In-situ combustion is the oldest thermal recovery technique. It has been used for more than nine decades with many economically successful projects. In-situ combustion 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 to the wrong reservoirs or the poorest prospects. The objective of this page is to describe the potential of in-situ combustion as an economically viable oil recovery technique for a variety of reservoirs.
Perozo, Hector (Petroleos de Venezuela S.A.) | Mendoza, Arturo Jose (PDVSA Intevep) | Teixeira, Jose Gregorio (PDVSA Intevep) | Alvarez, Argenis Jesus (PDVSA Intevep) | Marquez, Jose Gregorio (Industria Nacional Compresores) | Ortega, Pedro Cesar (Intevep S.A.) | Vasquez, Pedro Angel
The In Situ Combustion Pilot Project (ISCPP) to be carried out in the Orinoco Oil Belt (Venezuela), is a technological project leaded by PDVSA Intevep together with several organizations of PDVSA E&P San Tomé. ISCPP is oriented towards the assessment of such thermal process in the increase of recovery factors in heavy (H) and extra heavy (XH) crude oil reservoirs.
Although the Orinoco Oil Belt was discovered in the 1930s, it was in the 1980s that the first rigorous evaluations were made. Recently, the area was certificated to contain 235 billions of recoverable (20% of recovery factor) barrels of heavy and extra heavy oil.
The ISCPP will allow the study and development of new technologies that increase the current recovery factor in the world's largest H/XH oil reservoir.
This work covers all of disciplines considered in the project, mainly:
1- The analysis of lab combustion tests using two kinds of cells both prepared with sand and saturated with water and XH crude oil at reservoir conditions.
2- The static and dynamic reservoir simulations using Petrel and Star respectively.
3- The design, construction and completion of producers, observers and air injection wells.
4- The study, analysis and development of surface facilities and the gas treatment system and monitoring, which must have to take care of relevant quantities of contaminant gases such as SO2, H2S and CO.
Based on this study, the technical and economical feasibility analyses were completed. The cold production is expected to begin during first semester of 2011, while the thermal phase involving air injection, which is the aim of the project, will be implemented throughout the second semester 2011.
The Orinoco Oil Belt was discovered in the 1930s; but it was not until the 1980s that the first rigorous evaluation of the resources was made. Recently, the area was certificated to contain 235 billions recoverable (20% of recovery factor) barrels of heavy and extra heavy oil (PDVSA 2009).
Faja Petrolifera del Orinoco (F.P.O) is by far the largest known heavy and extra heavy oil accumulation worldwide, located at north of Orinoco river in Venezuela contains about 1300 MMMBN of OOIP and 297 MMMBN of recoverable reserves. Exploitation of FPO has been done until present mainly by cold production, reaching recovery factors, is best cases, of about 10% of OOIP. PDVSA in recent years has conducted studies of quantification and certification of reserves, based on recovery factors that consider EOR projects. In situ combustion, the older member of thermal oil recovery family, is a method with a high thermodynamic efficiency that has allowed reaching recovery factors over 50% in some fields, accomplishing technical and economical success. This work presents a state of the art of combustion process and a review of the reservoir characteristics and field performance of successful applications in Venezuela and the rest of the world. These data were used to establish an application window, without weighting the size or significance of the reservoirs. This window, combined with data from reservoir characterization for the first six blocks of the FPO Junín area, was used to visualize the most prospective areas for the application of the process using parameters of thickness and water saturation in a commercial reservoir characterization software, followed by a qualitative evaluation of pressure, viscosity, temperature and depth, calculating this way the volume of oil and associated areal space occupied. Results obtained define Junín Blocks 5 and 6, specifically in areas of Basal Sands and Oligocene as the ones with the most potential, therefore, detailed studies should be performed to assess the technical and economical feasibility of the process implementation in these areas.
Most exploitation technologies currently and previously applied to heavy oil reservoirs are thermal processes. ??lvarez, C. (2006) states that thermal processes for enhanced recovery of heavy oil have been known and used since the middle of the XX century. According to Turta, A.T. et al (2007), in the last decades, commercial application of in situ combustion has diminished. In Venezuela and Canada, the two countries with the largest accumulations of heavy, extra heavy oil and bitumen worldwide, currently there are no active in situ combustion projects, even when in the past, in both countries were carried out a variety of pilots test for this technology with mixed results. This reduction in the application of in situ combustion has been attributed to operational problems and the lack of control of the process.
