Turbidite Chicontepec Formation, Channel Chicontepec, Mexico. A diagenetic and petrophysical study to optimize the completions

Corralillo Area.

Enrique Estrada(1)

; Miguel Vielma(1)

; Jorge Morales(2)

; Jaime Estrada(2)

; Franklin Tineo (1)

and German Gomez

(1)

(1)

Baker Hughes. Enrique.Estrada@bakerhughes.com (2)

Pemex. Petróleos Mexicanos.

Abstract. This work is the result of authors' experience in complex reservoirs such as the calcitic-lithic sandstones of the Chicontepec Formation, in the Chipontepec Channel Basin. These rocks, highly reactive to acids, present problems of low permeability; they are often fractured but production decline rapidly in time. The diagenesis experienced by these reservoirs is very complicated because the large amount of carbonate lithics, igneous and metamorphic components present, which can be mixed with detrital clays and dissolution of fossils (moldic porosity). The Chicontepec Formation is a turbidite sequence deposited in shallow waters in a submarine canyon with submarine fans, benthic foraminifera, some charred plant remains, and graded and convolute cross-lamination. It is composed by alternating well cemented calcareous-clayey-sandstones, and dark gray calcareous shale. It exhibits conglomerate horizons, consisting of chert and platform limestone clasts. Petrographically it is composed by very fine grained to middle and, occasionally, course litarenite; consisting of carbonate lithic (mudstone), monocrystalline quartz, plagioclase (sericitized) and a minor lithic igneous, metamorphic, silt and shale components. The main authigenic cements are kaolinite, chlorite, calcite, ankerite and interstratified I/S. The facies described from core samples were adjusted with microfacies obtained from thin sections where permeabilities ranging 0.1 to 400 milidarcy, and porosities between 4 to 15% and occasionally 20% could be differentiated. The described type of porosity is mainly intergranular, with some intragranular and moldic porosity. The analysis of high technology logs, such as magnetic resonance and image logs, permitted us facies modeling by using a 3D multivariate analysis of Coates permeability, effective porosity, shale volume and volume of irreducible water to represent facies described in the analyzed core samples and to obtain an integrated Petrophysical-Geological model. The study of these diagenetic facies allowed us to predict which of the electro-facies were susceptible to high reactivity and select the best candidates for stimulation.

1- INTRODUCTION Turbidite systems located in different sedimentary basins worldwide, currently have a high economic interest, since a large number of giant oil fields in production are developed in this type of sedimentary systems. The importance of such oil streams in Mexico, it is established by existing fields in the Chicontepec basin, formed during the Early Tertiary, which is very important from the point of view sedimentological, tectonic and economic oil, since it considerable thicknesses are clastic rocks of turbiditic origin. For this reason, understanding how systems form and its characteristics as turbidite reservoirs is of vital importance for the development of exploration strategies. Thus, turbidite channels and other associated elements are currently the target of oil studies. In Chicontepec Basin, turbidite systems had their main source of supply of lifting and folding of the Sierra Madre Oriental to the west and northwest, and east of Tuxpan platform, and there are tectonic activity during deposition of sediments and continuing thereafter because the Chicontepec Formation rocks have folding and faulting that were observed in the outcrops in the Field Trip conducted with teachers of the (Mexico National University). Clastic rocks, by their source of origin and transport processes, storage and redistribution, have very special characteristics in terms of its geometry and horizontal and vertical distribution. While the potential economic viability of the fields Chicontepec Basin are influenced by the technologies available and the level of investment for development, perhaps the most important factor that defines its operations are its geological features. Due to the high economic potential has Chicontepec Basin, and the problems posed by the geological formation Chicontepec for exploitation, it is necessary a detailed geological study of the facies, and that a better understanding of these allow for better interpretation. In this study rock cores were studied using the concepts of interpretation

3,4,5,6,7,8, , to have

a better understanding of the sedimentology, and thereby establish greater detail the distribution of sandstone bodies that offer the best conditions, such as oil source rocks and gas. These bodies have lateral and vertical lithological changes fast, that locate them as reservoirs discontinuous, isolated and irregular shapes, difficult to pinpoint and high production costs.

2- GEOLOGICAL SETTING. Chicontepec Basin is located in the central-eastern Mexico on the coastal plain of the Gulf of

Mexico, its long axis has a length of 250 km., Oriented NW-SE and oval covers an area of 11 300 km2 with an average width of 60 km. Chicontepec Formation of Paleocene to Eocene, with more than 2,000 m thick of thin and thick interstratifications shale, limestone and siliciclastic sandstone, fine to coarse texturally, graduating at the top of the silty shale sequence

1,2 Chicontepec Formation outcrops in the

western and southeastern margin-Misantla Tampico Basin, geographically situated in the northern part of the state of Veracruz, on the southern tip of the state of Tamaulipas and the eastern portions of the states of San Luis Potosi, Hidalgo and northern Puebla. (Figure 1).

