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Collaborating Authors
SPE Latin America and Caribbean Petroleum Engineering Conference
Abstract Tight gas reservoirs exhibit frequently long periods of transit flow regime and do not reach the Boundary Dominated Flow (BDF) across their production history. This is caused due to low matrix permeability, that creates the need of a pervasive fracture networks to maximize the well – reservoir contact and drainage area. This will unlock high initial flow rates and a sharp decline from the early years of production. The development of new empirical equations approached to the understanding of tight gas reservoirs variability, through declination parameters. However, this produces uncertainties since the empirical models could have an analytical theory that has not been demonstrated at that time. The role of uncertainty analysis is very crucial throughout the investigation of the reservoirs Tight Gas, especially when production profiles present an unknown behavior in later periods. In this case, the degree of uncertainty increases, so the need for a probabilistic analysis to forecast production is fundamental. The paper proposes a methodology to define the statistical distribution of the declination parameters and predicts the behavior of gas reservoirs Tight, taking into account the uncertainties. The method also allows calculating a wide range of realization for each production well, sampling randomly the input parameters from the statistical distributions as in a Standard Monte Carlo Workflow. We provide an Evaluation of the realibility of the methodology considering a wide range of predictions and an evaluation of the Results with an avaiable historical dataset. To finally estimate reserves in terms of P10, P50 y P90 based on a combination of Advanced Decline curve [1] at specific time limit or abandonment rate. This case study was developed on a sectorial block of the Lajas Formation of the Neuquen Basin, with wells in production, where the use the uncertainty assessed to define the development strategy for a new field and the project choices. [1] Stretched Exponential Production Decline Model(SE), Doung Model(DNG), Power Law Exponential Method, Modified Hyperbolic and Modified Doung.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Probabilistic methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Information Technology > Artificial Intelligence (0.46)
- Information Technology > Databases (0.40)
Abstract Cold Heavy Oil Production with Sand (CHOPS) is widely used as a primary non-thermal production technique in thin heavy oil reservoirs in Western Canada and the Orinoco Heavy Oil Belt in Venezuela. Several solvent and hybrid steam/solvent schemes have been proposed to increase the recovery factor from these deposits. Development of the complex wormhole networks renders the scalability of these processes from laboratory measurements to field applications challenging. In this paper, numerical simulation is used to analyze how scaling of solvent transport and dispersion would vary with developed wormhole characteristics. It proposes a practical workflow to a scale up these mechanisms for field-scale simulation. First, a series of mechanistic compositional simulation models at the lab scale is constructed to model a cyclic solvent injection scheme (CSI). These models are calibrated against experimental measurements of solvent diffusion measured in porous media. Next, a set of detailed high-resolution (fine-scale) simulation models, where both matrix and high-permeability wormholes (modeled as fractal networks) are represented explicitly in the computational domain, is constructed to model how the solvent propagates away from the wormholes and into the bypassed matrix. Flows of solvent and oil in the matrix and wormholes are directly simulated. Following this, a dual-permeability approach is adopted to facilitate the scale-up analysis, where wormhole intensity is correlated to shape factor and apparent dispersivity. Characteristics at different averaging scales (i.e. scale-up level) are examined. Field-scale simulation are constructed using average petrophysical and fluid properties extracted from several CHOPS reservoirs in Saskatchewan, which are, to some extent, similar to those found in the Orinoco Belt. The initial conditions in terms of fluid saturations, pressure distribution and wormhole development are representative of those commonly encountered at the end of CHOPS. Solvent transport and mixing in the wormhole networks can be captured by parameters such as shape factor and apparent dispersivity in an equivalent coarse-scale dual-permeability system. Effective dispersivity increases with averaging scale and wormhole intensity. Considering identical surface solvent injection rate, effective dispersivity would enhance oil production and reduce gas production due to an increase in mixing between solvent and oil. Several solvent injection blends are evaluated to maximize recovery efficiency. Field-scale simulations are typically performed with grid block sizes that are much larger than the wormhole scale, and numerical analysis is often performed by arbitrary adjustment of dispersivity. This work offers a practical way to scale up solvent transport mechanisms in post-CHOPS applications. It facilitates more efficient and accurate assessment of solvent transport from lab measurements to field applications. This work serves as a starting point for formulating a systematic workflow to simulate solvent processes in wormhole networks that span over multiple scales.
