This work presents the conceptual development and experimental evaluation for a new technique to create blocking foams in matrix rock systems by the injection of the foaming agent dispersed in the hydrocarbon gas stream. This new technique aims at simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the disadvantage of limited reservoir volume of influence obtained in the SAG technique.
A systematic experimental work is implemented to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature, and using representative consolidated porous medium and fluids coming from the Piedemonte fields in Colombia. The concept behind this new technique is the transfer of chemical foamer from the gas dispersion into the connate or residual waters present in the hydrocarbon reservoirs under exploitation, due mainly to the chemical potential derived from the contrast in chemical concentration between the dispersed phase and the in-situ water.
Results herein confirm that it is possible to create blocking foam by this technique in a consolidated sandstone core at residual oil and water conditions, after being submitted to a gas flooding displacement. This condition is obtained as far as the gas velocity is above a minimum threshold, and the concentration of the active chemical is above certain limit (138 ppm for this case). Successful experiments with foams created by gas dispersed surfactant showed much longer stability periods when compared with results from foams created by the SAG technique at much higher chemical concentration (2,000 ppm). Application of this foams technique was done in a field pilot. About 600 Bbls of foaming solution were dispersed in the hydrocarbon gas stream in one gas injector of a Piedemonte field (Colombia, South America). Gas injectivity in the well was impaired after two weeks of injection, and the oil production well influenced by this injector changed its performance showing incremental oil production and flattening of the gas oil ratio (GOR) shortly after the dispersed chemical injection period. This innovative foams technique could also be extended to other non-condensable gases at field operating conditions like CO2, Nitrogen, Air, and Flue Gas.
Summary Genetic algorithms have been widely used in nonlinear multi-parameter optimization problems as seismic inversion. In this paper, via inversion of synthetic models, the role of the stochastic operators of crossing, mutation and selection in pre-stack seismic inversion is studied. Additionally, it is shown that implementation of reflected binary code (Gray code) out performs usual binary code. Genetic algorithm is applied to real seismic data of Colombian Llanos Orientales Basin. Introduction Surface measurements are the outcomes of diffractions, refractions and reflections that occur in the subsoil.
Ocampo-Florez, Alonso (Equion Energia Ltd.) | Restrepo, Alejandro (Equion Energia Ltd.) | Rendon, Natalia (Equion Energia Ltd.) | Coronado, Jorge (Equion EnergÃa Ltd.) | Correa, Juan Alejandro (Equion EnergÃa Ltd.) | Ramirez, Diego Alejandro (Equion Energia Ltd.) | Torres, Monica (Equion Energia Ltd.) | Sanabria, Rosa (Equion Energia Ltd.) | Lopera, Sergio Hernando (Universidad Nacional De Colombia)
Foams have proved to be efficient to block temporarily high conductivity layers, and improving gas injection conformance and sweep efficiency in predominantly matrix reservoir systems, at least at lab and field pilot tests; nevertheless, its successful use in naturally fractured reservoirs has not been fully demonstrated as of today. This paper presents the evaluation process and the successful results for two (2) foam EOR field pilots performed in the Cupiagua in Recetor field; a gas condensate system whose main reservoir is a low porosity (<6%) quartzarenite with matrix permeabilities in the range of 0.01 to 10 mD, and where the fracture corridors are confirmed to play an important role both in well productivity/injectivity, and in the inter-well connectivity and gas channelling between gas injectors and oil producers.
The reservoir has been developed under massive hydrocarbon gas re-injection, and the current recovery factors of condensate are between 35-40%. The foam treatments were deployed in two gas injectors located in different areas of the field, each one impacting two oil producers, and exhibiting different levels of gas recycling, with GOR ranging between 40,000 and 100,000 scf/STB.
Both operations were performed via bull-heading using the SAG method. The results for both jobs showed a temporary reduction in gas injectivity, with slow recovery to its base line within the next 3 months. Despite showing little changes in the injection profile at the gas injectors, the two producers affected by the first job showed a clear change in GOR trends, and a consistent ramp-up in oil production rates during a period of at least 7 months, reaching a maximum increase between 15 and 30 % over their base line productions. The second job was performed to confirm consistency and repeatability of technology, and evaluate duration cycle of blocking and benefit effects. Early surveillance indicates positive response both at the gas injector, and the oil producers. Results herein presented, confirm the viability for foams as an EOR method for this naturally fractured field, and open EOR opportunities for other fractured reservoirs located in the same basin and exploited under gas injection schemes.
