Analytical single well models have been particularly useful in forecasting production rates and Estimated Ultimate Recovery (EUR) to the massive number of wells in unconventional reservoirs. In this work, a physics-based decline curve model accounting for linear flow and material balance in horizontal multi-stage hydraulically fractured wells is introduced. The main characteristics of pressure diffusion in the porous media and the fact that the reservoir is a limited resource are embedded in the functional form, such that there is a transition from transient to boundary dominated flow and the EUR is always finite. Analogously to the frequently used Arps hyperbolic, the new model has only three parameters, where two of them define the decline profile and the third one is a multiplier.
This model is applied to a large dataset in a workflow that incorporates heuristic knowledge into the history matching and uncertainty quantification by assigning weights to rate measurements. The heuristic rules aim to lessen the effects of non-reservoir related variations in the production data (e.g. temporary shut-in due to fracturing in a neighboring well) and emphasize the reservoir dynamics to perform reliable predictions. However, there are additional degrees of freedom in the way these rules define the values of the weights, therefore a criteria is established that "calibrates" the uncertainty in the probabilistic models by adjusting the parameters in the heuristic rules. Uncertainty quantification and calibration is performed via a Bayesian approach with hindcasts. This methodology is implemented in an automated framework and applied to 992 gas wells from the Barnett shale. A comparison with the Arps hyperbolic, Duong and stretched exponential models for this dataset shows that the new model is the most conservative in terms of estimated reserves.
Unconventional reservoirs such as the Vaca Muerta formation in Argentina continue to be an important source of oil and gas, and represent a vital source of energy for specific segments of the global market. Achieving technical and financial objectives when developing such reservoirs requires operators to manage operational costs while still obtaining sufficient geological, petrophysical, and geomechanical information to successfully evaluate and develop the reservoir. In a recent Vaca Muerta exploration well, LWD resistivity and azimuthal sonic measurements were combined with advanced mud gas analysis of C1 to C8, toluene, and benzene gas components. These two data sources, acquired while drilling, were used in an integrated petrophysical analysis which characterized the stratigraphic variation of key reservoir parameters and geomechanical properties to identify sweet spots for further horizontal well development.
Geomechanical analysis from azimuthally oriented LWD slowness measurements revealed stressinduced anisotropy by identifying the splitting of shear slowness around the wellbore. The comparison with wireline sonic and micro-imaging tools in the same well confirmed the relatively isotropic acoustic response (2-3 % anisotropy) in the upper section and a more anisotropic acoustic response (7-9 % anisotropy) in the lower section of the Vaca Muerta. Additional mechanical properties such as elastic moduli were calculated to evaluate fracability, and the unconfined compressive strength (UCS) was correlated to the mechanical specific energy (MSE) from drilling mechanics measurements to monitor drilling efficiency.
Mud gas ratio analysis revealed variations in reservoir thermal maturity, identifying wet gas and dry gas intervals, while LWD resistivity and sonic data were used to compute TOC (using the Passey overlay method), porosity, and water saturation. The key reservoir quality parameters (TOC, porosity, water saturation, thermal maturity, and clay volume) were then combined with geomechanical properties (Poisson’s ratio, Young’s modulus, and UCS).The resulting interpretation provided a continuous evaluation of the entire Vaca Muerta sequence, facilitating zonation and selection of potential landing points for horizontal development wells.
This comprehensive evaluation from the integration of the LWD azimuthal sonic and advanced mud gas analysis demonstrated a cost-effective solution to characterize the formation which enhances real-time decision making, and provides the basis for optimizing well placement and completion strategies in the Vaca Muerta formation.
This study focusses on the impact of wettability alteration of reservoir clays on the overall efficiency of Steam Assisted Gravity Drainage (SAGD). Samples from two SAGD experiments were investigatedSAGD1, consisting of kaolinite in the oil-sand packing and SAGD2, consisting of a mixture of kaolinite (90 wt%) and illite (10 wt%). The residual oil saturation from two different zones (inside steam chamber and steam chamber edge) from each SAGD experiment was determined from spent rock samples. Series of systematic optical microscopy analyses were carried out on clay-sand and clay-sand-asphaltene mixtures under steam and water exposure to represent the inside steam chamber zone and steam chamber edge, respectively. The higher residual oil saturation for SAGD2 was associated with the wettability alteration of illite in the reservoir at the steam chamber edge, leading to significant illite-asphaltene association. The pore-bridging property of illite was also observed, adversely affecting reservoir permeability. Kaolinite-asphaltene interactions in the presence of liquid water, on the other hand, were found to be temporary and not binding. Our findings suggest that wettability of clays plays an important role in determining the efficiency of SAGD process, controlled mainly by the polar asphaltene fractions in bitumen reservoirs with high asphaltene concentrations.
