This paper describes the processes incorporated during the simulation study of the Chihuido de la Sierra Negra Field in Argentina, which is presently the largest oil field in the country. The field was discovered in 1968, and an aggressive water injection program was started in 1995. So far the oil production from this field is 65 million cubic meters and the water injection is 158 million cubic meters. The field has two separate stacked reservoirs that are structurally complex with different fault systems and fluids. Both reservoirs are highly compartmentalized with each compartment having different water-oil contact. The upper reservoir is composed of 6 isolated geologic layers, with each being different depositional environments (sand bars, dunes, fluvial channels, etc.). The presence of unconformities and volcanic intrusions further complicate the reservoir communication and plays an important role in flow behavior. Currently, the field has 734 production wells with commingled production from both reservoirs and the isolated zones with in the upper reservoir. Approximately 1250 injection strings are currently injecting water. The purpose of this study was to provide a detailed reservoir characterization to optimize recovery and to create a simulation model with predictive capability that can be used in improving field management. To achieve this purpose a 900,000 cell simulation model was constructed. This paper will discuss some of the challenges encountered during the history matching of the field model. The identification of the compartment boundaries and their associated water oil contacts (57 contacts) required the development of a new consistent approach. This method provided significant accuracy and time savings over the traditional approach of iterating between history matching and reservoir characterization. The overwhelming volume of data and the volume of simulation results for 2200 well strings required special considerations for pre- and post-processing. New tools were needed to quickly modify the simulation arrays and review all the wells in an efficient and timely manner. As the history matching progressed many additional practical tools were developed. This paper will discuss the significance of these innovations and tools to achieve a successful history match in a timely manner. Introduction Chihuido de la Sierra Negra is the largest oil field in Argentina. It is located in the Neuquén Basin at 200 km Northwest of Neuquén City (Fig. 1) This field has three main clean sand reservoirs within the Lower Cretaceous Huitrin formation1. These are the Troncoso Inferior, the Agrio Superior and the Avile members. The measured depth where the producing intervals are located varies from 1100 to 1300 meters. The whole productive oil column is divided into ten (10) geological layers extended in a gross thickness of 200 meters. Fig. 2 shows the geological members and the layers present in this field. The shallower reservoirs (~1100 meters measured depth) Troncoso Inferior and Agrio Superior account for 60% of the ultimate recoverable reserves of the field. The depositional environments in the Troncoso Inferior Member include Aeolian dunes (5T and 4T intervals) and fluvial channels (3T and 2T). The middle portion of the productive column (Agrio Superior) is formed by marine sandbars (3A, 2A, 1A and 0A). The detailed reservoir characterization showed that an unconformity surface exists between the Troncoso Inferior and Agrio Superior members. During the simulation study the unconformity surface was verified to be a flow barrier between the two members. The deepest reservoir, Avile Member, is found at ~1300 meters (MD) and is composed of very productive Aeolian sand dunes. All the geological layers are isolated except 5T and 4T. Certain igneous sheets (volcanic intrusions) were correlated using the well logs that were available in the study area (Gamma Ray, Induction, Density and PEF). These identified intrusions have the potential of modifying the communication throughout the field. Fig. 3 shows an example well log with identified volcanic intrusions.
The El Trapial field is a 1.2 B bbl OOIP asset located onshore in Argentina, South America. The field was discovered in 1991. Water injection started in 1993 with current infill drilling and development of some areas still taking place. This field consists of several sandstone reservoirs with average permeability and porosity of 75 mD and 17% respectively. One unique challenge of El Trapial field is that the light oil coexist with gas that contains high CO2 concentrations, greater than 75%. This is observed in both dissolved gas and in gas caps in various blocks of the field. Well documented production data have indicated variations in CO2 concentration in different areas of the field. Conventional fluid modeling could not explain the formation of gas caps at dissimilar structural positions, nor could it explain the existence of oil legs at pressures below the apparent (predicted) bubble point pressure. A fluid characterization model was performed in the El Trapial field in order to improve the understanding of the PVT behavior at reservoir conditions in the presence of the original high content of CO2. An empirical model was created using the assumption that thermodynamic equilibrium was reached before the time of exploitation. This model shows that the bubble point pressure can increase with depth when light oil coexists with high concentrations of CO2, showing an opposite behavior to what is observed when the gas phase is mostly hydrocarbons. Sensitivity analysis was conducted to identify the key variables that impact this distinctive behavior. The developed model improved the understanding of the areal and vertical distribution of CO2 in El Trapial. It was used to redesign the development strategy of an area of the field, taking advantage of the oil production at shallow structural depths previously identified as potential free gas zones. Also, the production strategy of the entire field in terms of surface CO2 handling, corrosion prevention and production optimization was revised. This