Historically, the geomechanical behavior of a hydrocarbon reservoir has been modeled based on the classical theory of poro-elasticity, which considers absolute reversibility of deformation, which is liable to a porous medium when the mechanical state of the rock is altered. The sands associated with heavy oil formations are generally characterized by low levels of cohesion and density, which is viewed in an increased sensitivity of the rock to permanent deformation and hysteresis; hence it is not suitable to model these formations as if their rheological behavior is elastic. This set the need to construct a model, which describes the permanent plastic deformation that rocks from this kind of reservoir have. The modeling of the stress-strain behavior of plastic porous media aims to evaluate the permanent deformation that the rock suffers and to study the impact of this phenomenon on the behavior of the reservoir permeability porosity and mechanical stability of the layers overlying (compaction, subsidence). Several theoretical research and experimental surveys have defined that most heavy oil reservoirs can be studied as elasto-plastic materials. The purpose of this paper is to show the couple model of constitutive equations (stress-strain model) and fluid flow equations that describe the dynamic behavior of a heavy oil reservoir during an isothermal process, which deforms elasto-plastically, and thereby, to predict several geomechanical phenomena or consequence as productivity drop due to changes in the permeability, pore collapse, cap rock integrity, subsidence, among others, that allow an approach to the behavior of these kind of reservoirs in order to improve production processes and simulation.
Araujo Guerrero, Edson Felipe (Universidad Nacional De Colombia) | Alzate, Guillermo A (Universidad Nacional De Colombia) | Arbelaez-Londono, Alejandra (Universidad Nacional De Colombia) | Pena, Santiago (Universidad Nacional De Colombia) | Cardona, Alejandro (Universidad Nacional de Colombia) | Naranjo, Abel (Universidad Nacional De Colombia)
Sand production treatment, control and mitigation generate high costs for the petroleum industry. Therefore, this is considered a critical problem and requires a continuous monitoring and special management. A sand production study is fundamental in field development and will help to eliminate or mitigate the related problems. This way, an analytical geomechanical sand production model is proposed to design the best field sand free production plan and to select the type of sand control measures and sand management techniques. The model needs as input data, the reservoir characteristicsn and a mechanical earth model derived from well logs that includes the stress state regime. It also requires the well direction, azimuth and completion information in order to evaluate the well characteristics. In this model an onset sand production condition is calculated looking for the borehole pressure that makes the maximum effective tangential compressive stress equal or higher than the rock strength (failure criteria), which is usually known as critical borehole pressure (CBHP). The results are presented on two kinds of graphs: the CBHP versus depth graph that allows determining the sand production free interval and the CBHP versus reservoir pressure graph that helps to design different well production plans for optimizing the recovered volume avoiding sand production. Results must be calibrated and verified with data field to simulate the real reservoir behavior. Briefly, for a specific well path it is possible to propose the operating CBHP as a function of the reservoir depletion and well completion (open or cased hole), also for a new well, it is possible to design the best well direction and the completion type, in addition to the operating CBHP to minimize sand production.
Alzate, Guillermo A. (Universidad Nacional De Colombia) | Naranjo, Abel (Universidad Nacional De Colombia) | Arbelaez-Londono, Alejandra (Universidad Nacional De Colombia) | Arias, Juan Alejandro (Universidad Nacional De Colombia) | Araujo Guerrero, Edson Felipe (Universidad Nacional De Colombia) | Zabala Romero, Richard Disney (Ecopetrol)
Hydraulic fracturing is a well stimulation operation which is done with the purpose to increase the production of oil wells, and due to its associated high costs a preliminary evaluation using computational methods is required. Carrying out a hydraulically fracture in previously fractured wells could represent several benefits if the new fracture propagates towards different direction than the first did, thus the fracture can reach and drainage new regions in the reservoir.
The success of these operations depends on the behavior of the horizontal stresses, because they are the ones that determine the orientation and the geometry of the hydraulic fracture, the fluid production and injection that take place within both operations alter the stress state.
This paper shows the mathematical analysis developed to model the horizontal stress reorientation and the conditioning of a coupled geomechanics-flow numerical simulator to calculate the angle of reorientation, and the results obtained using the data of two wells located in Cupiagua field, Colombia.
Hydraulic fracturing is an operation that is becoming more popular in oil and gas industry, due to the need of sustaining and / or improving the productivity of wells to supply the world oil market and the lack of discovery of new reserves. The hydraulic re- fractured wells can be seen as a cheaper and simpler solution than to drill new wells to access undrained areas of the reservoir as a result of the production period of the first post- fractured well. But to access to undrained areas during the second fracturing job, a change in the direction of minimum stress must occur because this direction is a key parameter which defines the final propagation direction of hydraulic fracture. 
In recent decades, reservoir engineers have been dedicated to study and model the changes in reservoir geomechanics that are caused by changes in pore pressure as a result of the injection and production fluids. Among the main phenomena that result from the reduction of pore pressure are the rock compaction, which generates a decreasing pore size and consequently the decrease in permeability of the formation, and the surface ground subsidence in cases under extreme condition. The hydraulic fracturing process involves the injection of a designed set of fluids at high rates and pressures in order to make the reservoir rock fail and create a long and high-conductivity propped fracture; and thereafter the well is put into production for a period of time which generally comprises several years at a rate of flow variable as a function of properties and energy of producing formation, and also of fractures properties such as geometry, size (length and vertical extent), and conductivity.
