Copyright 2019, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Calgary, Alberta, Canada, 30 Sep - 2 October 2019. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Gutierrez, Mary Ellen (Universidad Industrial de Santander) | Gaona, Silvia Juliana (Universidad Industrial de Santander) | Calvete, Fernando Enrique (Universidad Industrial de Santander) | Botett, Jesus Alberto (Universidad Industrial de Santander) | Ferrari, Jean Vicente (Universidade de Sao Paulo)
About half of the world's oil reserves are in carbonate reservoirs, and most of these formations are mixed-wet or oil-wet and fractured, with extremely heterogeneous porosities and permeabilities. Implementation of enhanced oil recovery (EOR) techniques in this kind of reservoir is essential to achieve peak oil production and increase the recovery factor. Chemical EOR (CEOR) processes have been studied for many years in carbonate reservoirs but are not usually economically viable. Surfactant flooding has been considered as one of the most promising techniques among the chemical recovery methods due to the capacity of some surfactants to alter the carbonate rocks' wettability. However, the process is economically feasible only when losses of surfactant caused by adsorption into the porous media are decreased. Adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces. In general, the adsorption of cationic surfactants on carbonates is lower in comparison with other surfactants. Nevertheless, the high cost of cationic surfactants compared to anionic ones has led to studies aiming to evaluate the injection of the latter in the presence of a sacrificial agent in order to reduce the adsorption caused by interaction between the negative charges of the surfactant and positive charges on the carbonate surface. This work aims to study the effect of the presence of two chemicals, normally applied as scaling and corrosion inhibitors, on reducing the static adsorption of an anionic sodium olefin sulfonate surfactant on a carbonate rock. Water soluble poly(sodium methacrylate) (PSM) and diethanolamine (DEA) were evaluated as sacrificial agents in concentrations close to their scaling and corrosion inhibitor functions, respectively, to verify their sacrificial role in a co-injection chemical scenario. Adsorption studies were carried out using a pulverized carbonate rock in which low-salinity water was used as the base medium. Aqueous stability tests were carried out, which made it possible to select the correct salinity for the solutions of surfactant. Surface tension measurements were used as an indirect approach to study the adsorption of the surfactant in the presence and absence of PSM and DEA. Individually, PSM presented the best performance in reducing the adsorption of the anionic surfactant, while the DEA showed an almost null effect. However, when the chemicals were mixed, a synergistic effect was observed. The performance of PSM can probably be attributed to a steric effect of an adsorbed layer of polymer. It will be shown that even at lower concentrations, co-injection chemicals which are used for targeting other issues, such as scaling and corrosion inhibitors, may play the role of a sacrificial agent in reducing the adsorption of anionic surfactants, which is a concern in application to carbonate reservoirs.
Guerrero-Martin, Camilo Andrés (Universidade Federal do Rio de Janeiro – Instituto de Macromoléculas) | Montes-Páez, Erik (Universidad Industrial de Santander) | Khalil de Oliveira, Márcia Cristina (Petrobras) | Campos, Jonathan (Universidade Federal do Rio de Janeiro – Instituto de Macromoléculas) | Lucas, Elizabete F. (Universidade Federal do Rio de Janeiro – Instituto de Macromoléculas)
Asphaltenes precipitation is considered a formation damage problem, which can reduce the oil recovery factor. It fouls piping and surface installations, as well as cause serious flow assurance complications and decline oil well production. Therefore, researchers have shown an interest in chemical treatments to control this phenomenon. The aim of this paper is to assess the asphaltenes precipitation onset of crude oils in the presence of cardanol, by titrating the crude with n-heptane. Moreover, based on this results obtained at atmosphere pressure, the asphaltenes precipitation onset pressure were calculated to predict asphaltenes precipitation in the reservoir, by using differential liberation and refractive index data of the oils.
The influence of cardanol concentration on the asphaltenes stabilization of three Brazilian crude oils samples (with similar API densities) was studied. Therefore, three formulations of cardanol were prepared: The formulations were added to the crude at 5:98, 1.5:98.5, 2:98 and 4:96 ratios.
The petroleum samples were characterized by API density, elemental analysis and differential liberation test. The asphaltenes precipitation onset was determined by titrating with n-heptane and monitoring with near-infrared (NIR). The asphaltenes precipitation onset pressures were estimated. The envelope phase of the crude oils were also determined by numerical simulation (pipesim). In addition, supported in the downhole well profile and a screening methodology, the adequate artificial lift systems (ALS) for the oils were selected. Finally, the oil flow rates were modelling by NODAL analysis production system in the SNAP software.
The results of this study show the refractive index for each sample, and the predictive pressure to asphaltene instability. The asphaltenes precipitation onset of the crude oils were 2.06, 2.30 and 6.02 mL of n-heptane/g of oil. The cardanol was an effective inhibitor of asphaltenes precipitation, since it displaces the precipitation pressure of the oil to lower values. This indicates that cardanol can increase the oil wells productivity.
