (Cambrian) and Knox Dolomite (Cambo-Ordovician) and high CO2 storage capacity with favorable reservoir properties. This conclusion is supported by the results of modeling performed using both TOUGH2 and CMG GEM simulators. It is expected that 15-17 Mt of CO2 could be safely injected into Mt. Simon formation during 25 years via one vertical injection well while staying below fracturing pressure. It was demonstrated that combination of DOE and RSM techniques could be successfully applied for research into CO2 sequestration.