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)
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.
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
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.
This paper presents a case study focusing on the identification of CO2 in the Hollin reservoir, based on nuclear magnetic resonance (NMR) responses, its effect on petrophysical parameters, and the negative effect on production wells. The paper also discusses the strong relationship between the high CO2 concentration in the reservoir fluids and its effect on the formation damage resulting from pore throat plugging from organic and inorganic compounds.
After NMR processing, it was possible to identify the CO2 response on porosity related to low hydrogen index; the PVT analysis reveals approximately 75% of CO2 in the reservoir conditions and more than 95% of CO2 in the surface conditions. Asphaltene stability was evaluated through four methods, including the Leontaritis method, colloidal stability index, Stankiewicz method, and stability crossplot (SCP), which enabled the determination of an unstable probability by more than 75%. Palo Azul wells have been completed with production enhancement techniques, such as fracturing, to minimize the formation damage and its negative production effect; until now, however, the unique hypothesis considered formation damage to be related to fine-grain migration without considering that the primary problem could be connected to asphaltene stability. The deposition of the asphaltene can plug pore throats, reducing wellbore permeability and dramatically reducing fracture wings conductivity.
This case study provides several important contributions. First, NMR results were successfully used in the Oriente basin of Ecuador to identify reservoirs with high concentrations of CO2. Second, four different diagnostic methods were used to determine asphaltene stability; this has altered common paradigms regarding production reservoir behavior. Finally, this case study enabled the development of a new technical hypothesis concerning additional factors that can contribute to formation damage in the Hollin reservoir.
Exploration and production of heavy and extra heavy oil have always presented challenges that gradually have been overcome by reservoir engineers through the application of new technologies like downhole heating and diluent injection. However, it is recommended to conduct pre-assessment studies of these technologies in order to optimize resources associated with the implementation phase and subsequently with a large scale implementation of these technologies in the field.
One successful example where this pre-assessment study was applied, is the one performed in the Huyapari field located at the Orinoco Oil Belt, currently with more than 600 active horizontal wells where the productivity of the wells could be affected by the frictional pressure losses in the horizontal section. This is the reason why the main objective of this paper is to develop a reliable methodology to conduct a pre assessment study of the downhole heating cable technology by the integration of different methodologies such as analytical and deterministic analysis, operational evaluation, and numerical simulation.
Based on the results of the implementation of a downhole heating cable in the A-P10 well (producing with downhole heating cable since 2005) and the representation of these results by numerical simulation, it was established a procedure that takes into account the characteristics of the reservoir and some operational variables. The response in production of this well due to a slight increase in temperature in the horizontal section was evaluated through numerical simulation. Some other parameters such as changes in viscosity vs temperature, frictional pressure losses in the horizontal section, heating time were also investigated.
This procedure allowed the selection of the most prospective wells to install this technology, among more than 200 horizontal wells in the same reservoir; just 30% of the wells met all the requirements. This selection methodology added value to the well optimization strategy of the field saving considerable resources.
In conclusion, this study helped to represent the performance of the well when it has undergone a stimulation with a downhole heating cable, allowing to quantify the barrels associated with cumulative production and the developed reserves in different scenarios. This result could be of great importance for the Orinoco Oil Belt with its more than 297 MMMBP that represents today the largest accumulation of reserves of heavy and extra heavy oil in the world.
This paper presents a comprehensive perspective for comparing field development strategies (i.e. setting up oil field for production) by outlining a simple approach to help the integrated asset team in making decision on which method would be most appropriate. The field development options considered were natural depletion, water injection, gas injection, and water alternate gas (WAG).