Terrigenous sediments Chicontepec Formation, are the result of tectonic uplift and erosion of the rocks of the Sierra Madre Oriental, which occurred during the Late Cretaceous to Early Paleogene; of the paleo-island east of Tuxpan and the solid Teziutlán south with the subsequent transport and deposition of sediments resulting in clear progradation into the basin and Chicontepec paleochannel as deep marine turbidite systems.

The stratigraphic column of the Lower and Middle Paleocene eroded in most parts of the basin during the late Paleocene-early Eocene and specifically along the western shore of the Island and south of Tuxpan, were also eroded the rocks basamentales Tertiary Basin, Cretaceous and Upper Jurassic. Paleogene stratigraphic column in the canyon paleo includes rhythmic alternation of clayey and sandy sediments, forming lenticular and tabular bodies laterally discontinuous, consisting of loamy sand and sandy silt-clay intercalated and interdigitated laterally and vertically.

3- FACIES DETERMINATIONS

In this study, the cores from the Paleogene stratigraphic sequence was studied through the concepts of interpretation

3,4,5,6,7,8, to have a better understanding of the origin and evolution of

sedimentary facies and their spatial-temporal distribution, with the purpose of oil exploration serve as additional criteria of support, with other geological and geophysical, facilitating their identification in deep subsurface of the Tertiary basin. 5 wells were used (AGF_509, AGF_569, AGF_867, COR_607 and COR_624) where the macroscopic description is described in detail the following features as rock type, color grading, sorting, roundness and sphericity of the grains, sedimentary structures, mineralogical content and paleontology. This description allowed to define a total of seven in the 145.76m described facies, corresponding to four sandy facies, three facies very fine sandy loam, and a limoarcillosa facie. The high degree of impregnation thick sandy lithologies, significantly hindered the description of the sedimentary characteristics of the nuclei especially in facies A1, B1 and B2. The codification of the facies are as follows (Figure 2):

A2: conglomerates and boulders and landslides. Associated Debris Flow. A1: Sandstone media. Abundant in the main channel or center channel B2: Sandstone media. Abundant in the main channel or center channel B1: Sandstone media. Abundant in the thick of the middle lobe. C2: Limo coarse to very fine sandstone fully saturated hydrocarbons. Abundant in the Middle Lobe fine. C1: Limo thin thick sandstone occasionally minor traces of hydrocarbons. Common in that part of the external lobe. D: Limoarcillita occasionally coarse silt, with no trace. Party thin outer lobe.

The study of facies was built and completed petrographic descriptions of these and can thus establish a direct relationship with the mineralogy present in every facie and potential of each facies mineral reactants. That way it could be established within each facie the type and porosity distribution. The spatial and textural distribution of clay minerals( detritical and authigenic) as well as the dissolution of grain and the crystallization and cement some of them, let us know the level achieved by each facie diagenetic. In this way, knowing the different facies associations (from their electrofacies and seismic sections) and its diagenetic evolution, we can recognize different types of reservoir rock quality associated with different facies associations. 3.1 Facie A2. It is characterized by dark gray sandstone, angular to sub-angular, poor selection, consolidated and carbonate cement, with interbedded lenses with different grain size, clasts of conglomerate, shale and siltstone fragments deformed flint several centimeters in length. Clast and matrix supported sandy in part,