Trujillo, M. (Ecopetrol S. A) | Delgadillo, C. (Ecopetrol S. A) | Niz-Velásquez, E. (Universidad Industrial de Santander) | Claro, Y. (Ecopetrol S. A) | Rodriguez, E. (Ecopetrol S. A) | Rojas, R. (Ecopetrol S. A)
Prior to starting any Enhanced Oil Recovery (EOR) process, it is desirable to characterize the flow pattern within the affected reservoir volume. This becomes of critical importance for in situ combustion in heavy oil reservoirs, where the mobility ratio is highly unfavorable, oftentimes resulting in channeling or early breakthrough. An inter-well connectivity test through immiscible gas injection aids in characterizing the flow distribution, in addition to: 1) calibrating estimates for sweep efficiency, 2) evidencing geological features that may lead to preferential flow towards a particular well or group of them, or lack of connection amongst them, 3) creating a gas path between the injector and producer wells to enable a safe progression of the combustion front, and 4) evaluating the performance of artificial lift and well control systems under high gas-liquid ratio conditions.
A connectivity test using nitrogen was designed, implemented and evaluated at the Chichimene field, prior to the ignition of the in situ combustion pilot. This process is summarized and described in this paper. This will be the first in situ combustion trial in a deep (≈ 8,000 ft), extra-heavy oil reservoir, and will serve as a data source to evaluate the development of resources under similar conditions in the eastern plains basin of Colombia. This set of reservoirs bears a significant fraction of the hydrocarbon resources in the country and under Ecopetrol operation.
The importance of this pilot makes this connectivity test of even larger relevance to reduce the subsurface and operational uncertainty, identify risks, and increase the probability of success of the combustion process as an option to economically producing these resources.
Cedeno, D. (Universidad Estatal Peninsula de Santa Elena) | Alvarez, A. (Universidad Estatal Peninsula de Santa Elena) | Fuentes, J. (Universidad Estatal Peninsula de Santa Elena) | Portilla, C. (Universidad Estatal Peninsula de Santa Elena) | Machare, V. (Universidad Estatal Peninsula de Santa Elena) | Erazo, R. (Universidad Estatal Peninsula de Santa Elena) | Escobar, K. (Escuela Superior Politécnica del Litoral) | Cedeño, R. E. (Universidad Industrial de Santander)
This work highlights the use of tools that can perform multi-space directional multifrequency propagation measurements to drill horizontal wells in real time. The same that provide information such as the distance of the geological limits and the orientation of fluids through interpretations that can be executed in real time and recorded mode. The new concept of measurements and principles involves tilted and transverse antennas to provide measurements that are sensitive to the orientation of the tool with respect to the geological structure around the well, enhancing real time decision making and improving the geo-position trajectory of productive wells.
Santos, N. (Universidad Industrial de Santander) | Carrillo Moreno, L. F. (Universidad Industrial de Santander) | Carreño Hernandez, J. H. (Universidad Industrial de Santander) | Rodriguez Molina, J. J. (Universidad Industrial de Santander) | Martinez Lopez, R. A. (Universidad Industrial de Santander) | Modelamiento de Procesos Hidrocarburos, G. (Universidad Industrial de Santander)
Formation damage due to calcite deposition is currently an issue in the five sedimentary basins producers of hydrocarbons in Colombia. At this moment, over 100,000 BOPD are in risk due to this kind of damage. A lab-scale correlation is developed which contemplates thermodynamic and hydrodynamic parameters for predicting the Calcium Carbonate formation tendency in Sandstones. An experimental methodology to recreate the continuous deposition of CaCO3 was implemented using Berea sandstones, scalating different production rates and varying the physicochemical composition of the formation water, reproducing accurately the concentrations of the ions Ca++ of Colombian oilfields (consisting currently the biggest issue in this sort of formation damage). The used methodology consisted in a factorial experimental design, which allows the optimal combination of thermodynamic parameters (represented by the Ca++ concentration) and hydrodynamic parameters (represented by injection rates), along a series of rock-fluid interaction experiments which exhibited a permeability impairment of approximately 80%. The correlation was developed using a specialized software. The proposed correlation predicts the permeability impairment with an 80% adjustment of experimental data. This correlation is valid for low permeability values (less than 150 mD), field-scale velocities between 1 and 10 ft/day, and contemplates regular values of Ca++ ions concentration for Colombian oilfields. Furthermore, the correlation was validated with experimental data obtained at several flow rates (between 1 and 3 cc/min), several temperatures (150 -250°F) and several concentration of Ca++ ions (250-650 ppm). This proposed correlation is the basis to develop a deterministic model, which quantifies the depth, severity and production losses related to this phenomenon.
Well deliverability is directly related to the hydraulic fracture conductivity of the created fracture networks. There are several influencing factors on fracture conductivity, including fracture surface topography, mechanical properties, and proppant concentration. Fracture surface topography inherently defines the connectivity of cavities inside the fracture that serve as flow channels, and such flow channels are further enhanced by the presence of proppant. This paper presents a study considering the aforementioned phenomena, centered primarily on the effect of proppant concentration on the primary hydrocarbon-baring Unit B of the Eagle Ford Shale formation.