Alzate, Guillermo Arturo (Universidad Nacional De Colombia) | Arbelaez-Londono, Alejandra (Universidad Nacional De Colombia) | Naranjo Agudelo, Abel de Jesus (Universidad Nacional De Colombia) | Zabala Romero, Richard Disney (Ecopetrol) | Rosero Bolanos, Mario Alejandro (Universidad Nacional De Colombia) | Rodriguez Escalante, Diego Leonardo (Universidad Nacional De Colombia) | Gomez Quintero, S. (Universidad Nacional De Colombia) | Benitez Pelaez, C. A. (Universidad Nacional De Colombia)
Well logs acquired directly in field have turned out to be one of the most key engineering elements to evaluate hydrocarbon formations. Nevertheless, the lack of information, some technical troubles related to the unfolding of tools, the operational states of the well and many other reasons may sharply limit the carrying out of an optimal formation characterization methodology along the entire productive or injective lifespan of a reservoir. Nowadays, artificial neural networks (ANN) are one of the strongest tools to supply such missing information in order to generate synthetic logs.
In this paper, we explain the putting into practice of an ANN methodology with the aim of provide useful input information in geomechanical modeling for the hydraulic fracturing simulator GIGAFRAC. More explicitly, the purpose of the schemes presented here is to provide transit-time curves for primary or compressional waves (DtP) and secondary or shear waves (DtS), based on full information measurements of Gamma Ray, Neutron-Porosity, Density, DtP and DtS logs; for some wells in the Cupiagua field located in Colombian Foothills, which break through some geologic formations such as Mirador, Barco, Guadalupe, and Los Cuevos.
A noteworthy amount of considerations were taken into account to ensure the success of the ANN estimation phases. A strong focus is done regarding to filtration and quality control of the input information to the network, relating to the control mechanism of outliers, as well as the splitting-up of logs in zones by using a geological criteria and spreading of data information in computationally convenient vectorial and matricial arrangements. Finally, good adjustments were obtained throughout the validation phases and they all were considered as successful outcomes, together with training phase and subsequent use of the same for estimating DtP and DtS curves.
Synthetic well logs derived from several methodologies, like artificial neural networks (ANNs), are used when formation or well data are not available, due to factors like the tool timing, the non-inclusion of the variable of interest or the difficulties during the logging operation.
ANNs are a set of learning and analysis models based on the human nervous system. The pattern recognition capability of ANNs makes them ideal in applications involving limited or highly distorted data, as long as it is possible to assign an appropriate training level, ensuring a proper fit to the problem of interest.
The aim of the implemented methodology and the proposed procedures is the generation of transit time curves for wells without this information. The generated data are essential for the geomechanical properties estimation of geologic formations in surrounding wells, to select well candidates regarding their feasibility for hydraulic fracturing.
Restrepo, Alejandro (Equion Energia ) | Ocampo, Alonso (Equion Energia) | Lopera, Sergio (Universidad Nacional De Colombia) | Coronado, Jorge L. (Equion Energia ) | Sanabria, Rosa B. (Equion Energia) | Alzate, Luis G. (Equion Energia ) | Hernandez, Sergio (Equion Energia)
The following paper is the continuation of SPE Paper 152309 (GaStim Concept - A Novel Technique for Well Stimulation. Part I: Understanding the Physics) and contains the experimental work and field pilot testing stages of the GaStimulation method already proposed by the authors. Systems studied correspond to tight quartzarenites containing retrograde gas condensates exhibiting Krg impairment under depletion. In this type of systems treatment penetration and durability are key factors for benefit sustainment. Supported by the theoretical background and preliminary lab tests presented in part I (SPE152309), the second stage of the GaStim project was planned and executed covering the phases of product´s screening, well candidate selection, pilots´ execution and results evaluation. Two pilots are reported, one in which water induced blockage is removed by stand-alone gas injection and another in which deep Gas + chemical dispersion is injected to reach a condensate blockage damage radius of 100 ft +. In the first scenario, it is noted that Sw reduction / Kg improvement is attained in the gastimulated area probably by coupled effects of evaporation and water slug displacement. In condensate blockage scenarios, it was noted that micellar type of surfactants exhibit the best performance when tested against IFT reduction capacity, Kg re-establishment (after condensate and water blockage) and treatment durability. Additionally, it was observed that the tuning of chemical concentrations and deployment method is key to maximize hydrocarbon flow capacity and minimize emulsion effects at surface after gastimulation. Further experimental work is planned to support modelling approaches both aimed on improving design criteria and expanding the potential of the technique into more challenging environments.
Vapourization of water in gas production can result in precipitation of salts in reservoirs. Water vapourization in oil fields occurs basically under two different scenarios: a) as a result of the increase of the molar water content in the gaseous phase as the pressure declines at a constant temperature around the wellbore; and, b) when dry gas is flowing in the reservoir, water is vapourized in order to fulfill the thermodynamic requirements at a given pressure, temperature, and salinity of the brine. Water vapourization has been reported as the cause of permeability reduction in some oil fields and as a potential problem in many others, especially in high pressure, high temperature reservoirs (HP/HT) which are characterized by very high salinity brines. The reduction in permeability can be aggravated over time due to capillary imbibition in water wet reservoirs into the zones where the water saturation has been reduced due to vapourization. Knowing the water content of the gas being produced is an important parameter to monitor and to prevent potential scaling problems due to water vapourization.