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Abstract The Auca Mahuida Volcano and Las Manadas field produces oil and gas from the Mulichinco, Lower Centenario and Rayoso formations. However this high quality reservoir has been severely damaged due to volcanic activity. This volcanism occurred after the main hydrocarbon migration and trapping, although there are hydraulically isolated bodies related to the igneous intrusions, confirmed from pressure testing and the distribution of the fluid along the stratigraphy column. The attitude and distribution of these intrusions in the reservoir is not generally known in part due to the lack of the surface seismic over this geologically complicated area. The big challenge is to be able to accurately identify and rank the intrusive igneous features such as dykes, sills, laccolith and other geological features. A new borehole image was introduced in Argentina for oil based mud systems. It has very good coverage with 80% in 8 inch wells. It is composed of 6 pads mounted in 6 independent articulated arms, each pad has 10 sensors resulting 60 micro-resistivity measurements. This tool works on different frequencies for different formation resistivity range. Depending on the known resistivity two frequencies can be simultaneously selected to acquire two images in one single pass. Recommended logging speed is 5.5 m/min. As a result of the operations more than 2000 meters have been logged with high quality borehole imaging. In spite of hostile weather conditions and because it is a natural protected area, there were no incidents registered during these jobs. At this point of the project dykes seem to follow pre-existing fractures to intrude the formations so the recognition of the fracture attitude is very important to prevent those intrusions at depths where the oil and gas is trapped. This information was considered as a high value to improve the existing geological model, providing knowledge about the complex net of intrusive bodies by the accurate recognition of the type of intrusion and its attitude close to the borehole.
- Phanerozoic > Mesozoic > Cretaceous (0.47)
- Phanerozoic > Cenozoic (0.47)
- Geology > Rock Type > Igneous Rock (1.00)
- Geology > Geological Subdiscipline > Volcanology (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- (2 more...)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Venezuela > Zulia > Lake Maracaibo > Maracaibo Basin > Lama Field (0.98)
- South America > Argentina > Neuquen > Neuquen Basin > Las Manadas Field (0.98)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Mulichinco Formation (0.94)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Borehole imaging and wellbore seismic (1.00)
Abstract Liquid loading is a significant issue within gas and gas condensate wells, resulting in production decline and rate instability. The Southern Gas Field serves as a case study, to investigate a field experiencing liquid loadup. The field is located in the Southern North Sea, and is being produced via natural depletion with no pressure support from the surrounding aquifer. In Yr. 9 production well A ceased to flow as a result of liquid build up, and by Yr. 11 well B also showed signs of liquid loading. The load fluid consisted of liquid condensate, and this was confirmed by wireline investigations. A decision was made by the operator to deploy two 2 3/8" velocity strings, in an attempt to extend the field lifespan, by restarting well A and returning rate stability to well B. Velocity strings are a relatively low cost deliquification method, that aim to increase the gas flow rate above the critical flow rate, enabling the well to continuously unload liquids. The design of velocity strings is crucial, as if too small a tubing is used, the velocity string can act as a choke, suffocating the well. The velocity string run in well B proved a success, however the workover in well A failed to restart the well. Batch foamer treatments were later tried in well A but proved ineffective. The effectiveness of foam to deliquifying gas wells, depends upon the composition of the load liquid, as both water and liquid hydrocarbons react differently to surfactants. Typically liquid hydrocarbons such as condensate do not foam well, and must be agitated to maintain foaming. This study aimed to make use of Petroleum Experts Integrated Production Modelling (IPM) software to model the effect of the velocity string deployment, with regards to returning rate stability. Prosper models were created and Systems Analysis was performed and confirmed that 2 3/8" velocity strings will lift both well A and well B out of the Turner region. Prosper was also use to model the effect of using foam as an artificial lift method, with the results identifying that the water gas ratio (WGR) of the field is too low for effective deliquification using foams. A GAP model was also created for the Southern Gas Field to determine the incremental reserve gains to be had by deploying velocity strings. The simulations identified that well workovers can provide an additional 4.99 Bscf to the recoverable reserves.
- North America > United States (0.94)
- Africa > Middle East > Algeria > Tamanrasset Province (0.45)
- Africa > Middle East > Algeria > Adrar Province (0.45)
- (5 more...)