Laboratory experiments were conducted to investigate the effect of proppant concentration on fracture conductivity for Eagle Ford Shale samples. The test samples were obtained from outcrops at Antonio Creek, Terrell County, Texas. A 100-mesh sand was utilized, as it is representative of the industry practice in the region. Fracture conductivity measurements were conducted by flowing dry nitrogen at varying closure stress stages. Ancillary measurements included Young's Modulus and Poisson's ratio obtained by a tri-axial compression test. The Brinell hardness number was measured by an indentation test, and fracture surface topography was obtained using a laser profilometer.
Results show that the initial evenly distributed proppant concentrations were altered during the process of measuring fracture conductivity, yielding a final proppant distribution that partially occupied the fracture surface. The remaining surface area was absent of proppant and served as channels of high conductivity relative to the areas occupied by proppant. It is believed this behavior occurs in field operations, especially under conditions of varying gas flowrates during production. Additionally, this work suggests the possibility of an optimum initial proppant concentration that can result in the highest channeling behavior for a particular fracture surface.
Valle Tamayo, G. A. (Universidad Industrial de Santander) | Romero Consuegra, F. (Universidad Industrial de Santander) | Mendoza Vargas, L. F. (Universidad Industrial de Santander) | Osorio Gonzalez, D. A. (Universidad Industrial de Santander)
A new approach is proposed for adjusting models of empirical equations to predict PVT properties based on current operating conditions of Colombian fields. The results obtained with this new approach are compared with existing correlations.
Using PVT measurement properties from 51 Colombian fields distributed in eight producing oil basins (which represents more than 50% of total Colombian oil production), and through the application of multivariate statistical analysis and average relative error, a new approach was presented focused on two methodological criteria: i) PVT empirical correlations existing adjusted to the operating conditions of Colombian fields. ii) Proposal of empirical equations to estimate the bubble point pressure, oil volume factor and gas ratio in solution, of Colombians crudes.
The inaccuracy of the empirical correlations of the fluids properties contained in the literature, to implemented for Colombian crude is manifested. Correction factors to adjust the experimental data are proposed to reduce the relative error percentage of correlations. A new empirical equation for estimating PVT properties is presented, necessary to solve reservoir engineering and surface production operational problems; by multivariate analysis. The proposed models are compared with the traditional ones, through relative errors based on the PVT measurement acquired, with the aim of ranking them according to its uncertainty.
Through the correlations based on Colombian crudes presented hereby, PVT fluid properties are obtained exhibiting behaviors with a lower order error compared to currently implemented in the industry. This improvement in PVT calculation accuracy will be of invaluable support for simulations and designs applied in Colombian Oil industry.
A new mathematical model is proposed using machine learning techniques for estimating PVT fluids properties such as bubble pressure and oil formation volume factor as a function of the solution gas-oil ratio, gas specific gravity, oil specific gravity, and temperature.
The result obtained with this new approach are compared with previous published correlations. The proposed method for PVT properties estimation consists of two stages: data decorrelation through Principal Component Analysis (PCA) and PVT properties estimation through an Artificial Neural Network (ANN). Data decorrelation is used to reduce redundancy in the data, which decrease the number of neurons and hidden layers needed for an ANN to achieve a high accuracy estimation. In the development of the proposed method there were used 504 points obtained from the literature as follows: 360 for training, 40 for cross-correlation and 104 for testing. The present model was compared with empirical correlations of PVT fluids properties in terms of absolute average percent error, standard deviation, and correlation coefficient; using worldwide experimental PVT data.
The results obtained show that the proposed model provides better estimation and higher accuracy than the published empirical correlations. The present model provides predictions of the bubble pressure and formation volume factor with a correlation coefficient approximately of 98%. Trend tests were performed to check the behavior of the predicted values of bubble pressure and formation volume factor for any change in reservoir temperature, solution gas-oil ratio, gas gravity and stock-tank oil gravity.
The model was based on artificial neural networks, and developed using 504 published data sets from the Middle East, Malaysia, and North Sea fields. This improvement in PVT calculation accuracy will be of invaluable support for simulations and designs applied in Oil industry.
Sandoval, M. I. (Universidad de Santander, Grupo de Investigación Recobro Mejorado) | Muñoz Navaro, S. F. (Universidad de Santander, Grupo de Investigación Recobro Mejorado) | Molina Velasco, D. (Universidad Industrial de Santander)
During EOR recovery processes, asphaltenes macromolecules can flocculate and cause drastic changes in the petrophysical properties of the reservoir, therefore it is very important to determine the time at the flocculation begins and further the size of the aggregates, since ultimately this depends on whether these can be trapped in the porous media. This work aims to evaluate the change in the asphaltene hydrodynamic radius of at different concentrations of n-heptane and to detect the onset asphaltene floculation using a new technique known as 1H Diffusion ordered spectroscopy-NMR (DOSY-NMR). H-DOSY NMR is a method based on the pulsed field gradient spin-echo from nuclear magnetic resonance (PFGSE NMR) and it allows the identification of the molecular components of a mixture sample and at the same time obtain information of their size through the diffusion coefficient. For our specific case, the asphaltene hydrodynamic radius was 16.8 Å and the onset of asphaltene floculation can be observed when the concentration of solvent n-heptane was 30 wt %.