- South America (1.00)
- North America > Canada > Alberta (0.99)
- North America > Canada > Saskatchewan (0.89)
- North America > United States > Texas (0.69)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Energy Efficiency Scenarios Following the Energy Trilemma - Argentina's Commitment to COP21
Cervantes-Bravo, R.J.. J. (Universidad Nacional de Ingenieria) | Ñaupari-Barzol, H.. (Universidad Nacional de Ingenieria) | Jimenez-Nieves, E.T.. T. (CORE Energy) | Magnelli, D.. (ITBA) | Dabrowski, A.. (Consultant)
Abstract Energy efficiency in the framework of the energy trilemma will guide to energetic policies focused on economic growth and development of the Developing Countries. Many of the International Organizations: such as the International Energy Agency (IEA) agreed to promote the rational use of the expressed sources in reducing energy intensity to mitigate accelerated climate change through the reduction of CO2 emissions as agreed at COP21 in Paris. The transition from Oil to Natural Gas in Argentina was marked in the years 1994 - 1999, because of an intense productive activity, causing an exponential increase in consumption. Although, if the Natural Gas less pollutant than oil, currently, the change in the matrix, did not report a reduction of C02 as expected due to the lack of technology and the rational use of these sources as energy. This implied that currently, the share of fossil fuels in the energy matrix more than 84 % above dealer, with nearly 51.1 % of Natural Gas. Therefore, the study focuses on the energy security of Argentina's growing energy demand and environmental Commitments; through, increased energy efficiency with the assumptions in reducing Energy Intensity towards a more sustainable energy trilemma to the medium and long term. It is worth mentioning that the reduction of the total demand of a country is associated with levels of energy efficiency. In our case, by 2035 an increase in energy efficiency of 19% could we reduce demand 36%; that is, a reduction in energy intensity of 29 % compared to 2015. The scenarios with reduction in energy intensity by 2035 are 1 %, 1.5 % and 2 % annually, which will involve a reduction in the consumption of primary sources and consequently a reduction in CO2 emissions of 5.3%, 14.4% and 20.2% respectively in each case. In this way, we could diversify the energy matrix progressively, towards more sustainable developments. To project the demand for primary sources from 2015 to 2035, it is necessary to design a macro-econometric model, based on an annual GDP growth of 2.77% and the projection of energy intensity according to 3 proposed scenarios. Then the relationship population country / world, will enable us to project the maximum allowable CO2 emissions by 2035, with a commitment not to increase the temperature more than 2 °C by 2100 and the commitment of Argentina with COP21 to reduce 15% CO2 emissions by 2030. Finally, the overall objective of the research will be to adjust energy policies of the country in the medium and long term through of the Evolution of Energy Matrix Primary versus the Evolution of Energy Efficiency, under the precept of securing the demand and comply with COP 21 under a more sustainable energy trilemma.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.31)
Abstract Fast simulation algorithms based on reduced-order modeling have been developed in order to facilitate large-scale and complex computationally intensive reservoir simulation and optimization. Methods like proper orthogonal decomposition (POD) and Dynamic Mode Decomposition (DMD) have been successfully used to efficiently capture and predict the behavior of reservoir fluid flow. Non-intrusive techniques (e.g., DMD), are especially attractive as it is a data-driven approach that do not require code modifications (equation free). In this paper, we will further enhance the application of the DMD, by investigating sparse approximations of the snapshots. This is particularly useful when there is a limited number of sparse measurements as in the case of reservoir simulation. The approach taken here is the snapshot-based model reduction, whereby one computes a sequence of reservoir simulation solutions (e.g., pressures and water saturations in the case of two-phase flow model) forming a big data matrix – we call this the offline step - that is used to compute basis for representing the states of the system for different input parameters – the online step. The selection of these few basis is the core of the model reduction methods. DMD selects the basis and apply the reduction without knowledge of the inner works of the reservoir simulator, as opposed to the POD methods. Sparse DMD has been introduced recently to determine the subset of the DMD models that has the most profound influence on the quality of the approximation of the snapshot sequence. Two model reduction process are involved. One is offline process, which does not require running the simulator but rather predicting future behavior with linear combination of DMD modes. The other online process incorporates sparsity DMD modes in numerical simulator to release the burden of linear matrix solver. We first show the methodology applied to a 3-D single phase flow problem. Here we show the DMD modes and its physical interpretations, and then move to two phase flow for 2-D heterogeneous reservoir using the SPE-10 benchmark. Both online and offline process will be used for evaluation. We observe that with a few DMD modes we can capture the behavior of the reservoir models. Sparse DMD leads to the optimal selection of the few DMD modes. We also assess the trade-offs between problem size and computational time for each reservoir model. The novelty of our method is the application of sparse DMD, which is a data-driven technique and the ability to select few optimal basis for the case of reservoir simulation.
