In the fluid flow study of polymer solutions through porous media in chemical enhanced oil recovery (ChemEOR) it is important to take into account very important properties such as the adsorption of polymer on mineral substrates, the residual resistance factor (Rk), the resistance factor (Rm), the wettability of the medium and cumulative recovery factor. For these reasons, this study has as main objective to evaluate rock-fluid behavior in presence of polymeric formulations by coreflood tests in porous media representative of extra-heavy crude reservoir conditions. To do this, an experimental methodology was proposed and a range of concentrations (800, 1500 and 2000 ppm) was established as the main variable of this study. Subsequently, relative permeability curves (Kr) on real sand cores were generated with an average absolute permeability of 7486.60 mD. Resulting in endpoints of the area of interest of: 29.0% and 65.6% of Swirr (Irreducible water saturation) and Sor (Residual oil saturation) respectively and a primary recovery factor of 36.4%. The amount of polymer adsorbed under dynamic regime was 19.1, 124.1 and 136.9 ug polymer/g rock. Following the same order, the values of additional oil recovery factor under polymer injection were 5.4, 10.2 and 15.2%, indicating a proportional increase with respect to injected concentration. However, there was no apparent correlation between the polymer concentration and residual resistance factor. Additionally, the initial wettability of the medium was preferential to water and this property increased with the injection of polymer formulations. Finally, using a methodology developed in this study, recycled polymer produced efficient results in ChemEOR processes generating an additional recovery factor of 2.38%. It also reduced the mobility of water in 98% (of that reported initially) and lastly its injection proportion per volume of crude produced was 3.522.
An experimental evaluation of a gas-liquid axial cyclone separator was conducted in a multiphase flow facilities al PDVSA-Intevep, the evaluation of the prototype was executed under controlled conditions of flow rates, between 24 and 60 Bbl/day for a liquid phase and between 80.000 and 190000 SCFD for a gas phase, considering three stator with 45, 60 and 75 of blade angle in a swirl generator section. The axial cyclone separator was built in plexiglass in order to record with video camera the phenomenon that was observed inside of the equipment the experimental data of the matrix was collected in a control room, considering the measurement of flow rate, local pressure and the pressure drop in the equipment. The axial cyclone separator consists of a flow conditioning section, as will generator section and a segregation section. Finally, a total of 72 points were valuated, the performance of the axial cyclone separator was improved with 60 and 75 of the blade angle than a 45 because the collection efficiency was above of 90%, in this study the pressure drop increases inside the equipment 30% when the 75 of blade angle was used in the stator, the best performance was achieve considering the 60 of blade angle in a swirl generator section.
Summary Lithologic discrimination was performed in clastic reservoirs in Orinoco Oil Belt, Venezuela, integrating rock physics, simultaneous seismic inversion and support vector machines. The rock physics analysis allowed to obtain relation between lithologic facies and elastic properties in reservoirs. Subsequently, through simultaneous seismic inversion was possible to generate P and S wave impedances and density volumes. Finally, combining the previous two points was generated a lithofacies volume using the algorithm of support vector machines as classification tool. Results of this study permitted to identify reservoir pay zones.
Solids/sand production is a serious problem faced by the petroleum industry during production stages. Particles or groups of particles of formation rock are produced together with oil or gas being pumped which has highly damaging effects on pipes and valves. Numerical simulation of sand/solids production presents a considerable challenge as intricacies of failure processes must be correctly simulated in order to correctly predict rates of solids production. This paper presents a finite element based procedure for simulating the process of sand production, considering fluid-mechanical coupling in both elasto-plastic Cosserat and standard continua. It is believed that the enhanced deformation modes included into Cosserat continua may contribute for proper modelling of the deformational behaviour and failure modes of the cemented/non cemented granular materials involved. This is made possible by the incorporation of enhanced kinematics and statics as compared to standard continua kinematics through additional degrees of freedom related to rotations of the microstructure, statics through the transfer of moment/couple stresses. For the modelling of the elasto-plastic/failure behaviour of the granular media involved, generalized Mohr-Coulomb constitutive model was implemented to Cosserat continua.
The phenomenon of particle production during the extraction of oil producing wells is commonly called sand or solids production. According to Dusseault and Santarelli , this physical phenomenon usually occurs when the fluid/porous medium, previously stable, becomes unstable, reaches the strength limit of the porous matrix, with consequent breakdown of the its constituent parts thereafter. Field observations indicate that perturbations of flow gradients and of effective stress acting on the porous matrix of the formation, initiate tearing of small fractions of the rock.
This phenomenon is commonly seen in sandstones, especially in poorly or non consolidated ones. However, it does not occur exclusively in these rocks, as it is also observed in rocks of various natures, such as coal and limestones.
Sand production is one of the most frequent and serious problems observed during the extraction of oil or gas. The Society of Petroleum Engineers (SPE) indicates that much world''s hydrocarbon reserves are contained in sandstone, and thus potentially subject to this phenomenon. Also, if not properly controlled, this might make the development of borehole economically unfeasible, or provide their premature closure. According to Fjaer et al , it is estimated that seventy percent of the world''s hydrocarbon reserves are contained in reservoirs where sand production may occur.
