The increasing world oil demand has led to develop the large heavy and extra heavy oil resources located in Venezuela. Heavy oil production and transportation are especially difficult due to the high viscosities of this oil that increase the complexity of the multiphase flow involved. Traditionally, low/gas liquid ratios have been associated to heavy and extra heavy oil fields; however, the experiences in the Faja Petrolífera del Orinoco Hugo Chávez Frías (FPO-HCF) indicate the presence of enough volumes of gas that impose further technical challenges which must be considered in surface facility processes - to be able to handle multiphase flow, and the different flow patterns that could be promoted through pipelines.
In the case of heavy and extra heavy oil fields, hydrodynamic slug flow is the most common flow pattern. For this reason, it is important to know how this flow pattern behaves as oil viscosity increases in order to improve the operation and design of surface facilities, such as: pipelines, separators, flow conditioners, risers, multiphase equipment, etc. Additionally, if slug flow pattern is better understood, corrosion effects could be better predicted, therefore, strategies to reduce this problem will be considered in a rigorous way.
One of the approaches to understand the slug flow pattern is experiments and improved mathematical models that predict both the flow pattern transitions and the slug flow characteristics. To this end, an experimental study of three different gas/liquid systems is made which includes liquid viscosities of 0.001 Pa.s, 0.418 Pa.s, and 0.996 Pa.s. In this work was studied the liquid viscosity effect on the slug flow characteristics, such as: flow pattern transition, slug translational velocities, slug lengths, pressure drops, holdup, and slug frequency. Moreover, a flow pattern transition model is proposed for two-phase gas highly viscous liquid systems.
IntroductionBy early 2014, Venezuela had nearly 298 billion barrels of proved oil reserves, the largest in the world. Most of these vast resources are heavy and extra heavy oils located in the FPO-HCF.
Electrical Submersible Pumps (ESP) are turbo machines that deliver energy to fluids using several stages comprised by one impeller and one diffuser. ESP performance is affected by viscosity variations and changes in the value of gas void fraction of the fluids that are pumped. For any centrifugal pump, as the viscosity of the fluid increases, the required brake horsepower increases as well; whereas, head capacity and efficiency decrease. Additionally, gas void fraction presented in multiphase pumping condition may affect negatively the head capacity of ESP systems. This research had as main goal to evaluate, in a fit for purpose test rig, a 513-series, 35-stage, mixed-flow-stage pump under two-phase flow conditions. Pressure and temperature changes at several stages through the pump were recorded. As a fluid, it was selected a multiphase mixture with air and ISO 320 mineral oil. The experimental matrix included tests with range of gas void fraction from 0% to 17%, 50 psig as pump intake pressure and 50 Hz of operating frequency. A better performance of downstream stages, located in the upper section of the ESP, was reported. A considerable rise of fluid temperature throughout the pump's stages was particularly reported in a range from medium to low flow rates. Furthermore, it was corroborated the unstable pumping region, where surging phenomenon occurred. The study was operational constrained by health security and environment restrictions – specifically the impossibility of using real heavy crude oil and gas as pumping fluid. The resulting information will allow better understandings of the ESP performance focused on multiphase pump condition where viscous fluids are present.
The prediction of pressure drop in multiphase flow for risers is of particular interest for the oil industry and also a critical variable for the right design of surface facilities in offshore fields. Empirical steady state correlations, mechanistic models and dynamic models are available to calculate the multiphase flow pressure drop, holdup and phases distribution. The main purpose of this paper is to evaluate the accuracy of several steady state pressure drop prediction models with two phase flow laboratory data conformed by 108 point using air as gas phase and liquids with viscosity up to 310cP. The models considered in this study, for predicting pressure drop are Beggs and Brill, Duns and Ros, Govier and Aziz, Hagedorn and Brown, Mukherjee and Brill, Orkiszewski, Ansari and OLGAS model, using PIPESIM simulator. The evaluation was based on the comparison between the predicted and the measured pressure drops, demonstrating the performance of each model for highly viscous liquids.
The Faja Petrolifera del Orinoco (FPO), located in the southern part of the Eastern Basin of Venezuela, has the largest reserves of heavy and extra heavy oil in the world. These oils are highly viscous and their API gravities values are between 7 and 15, these properties together with the existence of multiphase flow make the production and transportation of these oil is highly complex. Therefore, it is necessary to use heavy oil transportation methods focused on reducing the viscosity of oil, this is achieved be removing or modifying the oil compounds that have been pointed out as the main cause of the high viscosity of these oils, such as: partial or total upgrading or slurry transportation. This study presents a flow modeling of a solid-liquid dispersion through horizontal pipes, which represents a slurry transportation, using a software of computational fluid dynamics (CFD) called FLUENT 6.3. For the simulation methodology was selected Euler-mixture in a three dimensional pipe model, with different concentrations of solids. The simulations were validated with experimental data development by PDVSA Intevep that contains pressure drops, temperature, solid characterizations and reological behavior of the slurry. The performance evaluation by the CFD model showed an acceptable fit when it is compared against experimental data, this results allow to understand the hydraulic behavior of heavy oil slurry transport through pipeline.