Abstract Until the recent crude and gas price decrease in late 2015, development in the Vaca Muerta shale experienced profitable production through improved methods, efficiency, and economics control. To combine public domain hydrocarbon production datasets with detailed proprietary drilling information, operators and service companies can use completion, logging, and well stimulation data. These data enable analysis of trends and improvements that occur during drilling, fracturing, and production of horizontal wells targeting both shale oil and gas in the Vaca Muerta and help provide economic, efficiency, and productivity improvements. In recent years, more than 500 wells have been drilled in the Neuquén basin in the Vaca Muerta, the majority of which are located in the Loma Campana field. Other areas under development include El Orejano, La Amarga Chica, Aguada Pichana, Sierras Blancas, Cruz de Lorena, Bandurria, Aguada Federal, La Invernada, Bajo del Choique, and Puesto Silva Oeste. As of January 2016, Vaca Muerta monthly production of oil and gas was 6.7 million bbl and 13 million barrels of oil equivalent (BOE), respectively, representing 12 and 5% of total Neuquén basin production. A database was created including 47 records of horizontal stimulated wells that target the Vaca Muerta. Each register includes information related to location [well name, latitude, longitude, ground level, total depth (TD)]; production (operator, first oil date, effective time on, monthly oil, gas and water production); drilling (casing, liner, shoes, cementing); completion (directional survey, stages, clusters, perforations, plugs); fracturing [pump time, pressure, instantaneous shut-in pressure (ISIP), fracture gradient, horsepower, fluid type, injection rate, fluid volume, proppant type, proppant mesh, proppant mass, injection rate]; and production (cumulatives, rates, decline rate, recovery estimates, flow regime). Several correlations and crossplots between variables were developed and analyzed to identify trends and establish normal and anomalous behavior. The validity of using early production to estimate longer periods was confirmed, enabling creation of a complementary series of production data with modeled forecasts and estimated ultimate recoveries. Production data were then standardized by stages, horizontal length, proppant sacks (100 lbm) pumped, and fluids injected; after this, the records were sorted by productivity to determine average standardized production and typical completion and stimulation. Observing these values over time highlights trends toward longer wells with more stages and smaller sized proppant. Simultaneously, a recent shift to shale gas objectives located slightly basinward is indicated by deeper wells, where less fluid and more horsepower were used during stimulation.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.66)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.48)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Loma Campana Field > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Loma Campana Field > Lower Agrio Formation (0.99)
- (8 more...)
Abstract In this study, the historical production of VacaMuertais evaluated aiming to capture the complexities of this formation in terms of fluids production and recovery performance. This paper integrates the Neuquén province production analysis with the objective to understand the oil and gas historical production behavior in a development area of roughly 12,000 sq mi (31,000 km).A comprehensive evaluation using public data was conducted to present the contribution and the impact of VacaMuerta oil and gas production on the region and the country. The VacaMuerta formation represents the most-challenging source of new oil and gas in Argentina, with a huge potential considering the size of the development area in any block across the basin, the reservoir gross thickness and the resulting fluids in place, and the way forward to be achieved regarding the balance between well cost reduction and productivity improvement. There have been important drilling and development efforts in the last 4 years in which both vertical and horizontal wellbore configurations have been implementedand tested over the longterm. However, there are still uncertain factors under evaluation to assess the VacaMuerta formation performance, which achieved 29 million barrels and 124Bcf in December 2016, with 674 oil and gas producer wells. The workflow focuses on the analysis of historical production for both vertical and horizontal wells, average rates and cumulative production of initial 6 and 12 months, water cut and gas-oil ratio (GOR), decline analysis and vintage performance, with the addition of heterogeneity index plots. Production history statistics and probabilistic analysis were incorporated in the study to summarize and present the evaluation results. Important aspects related to well decline behavior and estimated recovery for the initial years were also analyzed. In this paper, we present the main findings and results of a complete production analysis of VacaMuerta formation after more than 10 years of production. This paper provides an overview of the historical production performance and the key elements for production forecasting. The integration of this production information with geology, reservoir characterization, well design, and completion and operation strategies provides an essential reference to improve the understanding of the production potential and the visualization and ranking of any well, field, or area in the Neuquén basin.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock (0.94)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Loma Campana Field > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Loma Campana Field > Lower Agrio Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Loma Campana Field > Los Molles Formation (0.99)
- South America > Argentina > Neuquen > Neuquen Basin > Loma La Lata Field (0.99)
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 The Vaca Muerta shale has been developed for oil and gas production since 2010 and to date nearly 500 wells have been drilled. The large amount of static and dynamic information from these wells has enabled fracture design and production strategy optimization. This paper details the methodology used to integrate all available data in 3D models, in order to understand the impact of rock properties in the production. The model was simulated using a commercial reservoir simulator, showing that hydraulic fractures are acting as a dual porosity system with a large conductivity (~10 D) connecting a low permeability matrix (~100 nD). We studied multiple wells in the history match (HM), using separator pressure and choke size as the control variables for the wells, and rates and pressures as comparison variables. A multi-segmented well approach was used to describe the pressure drop inside the well, and a vertical lift performance (VLP) table to describe the flow from the tubing all along to the separator including the wellhead choke. The static model included the seismic interpretation, stratigraphic framework, geomechanical and petrophysical characterization. Rock permeability, initial pore pressure and total fracture pore volume were calibrated with field measurements used as constraints in the HM process. Fracture conductivity degradation was introduced in the model to explain observed changes in the wells productivity. Laboratory tests are being designed to validate these hypotheses. We established early in the project that individual well HM were not unique. It was only through the HM of multiple wells that we were able to reduce the range of uncertainties affecting well performance (matrix permeability, initial water saturation and fracture height). This has given us a more reliable tool to obtain ultimate recovery estimation ranges. The described model showed a good prediction of a well with water lift problems, giving an accurate forecast for the incremental gas rate after a tubing diameter change. We concluded that the multi-segmented well model is a good representation of the water hold-up fraction behavior. This methodology enables us to integrate all the knowledge of the subsurface into a model that can be run in short simulation time (~30 minutes), allowing us to iterate quickly during the HM process. The model can be run for single wells or multiple wells and is flexible to adapt for new areas. We plan to use this methodology to design and monitor pilots in new blocks and to evaluate different development plans for existing projects.