UBED field was discovered in 1974, water depth is 130 m with initial reservoir pressure of 446 bars and 35,681,991 m3 estimated oil initially in-place (OIIP). Preliminary assessment using the material balance indicated about 25% ultimate recovery. Each scenario was optimized for maximum hydrocarbon recovery at the lowest cost per barrel by optimizing of wells, and critical gas saturation (i.e. 0% and 10% respectively). Economic analysis was performed using NPV, profitability index, payback period, and IRR on the cases. For each scenario, a plateau rate of 15% is maintained per year at a production rate of 3500 m3/d as benchmark.
The various economic impacts on the project were determined and the results are presented. Results shows that estimated ultimate recoveries (EUR) were 30.9%, 53%, 37.2% and 53.5% for natural depletion, water injection, gas injection, and water alternate gas injection schemes respectively. The best production option for UBED reservoir lies between water injection and WAG injection. The comparison between the two scenarios shows that WAG is less costly and to develop the reserves while recovery, and profits are very high. Production plateau can also be sustained economically for longer period with shorter pay back on investment. In addition, WAG shows better EUR, a shorter production plateau of about 4% increases in over the water injection. This increase was not offset by profit indices, and payback. In this scenario, a gas compressor was installed which resulted in an increased capital expenditure (CAPEX).
The revenues, expenses, and profits from each scenario are compared for the various development options at the end of the section and a proposed plan is selected based on economic parameters. The comparative economic assessment of the UBED field case in this study adequately addresses critical cost parameters relevant to field development studies, and integrated comparison of profitability indicators from which reliable economic decision can be reached.
Sustainability defines itself with preserving the natural resources, while maintaining a sustained rate of economic growth. Latin American countries are rich in natural resources and this has created an opportunity in exploiting the resources in order to gain economic advances. In particular, the newly rising economic powers in the region are attracting international investments in their oil exploration and production industries. Brazil, Venezuela and Columbia in South and Mexico in North America are among the largest Latin American oil producers of the world.
On the other hand, the increasingly concerning effects of the climate change phenomena has drawn significant attention towards methods of controlling the roots of the problem. An important cause as confirmed by the historic emissions data is the man-made Greenhouse Gas emissions resulting from excessive use of fossil fuels, and more importantly the carbon-intensive coal and oil.
In this paper, we investigate the possible impacts of an emission control system on Latin American oil producers to control the rate of emissions through a financial market which is referred to as the carbon market. Variations of this system has successfully been implemented in the Europe and some states of the US, such as the state of California. Our approach is based on the system dynamics methodology where the main factors of a complex system are extracted and their causal relations are exploited to obtain mathematical models that can explain the behaviors of overall system. What makes the system dynamics approach very appealing for our purpose is the tools that this method provides towards policy testing which is the particular focus of the current paper. We extend our previous models to fit the Latin American economies focusing on the sustainability issues.
The purpose of this paper is to present the analysis to the applicability of Coiled Lift (Coiled Tubing) as a method of optimization of artificial lift system in El Furrial Field, which is located 25 km from the city of Maturin. It is defined with 3 volumetric reservoirs with an API gravity of 25 ° average. As a result of the energy decline was initiated from 1992 a process of secondary recovery by water injection and miscible gas injection.
In recent years the number of wells with high water cut increased in El Furrial field associated with the direct influence of water injection wells, which meant an increase in the density of the fluid column. All this, in addition to the high decline in reservoir areas originated below the limit of influence production by the natural flow method, which required the implement methods of gas lift by conventional methods (Mandrels and valves) and unconventional (punching of production tubing and Coiled Lift) thus achieving maintain production levels successfully in order to fulfill productions commitments.
The experience gained during the massification of artificial lift by punching production tubing in El Furrial Field in the period 2013 to 2015, indicates that there are currently producing wells present flow instability due to low submergence of the dynamic fluid level relative to the point of gas injection operation, loss of lift efficiency due to decreased of reservoir pressure and increased water cut which causes charging problems and sliding fluid, and slow velocity of the free gas phase inside the well. All these variables were studied from the behavior of surface conditions and production, production loggings information, vertical profile of temperature and pressure, visualization of new infrastructure for handling fluid with lower surface pressure. This allows sensitivities components production system wells, determining that the optimum production method applied is the GL by Coiled Gas Lift, as this technique allows deepening operating point, decrease flow area of the well which in turn causes increased speed of liquid and gas phases of stabilizing the flow rate and minimizing sliding liquid. Under the methodology implemented, it has been possible until December 2016 to complete 16 wells Coiled Gas Lift System with increased oil production of 170,6 %.