Abstract The Papagayos formation in the Cuyana Basin, Argentina is one of the most prolific and mature reservoirs in the YPF portfolio. Currently it has a 98% water cut with an estimated recovery factor of 56%. The challenge was to determine if there was untapped oil in the field and subsequently how to economically extract it. To identify the source of the current oil production and potential new oil, well logs on infill wells were analysed. We also constructed a full field dynamic model that was history matched to production rates, RFT’s, gradient surveys and compared to historical water saturations identified on infill wells. To reduce uncertainty and to confirm the mechanism by which oil remained in the subsurface, we cross referenced the results of the simulation model against lab 2D visual cells filled with glass spheres to reproduce any trapped oil seen in the simulation. Well logs saw oil at the top of the reservoir; however it was not known if this oil was mobile. With the parameters history matched, the simulation showed the presence of mobile attic oil underlain by a water saturated zone swept by the aquifer. The simulation also demonstrated that the reservoir has multidarcy permeability; hence water coning would be a major issue to consider. The simulation model enabled an estimation of the aquifer strength and demonstrated that it would have a major impact on any recovery process. Simulations were made to determine if the aquifer could be either used to assist any new recovery process or otherwise if it could be subdued. Multiple EOR options were considered to exploit this remaining attic oil, however the most economic option was to augment the aquifer by injecting water on the flanks. Lab results corroborated the simulation and showed that attic oil could be a result of both coning and the structure of the reservoir. Also it was seen that increasing water injection rate into the 2D visual cells (augmenting the aquifer at high water cuts) lead to an increase in oil recovery. Despite a strong aquifer and both high water cuts and recovery factor, it was possible to identify and develop economic oil by applying an integrated modeling methodology. The model demonstrated that augmenting the aquifer is easier than fighting it by applying an EOR approach that requires massive injection to overpower the aquifer. Linking simulated reservoir response to 2D visual cell displacements demonstrated the effectiveness of flank water injection in increasing oil recovered.
- Geophysics > Borehole Geophysics (0.70)
- Geophysics > Seismic Surveying (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.76)
- South America > Argentina > Mendoza > Cuyo Basin > Vizcacheras Field (0.99)
- South America > Argentina > Cuyana Basin (0.99)
- South America > Argentina > Mendoza > Cuyana Basin > Barrancas Field (0.93)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract Drilling with Casing (DWC) has been used in over 500 strings in the last 5 years in Argentina and Bolivia. The objective of this paper is to summarize the experiences and share the lessons learnt in those years from the perspective of casing connections manufacturer. Within this paper several cases where drilling with casing technology has been used in Argentina and Bolivia. For each case there will be an explanation of the drivers behind the use of the technology, the challenges that arose during the field implementation and the lessons learned. Special attention will be given to the casing connections, the tools and services required and the limitations. In Argentina and Bolivia drilling with casing has been used in extensively, in mature fields and shale applications. In all cases the objective was to reduce cost and improve efficiency during drilling. However the drivers where not always identical, in some cases the technology aimed to overcome drilling difficulties as wellbore stability and circulation loss; in others reduce NPT and increase efficiency. The analysis of the experiences with drilling with casing technology indicates that there are two critical stages for the project: engineering and field operation. In the first, the analysis of fatigue, torque and buckling shall be done properly to reduce risks and hazards, being fatigue the less known and more difficult to assess. Regarding the second, the experience shows that improper handling and use of connections could lead to sudden and unexpected failures compromising the project sustainability. The results are summarized in a list of recommendations. The experiences from the field have led to the development of specific tools and services aimed to extend the benefits of the technology to other areas. Furthermore, the data collected will shape the design of next generation of casing connections. A guideline to select and operate casing connections in drilling with casing applications based on extensive field experience.