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- South America > Argentina > Patagonia Region (0.85)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.62)
Uncertainty Analysis for Production Forecast in Oil Wells
Monteiro, D. D. (Universidade Federal do Rio De Janeiro) | Ferreira-Filho, V. M. (Universidade Federal do Rio De Janeiro) | Chaves, G. S. (Universidade Federal do Rio De Janeiro) | De Santana, R. S. (Universidade Federal do Rio De Janeiro) | Duque, M. M. (Universidade Federal do Rio De Janeiro) | Granja-Saavedra, A. L. (Universidade Federal do Rio De Janeiro) | Baioco, J. S. (Universidade Federal do Rio De Janeiro) | Vieira, B. F. (Petrobras Cenpes) | Teixeira, A. F. (Petrobras)
Abstract The oil and gas industry is faced with uncertainty in many activities. Whereas in many of its areas, such as finance, geology and reservoirs these uncertainties are already incorporated in the modelling and studies. This is not the reality when it comes to modelling artificial lift and multiphase flow. Studies related with uncertainties in oil and gas production are limited. Therefore, this paper aims to develop a methodology to identify and quantify uncertainties, obtaining thus more accurate data to be used in production modelling. In addition, the methodology intends to evaluate oil production forecasting considering uncertainty propagation in oil flow simulation software. This study was divided in statistical analysis and production forecasting. An algorithm using R software analyzed and treated production data. It was applied statistical modelling techniques to data series. Deviations from these data were adjusted to a continuous distribution that provides the parameters to be used by Monte Carlo simulation method to generate random values to be input uncertainties of the MARLIM multiphase flow simulator. Oil flow rate, as output simulator, was adjusted to a new distribution and finally the intervals of occurrence probabilities of oil flow rate forecasts. This methodology was applied to BSW (Basic Sediments and Water) data from a representative field, showing the importance of including uncertainty analysis in order to generate greater reliability and accuracy in the production flow modeling. In conclusion, the method presented excellent results when applied to BSW.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
A Production Characterization of the Eagle Ford Shale, Texas - A Bayesian Analysis Approach
Moridis, Nefeli (Texas A&M University) | Soltanpour, Yasser (Texas A&M University) | Medina-Cetina, Zenon (Texas A&M University) | Lee, W. John (Texas A&M University) | Blasingame, Thomas A. (Texas A&M University)
Abstract We began this research by asking "Can we use Bayes' theorem to supplement available decline models and improve the accuracy of our estimates of ultimate recovery?" This study focuses on the Eagle Ford Shale, and in particular, on oil wells in the Greater Core Eagle Ford Area. Our goal was to develop a method based on a probabilistic approach to identify, characterize, and better model well production based on standard decline models To attempt to answer this question, we first obtained data for 68 wells in the Greater Core of the Eagle Ford Shale, Texas. As process, we eliminated the wells that did not have enough production data, wells that did not show a production decline and wells that had too much data noise, leaving eight wells. We then performed decline curve analysis (DCA) using the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) models (the two most common DCA models), consisting in user-guided analysis software. Then, the Bayesian paradigm was implemented to calibrate the same two models on the same set of wells. The primary focus of the research was the implementation of the Bayesian paradigm on the eight-well data set. We first performed a "best fit" parameter estimation using least squares optimization, which provided an optimized set of parameters for the two decline models. This was followed by using the Markov Chain Monte Carlo (MCMC) integration of the Bayesian posterior function for each model, which provided a full probabilistic description of its parameters. This allowed for the simulation of a number of likely realizations of the decline curves, from which first order statistics were computed to provide a confidence metric on the calibration of each model as applied to the production data of each well. Results showed variation on the calibration of the MH and PLE models. The forward models (MH and PLE) overestimated the ultimate recovery in the majority of the wells compared with the Bayesian calibrations, proving that the Bayesian paradigm was able to capture a more accurate trend of the data and thus able to determine more accurate estimates of reserves. In industry, the same decline models are used for unconventional wells as for conventional wells, even though we know that the same models may not apply. Based on the proposed results, we believe that Bayesian inference yields more accurate estimates of ultimate recovery for unconventional reservoirs than deterministic DCA methods. Moreover, it provides a measure of confidence on the prediction of production as a function of varying data and varying decline models.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.15)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.85)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Bayesian Inference (0.88)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models > Directed Networks > Bayesian Learning (0.50)