The present work focuses in the definition of the reservoir parameters for the application of in situ combustion process, based on the projects that have been successful in the world, and the comparison of those applicability parameters with the characteristics of Junín area of Faja Petrolífera del Orinoco (F.P.O.), with the aim to define potential zones for the successful application of in situ combustion technology. The study was performed with available reservoir description for Junín area of Faja Petrolífera del Orinoco, specifically, Junín 1, Junín 2, Junín 3, Junín 4, Junín 5 and Junín 6 blocks.
The heat may be supplied externally by injecting a hot fluid such as steam or hot water into the formations, or it may be generated internally by combustion. In combustion, the fuel is supplied by the oil in place and the oxidant is injected into the formations in the form of air or other oxygen-containing fluids. In principle, any hot fluid can be injected into the formations to supply the heat. The fluids used most extensively are steam or hot water because of the general availability and abundance of water. Hot water injection has been found to be less efficient than steam injection and will not be discussed here.
Anaya, Ismael (Petroleos de Venezuela S.A.) | La Cruz, Rosa Elena (Intevep S.A.) | Alvarez, Argenis Jesus (PDVSA Intevep) | Gutierrez, Dubert (Computer Modelling Group Ltd.) | Skoreyko, Fraser A. (Computer Modelling Group Inc) | Card, Colin (Computer Modelling Group Ltd.)
In-situ combustion (ISC) is a promising enhanced oil recovery process for the vast heavy oil accumulation of the Orinoco Belt in Venezuela. Combustion tube tests were performed to assess the feasibility of the process in a reservoir of the area. Given the successful laboratory results, it was decided to proceed with the design of a pilot test. Along with the basic design calculations, a simulation model was built to aid in selecting optimum well locations and operating strategies of the pilot. This would also be used for history matching of the actual operation and further optimization. One of the features of the model is the inclusion of the foamy oil behavior exhibited by the oil. For the modeling of the combustion process, a kinetic model developed in-house by PDVSA Intevep using thermo-gravimetric and scanning calorimetry experiments from an analog field, was employed. The first stage of the study involved the characterization of the oil into the same pseudo-components utilized by the kinetic model. A match of relevant PVT data was done for this purpose. In the second stage, the field scale model was history matched with the new fluid model, which included the foamy oil behavior. The best agreement with field measured data was obtained with a dispersed-gas foamy oil model with velocity dependence of the reaction that converts the low-mobility dispersed gas into high-mobility free gas. The following stage consisted of the history match of the combustion tube test, which was partly achieved with an assisted-history-matching tool. In the last stage, the results obtained from the combustion tube match were applied to the field model. In order to determine the most appropriate locations of production and injection wells, several pilot configurations were studied combining vertical and horizontal wells. A sensitivity analysis was completed using operational parameters such as injection rates and distance between producers and injectors wells. Based on ultimate recovery, the best pattern configuration was selected along with the optimum operational parameters. This paper illustrates the application of a workflow for modeling ISC from laboratory experiments to the field scale.
Venezuela has many heavy oil reservoirs, including the Orinoco Belt, the world's largest accumulation of heavy and extra heavy oil. However, since its discovery and further development, the recovery factor in most of the reservoirs is still less than five percent. Based on the need to look for alternatives to increase the recovery factor, the Venezuelan National Oil Company (PDVSA) is working towards the design and development of an ISC field-pilot test.
ISC is an enhanced oil recovery (EOR) process in which air or an oxygen-containing gas is injected into the reservoir to generate heat in-situ by burning a small percent of the oil in place. For this type of oils ignition is typically achieved artificially (e.g. using gas burners) and combustion is sustained by continuous injection of oxygen. The different driving mechanisms generated after ignition and combustion mobilize the oil towards the production wells to increase recovery. This process involves multi-phase flow in porous media, heat transfer and chemical reactions.