The in situ stresses constraint is one of the most difficult parameter in a geomechanics model. Most of them are simple models in which is not involved the influence of geological discontinuities such as complex fault system, bedding plane, folds and joints. Recent studies have pointed out that these can significantly impact on the in situ stress states, leading to changes in magnitudes and rotations of stress tensor along formation sections. However, taking into account the structural geology and projecting the stress state underground, its uncertainty can be reduced. It results in an improvement during the well construction design to obtain a safer operational fluid density window, optimum well trajectories and an effective borehole stability analysis.
This paper presents an integrated methodology to interpolate the magnitude of the stresses and their orientation, including the effect of structural geology. A case of study from Eastern Basin Venezuela, SJ Field, was analyzed. First, a review of the structural geology model was done to identify its origin and the fault history. Then, a geomechanics 1D model with the pore pressure calculation, rock mechanics properties and in situ stress estimations was developed to be integrated with a kinematic analysis in which the structural restoration was defined. Besides, dynamic analysis using a numerical simulation with finite element in a 2D structural section was performed.
The results confirmed that stress state changed not only in orientation, but also in magnitude near to the Anaco Thrust. As a main consequence, the boreholes located next to this structural element experiment variations in depth from normal to strike-slip regime.
With the aim of maintain Oil and Gas production in the Lake of Maracaibo fields, avoiding flowlines systems failure occurrence due to external and internal corrosion, it was necessary to initiate a project to study the availability of substituting failed metallic pipelines by composite materials alternatives. Due to the lack of experience in the use of flexible pipe for offshore application in Venezuela, it was mandatory to evaluate the behavior of this technology during real operation in the Lake of Maracaibo. Three flowlines transporting multiphase oil/water/gas flow and six gas lift flowlines were deployed, installed and commissioned in 2009 with the objective of evaluating the materials and operational performance during service. An exhaustive evaluation program was developed and performed under the API 17 J and API 17 B requirements and recommendations with the objective of assuring the mechanical integrity of the flexible pipes prior and during service. Mechanical properties test, hydrostatic pressure test, gas-venting test, aging test and gauge test were performed in laboratory for new and aged samples retrieved from service every three months. Continuous inspection and monitoring of the gas venting system during service was also set up. After three years of service, no failure or damage associated with the material in any of the nine experimental flowlines deployed in the Lake of Maracaibo were detected, opening the possibility to use the flexible pipe technology to restitute the Oil/Gas production.
In the oil fields of North District in Venezuela, one of the common characteristics is the high temperature of the oil (up to 150 °:C) that has a di rect impact on the performance of the pipeline’s coating. Internal and external corrosion are the common problems in the performance of these flowline systems. In the past 10 years, one solution used to mitigate the external corrosion in the pipelines has been with the use of liquid epoxy resin-based coatings. Nevertheless, beside the use of liquid epoxy coatings, very little is known however about the degradation of these coatings at high temperatures. The main purpose of this paper is to present some results of thermal and thermo-oxidative ageing of five different types of liquids coatings systems (A, B, C, D and E). For this evaluation, we prepared coupons of carbon steel coated with all the organic coatings system. Differential scanning calorimetry (DSC), Aging tests, Thermogravimetric analysis (TGA), Fourier transform infrared spectroscopy (FTIR) measurements, Scanning electron microscopy (SEM), and Cathodic disbondment (CDT) were performed in order to classify the thermal degradation of the coating systems. Results show an influence of the aging conditions on coating embrittlement.
The continuous increase in the world's oil demand is leading to improvements to existing transportation solutions or development of new ones. Venezuela has 296.500 million barrels of heavy and extra heavy oil certified reserves, located in the Orinoco Oil Belt. The main strategy to develop the Orinoco Oil Belt is a combination of dilution and upgrading of the extra heavy oil. For the developments to be feasible, however, alternative transportation solutions must be explored, such as the addition of polar compounds to improve dilution, heating, oil-in-water emulsion, core annular flow, foam flow and slurry transportation.
Current selection of candidate wells for water shutoff by polymer gel technology is based on empirical criteria which make uncertain its result. Although sophisticated models to resemble the injection of polymer gels in a porous media are available, they require extensive knowledge of the well and reservoir, plus specific yet to be characterized gel kinetics parameters. In this work a model is proposed to predict a well future production response based on well and reservoir information that is commonly available.
Neural network models were designed, trained and validated for predicting wells production performance after a polymer gel treatment for water shutoff. A total sample of 31 historical applications of gel treatments were used for training and validating the proposed networks. Historical applications gathered include different well and reservoir types, which make the model prediction validity wide broad.
Neural networks with two different tasks were developed during this study, one of them with a bi-valuated response (output), and qualified as classification networks and the others with a wider range of potential output, identified as regression networks. The model aims to predict a well future oil production and the percentage of water associated to that production after the execution of a gel treatment. Training of the neural network was carried out using 90% of the wells set gathered and 10% of the wells were used for validation. An average relative error of 20% was obtained when comparing the actual production performance of wells and the neural network prediction for oil rate and water content.
The proposed neural networks allow the selection of future candidate wells for gel treatments, based on its potential success. Additionally, the proposed network allows improving future gel treatments by evaluating the effect of the volume of gel to be injected on the treatment's result.
Alvarez Lameda, Mariangel (PDVSA Intevep) | Chirinos Reyes, Manuel Segundo (PDVSA Intevep) | Silva Chamorra, Félix (PDVSA Intevep) | Zabala Marin, Adrian Rafael (PDVSA Intevep) | Perdomo, Lenin Eduardo (PDVSA Intevep)
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