Abstract There is a well-known theoretical chart that shows how compression, scales, liquid loading, corrosion, etc. appear as a gas field decreases production due to reservoir depletion. The approach of this paper is ambitious and will demonstrate and exemplify how these problems appeared in our gas field, and share the techniques, methods, and procedures we went through to satisfactorily handle them. This paper shows the development of a gas field placed in the Golfo San Jorge Basin (Argentina) including the different life stages of the field (High/Medium/Low Pressure) with the related problems in Facilities, Flow Assurance, and Liquid Loading, and finalizes with an introduction to the future problems we are expecting. Throughout the paper, we will show the changes we went through, lessons learned, and conclusions related to the following topics: + Facilities → Slugging in flowlines/changes in suction pressure/new facilities + Flow Assurance → Chemical usage for solving organic and inorganic scales. Need of migration from bullheading treatments to CT nitrogen assisted operations. Acid stick treatments. + Liquid Loading → Foaming agents/Velocity Strings/Capillary Strings/Wellhead Compression + Tendency of Scales Evolution in produced water. + Evolution of tubing metallography + New approaches in PLT interpretation Not many papers cover in such an integral way the development of a conventional gas field with a large exploitation history as this work does, where the field dates from the 2000s. This paper sets a reference and fills a gap in terms of an overall look at all problems together, and integrates the theory from the literature, information from field experiences, best practices, and the application of new technologies/methodologies. Challenges for future exploitation are presented as well. Reading this paper will help in understanding the complexity that those people involved in the management of a gas field will face as their reservoirs deplete and the production of the wells goes down.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Sierra Chata Field (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > Trahuil Field (0.99)
Abstract The Lajas formation in the Neuquén Basin, Argentina, has been identified as a key opportunity to supply the gas requirements of the Argentine economy. A number of fields are currently being developed in this formation with an ongoing exploration program likely to yield more discoveries. Maximizing the value of existing and new assets was the task at hand. To optimize the development, dynamic models were needed to produce forecasts for different development scenarios. One of the main issues to solve was how to represent in commercial dynamic software the hydraulic fractures and their interaction with a low permeability formation. The optimum approach to model induced fractures had to be identified. Additionally, flow tests of wells were infrequent and often gave contradictory results. Hence we explored a number of different options for controlling the history match and forecast such as controlling by gas rate, tubing head pressure and back pressure through the choke. We concluded that dual porosity modeling of the fractures offered an acceptable balance between computational overhead, absolute accuracy and flexibility. The main parameters adjusted to achieve the history match were the fractures half length, height, volume and conductivity/permeability that ruled the early behavior of the wells and the matrix permeability that conditioned their longer term productivity. Controlling the wells in the history match was found to be best achieved by control through the choke and line pressure. Tubing head pressure as well as gas and water simulated rates were cross checked against historical data. The vertical lift performance modeling of the wells was also found to be critical to achieve the history match. The pressure drop in the wells was modelled by lift curves from the well head to the first perforation and by segments from there onwards to understand their liquid loading. All this had to be taken into account due to the fact that wells were impacted by tubing, choke and line pressure changes through their production history. It was possible to optimize Lajas gas development by applying an integrated modelling methodology linking geology, reservoir and production engineering. The model helped justify new infill locations and estimate the difference in productivity between different Lajas geological sequences. The dynamic model results were compared with the outcome of other forecasting methods such as DCA Tipe Well, RTA and layercake dynamic models.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Neuquen > Neuquen Basin > Barrosa Norte Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Asab Field > Thamama Group Formation (0.99)