paper illustrates the characterization of this unique behavior, including modeling, application and results. This proposed model can be applied to other reservoirs where CO2 is present. A methodical approach is presented including laboratory tests, field surveillance and monitoring needs as well as resulting development improvements. Introduction The production of oil with content of CO2 above 60% is a common pattern in many onshore fields of the Neuquen Basin in Argentina, South America. This high concentration of CO2 is present in the formation gas as dissolved gas and as a gas cap and is not caused by gas injection. A fluid characterization model was performed in El Trapial field in order to improve the understanding of the PVT behavior at reservoir conditions in the presence of the original high content of CO2. An empirical model was created using the assumption that thermodynamic equilibrium was reached before the time of exploitation. One unique challenge of El Trapial field is that the light oil coexists with a gas that contains high concentration of CO2. Conventional fluid modeling could not explain the formation of gas caps at dissimilar structural positions, nor could it explain the existence of oil legs at pressures below the apparent bubble point pressure. Field Description The El Trapial field is a 1.2 B bbl OOIP asset located onshore in the Neuquen Basin in the north of Neuquen Province of Argentina, South America. The field is part of one of the most productive zone in Argentina and is nearby several existing fields, including Chihuido de la Sierra Negra and Puesto Hernandez. The field was discovered in May of 1991 and the discovery well was ChT.x-1. The PVT study performed in this discovery well is shown in Table 1. Peripherical water injection commenced in 1993 with current infill drilling and development of some areas still taking place. This field consists of several sandstone reservoirs of Lower Troncoso and Upper Agrio formations as well as Avile member with an average permeability and porosity of 75 mD and 17% respectively. Current oil field production is above 40,000 bbls/day with a water cut of 80%, total gas oil ratio (GOR) of 450 scf/bbl and an average content of CO2 in the produce gas of 75%.
A case study is presented to compare results between a deterministic and probabilistic hybrid flow unit approach (FU) based on core-log analysis and classical models based on log and petrophysical interpretations in Chihuido de la Sierra Negra Field. Neuquén basin, Argentina. The base of this paper comes from an exhaustive and detailed reservoir characterization model performed by a multidisciplinary team following the FU approach1. The objective of this work is to obtain more realistic values of OOIP and to compare different calculation techniques to achieve reliable absolute horizontal permeability and initial water saturation values. The permeability obtained from different approaches was tested with several core data points available in the field. The main conclusion is that the permeability derived from FU was more accurate than the generalized relationships. The initial water saturation calculated was validated with field data and preserved cores. Besides, values obtained by FU-capillary pressure also were more precise than those models using straight well log data. These improvements in reservoir description have provided the opportunity to increase the amount of OOIP and justify reliable recovery factors. The accuracy in the determination of initial water saturation and absolute permeability shown on this work allow us to apply this technique in any numerical simulation model. Introduction Permeability is one of the most important parameters in basic reservoir engineering. It is used for completion purpose, stimulation strategies, waterflooding projects and for complete characterization of reservoirs to be applied in representative simulation models. Many studies were done on permeability. They have been conducted on clean and shaly formation in order to get better correlation and estimation. Some of them take into account the heterogeneity involved in different pore geometries and the amount and type of clay. Initial water saturation is one of the key factors to achieve more accurate OOIP. Common calculations derive water saturation from logging tool responses. Meanwhile, other approaches estimate it from capillary pressure curves. The upcoming numerical simulation project of Chihuido de la Sierra Negra Field give us the challenge to review the reservoir characterization done before and check different techniques to calculate horizontal permeability and initial water saturation. For that purpose two new cores were added and tested with the prediction model. A sensitive study has been performed taking into account contrast in heterogeneity, difference in depositional environments and also the quantity of data available. Field Description Chihuido de la Sierra Negra is located in Neuquén Basin at 200km to the Northwest of Neuquén City. It is the largest oil field in Argentina. It have been under waterflooding since 8 year. Current production is around 12,000 m3/d of light oil (33–35 API) and 70,000 m3/d of water distributed in 700 producer wells. The water injection is about 90,000 m3/d with 550 injectors. It has three main sand clean reservoirs (less than 8% of clay) within Huitrin formation (lower Cretaceous). These sand reservoirs were deposited in a combination of different environments such as aeolian dune; fluvial channels and sandbars and they exhibit complex variations of pore space-related properties. These variations reflect not only the original depositional process but also the diagenetic and tectonic changes. The producing intervals are in an average of 1,200 m(MD) and listed from top to bottom are: the Troncoso Inferior (TRI), the Agrio Superior (AGS) and Avile (AVI). The TRI is the main reservoir with more than 60% of OOIP. TRI and AGS are subdivided in 10 geological layers. The gross thickness of this several layers plus AVI reservoir is around 200 m.
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