- South America > Bolivia (1.00)
- South America > Argentina > Patagonia (0.28)
- North America > United States > Texas (0.28)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
Abstract In the study of fractured systems petrophysics, the concept of relative permeability is of primary importance as it integrates into a characteristic curve, the net effect of complex interactions between matrix, fracture and fluids as a function of the state of saturation. In most practical applications, this curve is assumed invariant to the state of stresses and / or to the relative magnitude of viscous and capillary forces, normally represented by the capillary number concept Nc. In coupled simulation schemes, some approaches incorporate geomechanical effects to petrophysical attributes such as absolute permeability, porosity, fracture width and fracture permeability and others; incorporate variable capillary number to the relative permeability functions. In a practical sense, the assumption of invariant Kr with the stress and / or the capillary number actually simplifies computational requirements but can underestimate known physical effects that variable stress regime and variable viscous-capillary forces field induce over multiphase flow and of special relevance in the context of naturally fractured reservoirs subject to fluids injection and production. In this work, results of water-oil relative permeability curves, measured over a single fractured Berea core by the unsteady state JBN method, with variable hydrostatic effective stress and capillary number are shown. The aim of the present study is to advance towards the prediction of complex dynamics in systems were matrix-fracture deformation occur due to stress changes, and variable flow regime exist as a function of relative variations of the field of viscous-capillary forces across the reservoir. The methodology is based on the exploration of the variations of Corey relative permeability parameters with both hydrostatic effective stress and capillary number outlining that literature reports studies about the independent effect of these two variables but not of its combined effect. Results to date indicate that the features of relative permeability curves of fractured rocks (e.g. ranges of mobile saturation, curvature, endpoints) get modified when changes on the effective hydrostatic stress, the capillary number or both are induced. It is herein proposed, that the degree and configuration of the variation of the curves with respect to a reference curve is a function of the level of flow transfer between the matrix and fracture which in turn is determined by the relative incidence of the capillary, viscous and deformation effects over both domains. Further phases of the investigation shall include additional variables such as anisotropic stress regime, other types of fractures and wettability conditions towards the derivation of empirical correlations for Kr prediction.
New Methodology for Pore Pressure Prediction Using Well Logs and Divergent Area
Velázquez-Cruz, D.. (Instituto Mexicano Del Petróleo) | Espinosa-Castañeda, G.. (Instituto Mexicano Del Petróleo) | Díaz-Viera, M. A. (Instituto Mexicano Del Petróleo) | Leyte-Guerrero, F.. (Instituto Mexicano Del Petróleo)
Abstract The pore pressure prediction is the most important process in the design of drilling wells. This paper depicts a new methodology to analyze pore pressure based on both, the normal compaction theory of sediments and the way that normal behavior diverges when it is interrupted. Much has been written on the topic; however, even today a high percentage of non-productive time (NPT) in drilling activities is related to pore pressure and wellbore instability problems. Here, a new methodology is proposed to improve the accuracy of calculated pore pressure from well logs and seismic data. Moreover, this new methodology allows, under specific conditions, to determine pore pressure in carbonates and other reservoir rocks. The compaction process defines the normal trend of porosity indicators with depth, the fluid retention depth and those rock bodies diverging from a normal compaction trend. The divergence detection procedure includes the identification of both, transitional changes of the porosity indicators (shale) and those that are parallel to normal compaction trend (reservoir rock); they allow to build a divergent area. When the divergent area is defined, the pore pressure calculation can be done using a pore pressure model based on normal compaction theory and well logs or interval velocity data from seismic. Misleading prediction of geopressures for a particular area are linked to: misunderstandings of pore pressure origins there, the limited scope of pore pressure models based on well logs and to miscalculations of the key parameters of pore pressure models. This work discuss the impact of these key parameters in the pore pressure prognosis. Analysis of actual cases showing the impact of miscalculation of overburden stress on pore pressure estimations, normal compaction trend definition and pore pressure calculations are presented using divergent area along with the Eaton model. The conclusions support the following statements: well log density data cannot be used to calculate the overburden pressure and under some conditions, the divergence methodology can be used to calculate pore pressures in carbonates. Furthermore, the divergent area method eliminate the use of shale points in pore pressure prognosis.
