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The giant Chicontepec field contains oil from 18 to 45 oAPI in laminated sandstones of 0.1 to 10 mD at a depth of around 2500 meters (8202 ft). Original Oil in Place (OOIP) is estimated to be 140, 900 MMSTB. The complex geology (complicated structural and stratigraphic nature of the reservoirs), lack of reservoir information and lack of technology availability caused a gap between discovery and development. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The exploitation of the Paleonchannel was postponed because most of the wells showed poor productivity. The reasons for the low recovery (around 3%) have never been thoroughly understood. Various hypotheses have been proposed to explain the deficient performance such as partial closing of the fractures with declining reservoir pressure (bubble-point pressure is near initial pressure), inadequate comprehension of the geological model, deficiency in the fracturing technology, oil-wetted or intermediate-wetted reservoirs, applicability of unconventional wells (horizontal wells, casing drilling technology), etc. Today, the Chicontepec Paleochannel is an intermediate stage. Due to the experience of different fields with similar characteristics, this paper describes an analysis of alternatives that may be considered to resolve the problems of exploitation at the Chicontepec field. Advanced technologies, hydraulic fractures, artificial lift systems, all of them combined with secondary and enhanced oil recovery, may be feasible to sustain or increase production. A number of hurdles will have to be overcome. This field, the second most important oil field in Mexico, should take advantage of the experience learned from these analogous reservoirs. Chicontepec Paleochannel Geographically, it is located in east-central Mexico in parts of the states of Veracruz, Puebla and Hidalgo. Chincontepec system was deposited under complex tectono-stratigraphic conditions. Geologically, it covers an area of 957,534 acres (Figure 1). Aproximately half of Chicontepec consists of shales or silty shales with the rest of the formation made up of multiple thin sandstones beds and zones of sandstones beds. Typically, between 8 and 16 major reservoirs are present. These set of reservoirs is composed of channel complexes that are flanked by, and rest on, lobe sandstones that grade into distal fan and basin floor deposits, resulting in high heterogeneity. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The 3D seismic allowed the identification of sand bodies with viable pay thickness. Some wells produce small amounts of water, in general, water-oil contacts have not been identified. X-ray diffraction analysis showed that the clay cointains dominantly kaolinite with a content of 1 to 5 %. The sandstones are immature litharenites consisting of quartz grains, abundant carbonate fragments, and granitic fragments. Because of the abundance of carbonate in the system, the sediments are highly cemented by ferroan calcite and ferroan dolomite, in addition to quartz overgrowths. Core analyses show that the reservoirs are characterized by both low porosity and low permeability, Figure 2. All the reservoirs have permeabilities of 0.1 to 10 mD and porosities ranging from 5 to 15 %. The effective permeability, as determined from build up, fall off, drawdown and step rate test or advance decline analysis, varies from 0.01 to 15 mD.
The giant Chicontepec field contains oil from 18 to 45 oAPI in laminated sandstones of 0.1 to 10 mD at a depth of around 2500 meters (8202 ft). Original Oil in Place (OOIP) is estimated to be 140, 900 MMSTB. The complex geology (complicated structural and stratigraphic nature of the reservoirs), lack of reservoir information and lack of technology availability caused a gap between discovery and development. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The exploitation of the Paleonchannel was postponed because most of the wells showed poor productivity. The reasons for the low recovery (around 3%) have never been thoroughly understood. Various hypotheses have been proposed to explain the deficient performance such as partial closing of the fractures with declining reservoir pressure (bubble-point pressure is near initial pressure), inadequate comprehension of the geological model, deficiency in the fracturing technology, oil-wetted or intermediate-wetted reservoirs, applicability of unconventional wells (horizontal wells, casing drilling technology), etc. Today, the Chicontepec Paleochannel is an intermediate stage. Due to the experience of different fields with similar characteristics, this paper describes an analysis of alternatives that may be considered to resolve the problems of exploitation at the Chicontepec field. Advanced technologies, hydraulic fractures, artificial lift systems, all of them combined with secondary and enhanced oil recovery, may be feasible to sustain or increase production. A number of hurdles will have to be overcome. This field, the second most important oil field in Mexico, should take advantage of the experience learned from these analogous reservoirs. Chicontepec Paleochannel Geographically, it is located in east-central Mexico in parts of the states of Veracruz, Puebla and Hidalgo. Chincontepec system was deposited under complex tectono-stratigraphic conditions. Geologically, it covers an area of 957,534 acres (Figure 1). Aproximately half of Chicontepec consists of shales or silty shales with the rest of the formation made up of multiple thin sandstones beds and zones of sandstones beds. Typically, between 8 and 16 major reservoirs are present. These set of reservoirs is composed of channel complexes that are flanked by, and rest on, lobe sandstones that grade into distal fan and basin floor deposits, resulting in high heterogeneity. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The 3D seismic allowed the identification of sand bodies with viable pay thickness. Some wells produce small amounts of water, in general, water-oil contacts have not been identified. X-ray diffraction analysis showed that the clay cointains dominantly kaolinite with a content of 1 to 5 %. The sandstones are immature litharenites consisting of quartz grains, abundant carbonate fragments, and granitic fragments. Because of the abundance of carbonate in the system, the sediments are highly cemented by ferroan calcite and ferroan dolomite, in addition to quartz overgrowths. Core analyses show that the reservoirs are characterized by both low porosity and low permeability, Figure 2. All the reservoirs have permeabilities of 0.1 to 10 mD and porosities ranging from 5 to 15 %. The effective permeability, as determined from build up, fall off, drawdown and step rate test or advance decline analysis, varies from 0.01 to 15 mD.
Natural fractures exist in many oil and gas reservoirs. The activation of these fractures can have a significant influence on the initial production and the EUR of the wells. It is therefore very important to know whether they are interconnected and their impact on oil recovery, thus optimizing the development plans of the reservoirs. The giant Chicontepec field, located in central eastern Mexico, with 140 billion barrels of oil in place (OOIP), with laminated turbidite sequences, limited lateral extent, low porosity and permeability, very low current recovery, there are natural fractures or fissures. These natural fractures have been observed in many cores, as well as image logs and outcrops. It is considered that the natural fracture system must be analyzed in Chicontepec in more depth and more importantly, the degree of interconnection may have and its impact on oil recovery because it is estimated that may not be effectively interconnected. Due to the low permeability of the rock, wells are hydraulically fractured. The analysis of the evolution of the pressure at the bottom of the well and or net pressure during a fracturing job is a valuable tool to infer the geometry of the fracture that was generated by the fracturing job. Furthermore, this analysis of the pressure is a powerful tool that can support the identification or existence of interconnected natural fractures and therefore with a certain level of contribution to the producing wells and the recovery of oil from the reservoir. This report presents the application of the analysis of the evolution of the pressure during fracturing jobs in Chicontepec with examples that allow inferring that the natural fractures in Chicontepec are not interconnected or very little.
Fracture geometries and drainage radius are important parameters for developing a reasonable development plan of a single fractured well. In some unconventional gas reservoir, some scholars observed the phenomenon of single well controlled reserves increasing through the material balance curve, and put forward the idea of district supply. In addition, owing to fracture hits, the fracture geometries of fractured wells are sometimes more complex. Thus, those complex factors bring challenges for parameter estimations. In order to study the variation of the drainage radius and complex fracture geometries in the single model, a well testing based model for a finite-conductivity fractured vertical well in radial composite reservoirs with dynamic supply and fracture networks is established. Based on "successive steady state method", the point source function, pressure superposition principle and boundary element method are used to solve the reservoir model, and the methods of discrete fracture and pressure superposition are used to solve the fracture model. By introducing the rate normalized pseudo-pressure and material balance time, the variable fluid flux is equivalent to the constant fluid flux. Combined with the inversion idea of well test, the drainage radius value and fracture geometries are solved by fitting the log-log curves of pressure response, and case studies are performed. The results show that the drainage radius increases with the increase of production time and finally tends to a certain value, and it has a good exponential relationship with time. Also, the fracture geometries of the typical well are multiple-radial fracture networks. Through the study of dynamic drainage radius, the controlled reserves of single well in unconventional gas reservoir can be better determined, and it can also provide theoretical basis for fracture evaluation, productivity prediction and enhanced recovery study of the same type of unconventional gas reservoir.
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