Bianco  suggested that the sand production phenomenon in oil producing wells would be associated to three basic sets of factors: magnitude of the in-situ stresses and its variations, pressure gradients, fluid flow velocity and changes in fluid saturation; strength factor (strength of the material, inter-particle friction; arcs of sand, capillary forces); operational factors (strategies of drilling and completion, production procedures and depletion of the reservoir). A description of operational aspects and other mechanisms related to sand production are described in detail in Fjaer et al .
Castro, Yefrenck Enrique (Petroleos de Venezuela S.A.) | Sanchez Monsalve, Diego Alejandro (PDVSA Intevep) | Veliz, Alida Maria (PDVSA E&P) | Rodriguez, Mileydi Margarita (PDVSA-Intevep) | Rondon, Nelson Gabriel (PDVSA) | Rivero, Solange (PDVSA Intevep) | Cortez, Marina Luz (PDVSA Intevep)
Venezuela has the biggest reserves of heavy and extra heavy oils in the world. High viscosity of heavy and extra heavy oils is the main difficulty for its exploitation and production. Steam injection is a possible enhanced oil recovery (EOR) technique most widely applied to this type of oils based on temporary viscosity decrease. Commonly, it is used in Venezuela and Canada; however, factors as steam availability at field operations and low values of displacement efficiency achieved along the process by oil viscous forces have affected its possible use in the future.
Nowadays, PDVSA Intevep is evaluating the potential application of the method using some light oil cuts as solvents or additives which are from refineries located nearly to the fields under exploitation operations.
So far, static tests have been carried out by using methane, heavy oil from a Venezuelan field (9°API y 41500cP@43 °C) and solvents as light oil cuts (naphtha, kerosene) and two types of effluents from some refinery processes which will be named cut A and B along this investigation at saturated steam conditions. Displacement tests using displacement cells at reservoir conditions in porous media (253 °C, 400 psi, 30% porosity value and 4 Darcies, permeability) have also been performed in order to determine percentages of oil recovery.
Results indicated no net differences between the solvents selected during oil - solvent compatibility tests. Nevertheless, the effluents named 1 and 2 increased percentages of recovery factor notably along displacement tests obtaining values around 50 % in comparison to conventional displacement tests by using steam only. Hence, the use of this type of effluents which are cheaper than the light oil cuts selected is being recommended as potential application at field operations in Venezuela taking into account further studies as well as further technical and economical evaluations.
Overview - No abstract available.
Two-phase flow behavior prediction of centrifugal pumps is a hard task due to the complexity involved in modeling multiphase flow inside turbo machines. No models are currently available for this purpose. Some empirical correlations are available in the literature, but they are valid only for the tested pumps in the experimental range used to develop them. An experimental study has been conducted at The University of Tulsa Artificial Lift Projects - TUALP with a 22-stages GC6100 pump to gather data for pump performance under two-phase flow conditions. Air and water were used as working fluids. This study differs from other experimental works because the pressure changes were recorded stage-by-stage. The results of previous works have been reported as an average of the intake and discharge conditions, and depend on the number of stages used.
Phenomena like surging and gas locking were observed during these tests and their boundaries have been mapped. It will provide some insight regarding when they appear, and the way they are revealed.
The pressure increment and total hydraulic horsepower for the average pump and per stage as a function of the liquid flow rate, and each gas flow rate considered are presented. The average brake horsepower and efficiency for the pump are also plotted for the variables mentioned.
The results indicate that the average behavior for the pump is significantly different from that observed per stage.
Centrifugal pumps are dynamic devices which use kinetic energy to increase liquid pressure. They are successful with handling water and other incompressible fluids ranging from low to medium viscosities but are severely impacted by free gas or highly compressible fluids.
Significant amounts of free gas may be found during hydrocarbons production. This motivated important research from the petroleum industry focusing on improving the successful application of ESP as an artificial lift method.
The consequences of entrained gas on centrifugal pumps depend on the relative amount of gas and liquid present, and vary from a slight deterioration on performance up to a complete blockage known as "gas locking". Before gas locking occurs, another phenomenon known as surging takes place.
Each pump is characterized by performance curves, which include the head developed, brake horsepower consumption and efficiency as function of the flow rate through the pump for a certain rotational speed (see Fig 1). Traditionally these curves are determined experimentally using water.
The head characteristic curve is used to size the pump, while the brake horsepower information is useful to size the motor required to drive the pump. The sizing of a multi-stage ESP for water wells is fairly simple, and good accuracy of the predicted performance is achieved using the water performance information supplied by the manufacturer.
The design of an ESP system using the water information for oil wells with high free gas fraction at pump intake conditions is a harder task, and is based on the prediction of performance curves by modification of the water curves. The leading parameter is the mixture density at the flow conditions of each stage. Applying this procedure, the ESP system often shows some degree of under or over sizing when operating.
An accurate prediction of the performance for any pump handling free gas is challenging. Some empirical and mechanistic approaches have been attempted in the past. The main problem of the experimental approach is that the developed correlations are based on the average performance of the pump. These correlations become specific for the type and number of stages tested. On the other hand, theoretical models are difficult to develop since the geometry of the channels inside the pump is complex. The phenomena that take place in such channels are not well understood, and thus the use of empirical parameters to close the model is required.