- North America > United States (0.46)
- North America > Mexico (0.30)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.48)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.56)
- North America > Mexico > Tamaulipas > Burgos Basin (0.99)
- North America > Mexico > Nuevo Leon > Burgos Basin (0.99)
- North America > Mexico > Coahuila > Burgos Basin (0.99)
- (4 more...)
Reduction of Opex Costs and Increase of Oil Production by Means of Production Deferment and Pump Failure Prevention with a Cost-Effective Well Monitoring System
Armacanqui, Samuel (CeO Gaia Energy Resources) | Eyzaguirre, Luz (Universidad Nacional de Ingeniería) | Lujan, Cesar (Universidad Nacional de Ingeniería) | Tafur, Yeltsin (Universidad Nacional de Ingeniería) | Marticorena, Harol (Universidad Nacional de Ingeniería) | Rodriguez, José (Universidad Nacional de Ingeniería) | Paccori, Hancco (Universidad Nacional de Ingeniería) | De La Cruz, Ruben (Universidad Nacional de Ingeniería) | Yataco, Sheyla (Universidad Nacional de Ingeniería) | Sueldo, Freddy (Universidad Nacional de Ingeniería) | Cuestas, Francis (Universidad Nacional de Ingeniería)
Abstract A system of well monitoring in real time was developed, that is cost-effective and reliable. It allows the the obtained the real time data gattering. Among the advantages of this system is the low price and effectiveness; as it uses low cost electronic components and an inexpensive communication network. The main electronic components used, are the Arduino controller and the wireless information transmitter using the free bandwidth in the world: 2.4GHz, which allows programming a more effective communication network (ZigBee Network); the power supply is based on photovoltaic cells (5V). The ZigBee Network Technology achieved its goal of keeping all interconnected points. The limited range of the transmitters (1500m) was overcome by the use of interconnected network points, which can build a grid to cover the entire field. The tested prototype was composite of four points in a transmition station – simulating a control room The system is based on good quality and low cost equipment, that aims to reduce the production deferment and artificial lift equipment failures; by the implementation of a system that generates alerts according to the monitored parameters.
Abstract Well integrity undeniably is considered one of the most important topics of the petroleum industry. Failure in not keeping a well integrity system functioning adequately may result in disastrous accidents called blowouts with all tragic consequences that they may bring: loss of human lives, loss of drilling equipment or production facilities, loss of hydrocarbon reserves and pollution. Also, well integrity issues may lead to substantial financial losses during the entire well life cycle as a result of non-productive operational time and/or remedial solutions. The situation is aggravated when considering deepwater scenarios. Unfortunately, in 2010 the oil industry faced its worth accident caused by the loss of well integrity: the blowout of Macondo in the Gulf of Mexico with devastating consequences to the oil industry. The accident has been demanding from all players (operators, drilling contractors, service companies, regulators, industry organizations, academia and training providers) a huge amount of effort to minimize the risk of having this kind of accident repeated. Originally, those efforts were aimed at deepwater drilling activities in the Gulf of Mexico but with time they were disseminated throughout the oil industry activities all over the world. Significant progress has been done to enhance the safety during all phases of the well life cycle since the Macondo blowout. This paper intends to present and discuss with actual examples the latest technical and managerial developments with emphasis in deepwater situations since the tragic blowout of Macondo happened. Particular attention is given to the following aspects: operational guidelines, regulations, well control equipment, training and competency assurance, well integrity management systems, novel technologies and research.
- Instructional Material (0.49)
- Research Report (0.48)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 252 > Macondo Field > Macondo 252 Well (0.89)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Horizon Oil Sands Project (0.89)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Pressure Management > Well control (1.00)
- Health, Safety, Environment & Sustainability > Safety > Operational safety (1.00)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > Contingency planning and emergency response (1.00)