Brooks, David (Shell Intl. E&P Co.) | De Zwart, Albert Hendrik (Shell Intl. E&P Co.) | Bychkov, Andrey (Shell) | Azri, Nasser (Shell International EP) | Hern, Carolinne (Shell) | Al Ajmi, Widad (Petroleum Development Oman) | Mukmin, Mukmin (Petroleum Development Oman)
The primary recovery of a medium-heavy oil reservoir with a strong bottom aquifer is generally poor. The introduction of horizontal wells that are drilled at the top of the oil column has improved the oil recovery. However, even horizontal wells suffer from fast water breakthrough that leads to oil production at a high water cut. Given the low primary recoveries, such fields are attractive EOR targets.
In situ combustion (ISC) is a displacement process generally applied to medium-heavy oil reservoirs in order to increase oil production by reducing the oil viscosity. In thick reservoirs (thicker than 10 meters), oil recovery could be severely challenged by gravity override of the injected gasses. In reservoirs without active aquifers, a significant part of the incremental oil is produced by gravity drainage after breakthrough.
We propose an ISC strategy where an infill producer is drilled close to the oil-water contact so that a significant amount of heat can be rapidly deployed in the middle and upper sections of the reservoir. Subsequently, the aquifer is used to sweep the warm oil through the heated zone towards the producers. The ISC process is compared with steam injection that also employs an additional infill producer. ISC and steam injection are used to deploy heat in the reservoir.
Numerical simulations show that the oil is produced at much lower water cut compared to the cold case (50-60 % versus 95%). Simulated oil recoveries increase significantly for both ISC and steam injection. A detailed comparison of these two processes is presented in this paper.
For thermal recovery processes, the use of well test analysis to determine the swept volume is an important concern. Well tests conducted on wells undergoing a thermal recovery process have been typically idealized using a two- or three-region composite reservoir model. However, simulated thermal falloff tests have shown that mobility and storativity may be continuously changing in the swept region. For these reservoirs, a two- or three-region composite model may not be appropriate, while a multi-region composite model is suitable. A multi-region, composite reservoir analytical model has been developed to study the effects of various trends of mobility and storativity variations, within the swept region, on well tests for reservoirs undergoing a thermal recovery process. Pressure transient responses from this multi-region composite reservoir model show that on a log-log graph, the intermediate-time semi-log pressure derivative data falling on a straight line, whose slope is less than unity, is due to continuously changing mobility or storativity. The preceding behavior has been observed on several simulated thermal well tests. However, no theoretical explanation for this phenomenon has been advanced prior to this study.
Usually, well tests from enhanced oil recovery projects, such as steam injection, in-situ combustion, and CO2 flooding projects, are analyzed using a radial, two-region composite reservoir model. However, a three-region model may be more appropriate in may cases. An analytical solution for the transient pressure response of a well in a radial, three-region reservoir is available. But a detailed study of the transient pressure an-or pressure derivative response of a well in a three-region reservoir has not been presented in the literature.
Using a analytical solution, this study establishes the ratio of the intermediate region radius to the inner region radius as a correlating parameter for the transient pressure derivative responses for a three-region reservoir. Additional four parameters are related to the mobilities and the storativities of different regions. This study shows that the deviation time method would result in a estimate for the inner region radius, if the effects of the mobilities ad the storativities of the inner ad the intermediate regions are not balanced in a way to produce a incorrect deviation time.
Analytical expressions for the effective porosity-compressibility pressure and mobility are developed for the analysis of pressure transient data by the pseudosteady state (PSS) method. The PSS method would result in an estimate of the combined volume of the inner and the intermediate regions, if an effective porosity-compressibility value is used to analyze the pseudosteady data. However, at times, the development of an apparent pseudosteady state may yield an overestimated volume. An idea about the development of an apparent pseudosteady state may be obtained by calculating the effective dimensionless time corresponding to the time to start of an approximately constant Cartesian slope for the pressure transient data in question.
Two-region composite reservoir models have been used to analyze pressure transient data from enhanced oil recovery projects. Three-region composite reservoir models have been used less frequently to analyze well tests from enhanced oil recovery projects. Ref. 1 presents a review of analysis methods used to interpret well-test data from enhanced recovery projects along with several design and interpretation relationships developed from a analysis of well-test response for a well located in a two-region composite reservoir.