elsewhere in deformed shale clast and clay matrix, clasts ductile deformation common to most competent clasts. The facies are not impregnated with hydrocarbons. Regular mid-quality reservoir rock. The abundance of clay matrix makes it a cohesive flow of high density and high viscosity, typical facies of "cohesive debris flow (Figure 3). 3.2 Facie A1. It consists of calcareous litarenita. Sandstone, medium to coarse grain, although this coarse silt, predominantly medium sand phase. Angular to sub-angular, very poor selection of regular, consolidated, low calcareous cement, low cement clay mudstone clasts of quartz predominant. Petrographically the presence of lithic grains and detrital calcite mudstones predominate over monocrystalline quartz, generally low rates of clastic. The presence of clay minerals was determined by X-ray diffraction, resulting in the total volume of clay in the rock. See Figure kaolinite and interstratified illite/smectite and smectite in the center of the pore, it is also possible to observe the presence of authigenic carbonate (ankerite). Facie it has good visual porosity, and is fully saturated with hydrocarbons. (This facie have permeabilities greater than 100 mD) (Figure 4). 3.3 Facie B1 y B2 Calcarea Litarenita. Sandstone, medium to coarse silt with a predominance of fine sand (B1 and B2). Sub-angular to sub-rounded. Moderate selection, consolidated, calcareous cement. Monocrystalline quartz is observed petrographically and lithic carbonate (mudstones) and the main main components, low rates of terrigenous. Dolomitized limestone fraction, planktonic foraminifera and other unidentified. Abundant calcareous cement detrital dolomitized calcareous clay matrix. X-ray diffraction have determined the presence of illite, mica, chlorite and interstratified illite / smectite. Good visual porosity, secondary porosity, total hydrocarbon impregnation. Good quality reservoir rock. The sandstones medium to coarse silt with a predominance of fine sandstone with permeabilities of 10 to 50 mD was defined as B1, where the permeability is increased by 50-100 mD diagenetic processes we consider B2. (Figure 5). 3.4 Facie C2. Litarenita calcareous, fine to coarse sand, with a predominance of fine sand. Poor selection. Angular to sub-angular, consolidated, calcareous cement, fine quartz grains and lithic dark. Monocrystalline quartz stone petrographically and carbonates (mudstones) low percentage of terrigenous. High calcareous cement, recrystallized. X-ray diffraction was determined the presence of illite, interstratified illite/smectite, kaolinite and chlorite. Intermediate visual porosity. Frequent oil impregnation. Regular quality reservoir rock (This facie have permeabilities between 0.5 and 10 mD). (Figure 6). 3.5 Facie C1. Litarenita limestone, sandstone, very fine to coarse silt, with a predominance of very fine sandstone. Poor selection, sub-angular to angular, consolidated, calcareous cement, fine quartz grains and lithic dark. Fair to poor quality of reservoir rock. Monocristalline quartz petrographically more abundant than polycrystalline quartz, carbonate fragments and plutonic lithic fragments of shale, siltstone feldspar and mica alteration. Cement type calcite limestone, dolomite rarely. Low porosity, intergranular and secondary type uncemented fracture. X-ray diffraction was determined the presence of illite/smectite, kaolinite, chlorite and illite (mica). Little partial impregnation of hydrocarbons. As fair to poor quality reservoir rock. (This facie have permeabilities between 0.1 and 0.5 mD). (Figure 7). 3.6 Facie D1 Limoarcilita. Limo medium to fine grained, occasionally thick. Sub-angular to subrounded, consolidated, calcareous cement, fine quartz grains and lithic dark. Abundant flakes of organic matter and limoarcillosos lenses with pyrite and organic matter. Petrographically monocrystalline quartz, lithic siltstones and shales. Lithic carbonate (mudstones) and small amounts of plagioclase, chert, metamorphic lithic opaque. Abundant calcareous cement, detrital clay matrix and occasionally cracks or tears disminutas filled with organic matter. X-ray diffraction indicated the presence of illite, mica, chlorite and interstratified illite / smectite. Poor visual porosity. Very poor quality as reservoir rock. This facies is less than 0.1mD permeabilities. (Figure 8).

4- DISTRIBUCION TEXTURAL AND SPATIAL CLAYS. In each of the facies is set to textural and spatial distribution of clay minerals. Being able Reconco that in most of the changes in facies minerals illite, kaolinite, chlorite and interstratified illite / smectite, similar percentages vary for most of the facies between B, C and D. While the clay content but increases towards the facies C and D in general, the percentage of the same varies between 8 and 12% majority. The facies C and D show a clear association with thin layers of shale, where the shales are interbedded with them. In facies B and the distribution of the clays is mainly dispersed type, showing clay cement around grains like ring (rims) of illite / smectite or lining the pore and kaolinite. While the clay dispersed within the pores are dominantly composed of kaolinite, there is also completely altered fragments formed by a mixture of mudstones and clay (smectite or interstratified iillita / smectite) found by filling the pores. Regarding the distribution of the structure or skeleton of the sandstones, there is a differentiation with respect to facies A and B in which the predominant grains lilticos carbonates (mudstones), followed by quartz crystal and a minority of terrigenous cosntituyentes. In the facies C and D the skeleton is represented mainly by quartz crystal, polycrystalline, mudstones, shale and siltstone lithic, lithic clastic metamorphic and other constituents. Reactants for minerals can say that the lithic carbonate have been among the first constituents who have reacted to the passage of fulvic and humic acids that passed just before the migration of hydrocarbons. While we have also observed the presence of feldspar in the center of the grain completely dissolved and filled by clay, which indicates that the mobilization of aluminum from the mineral structure, are formed by the buffer effect (Surdam), where in very basic pH become unstable aluminosilicates very acid pH and carbonates, balanced by the pressure of CO2 in the system. It is clear that most of the lithic carbonate reacts in this way were and are responsible for providing the carbonates and Ca and Fe cations Mainly for the formation of new minerals such as calcite, pyrite and ankerite. These cements are common in all facies and are found in concentrations depending diferentres detrital this fashion. On the fashion we can say that they are detrital limestone or Arens Litarenita hybrid, because their constityentes are mainly calcite (30-40%), quartz (15-25%), feldspar (5%), Dolomite (2 - 15%), pyrite (1-3%), clay minerals (10%) and ankerite (0-2%) by X-ray diffraction.

5- PETROPHYSICAL MODEL

The specific objectives of the petrophysical study included the evaluation of all the wells with wireline logs. Before processing, all curves from the wireline logs were put in depth using as curve base the resistivity log, then the log data was first corrected for environmental conditions, bed thickness and invasion. Also, curve normalization was applied when deemed necessary.

In order to asses the quality or the reservoir rock, the analysis had to determined the petrophysical properties of the reservoirs in the area in study through the evaluation and interpretation of wireline logs, production data and core descriptions. To accomplish this, a lithological pattern was established for each type of curve available in the data base. The identified patterns were used to determine the different intervals in which the processing of each well had to be zoned, as each interval or zone requires different parameters to be input. After the petrophysical properties were determined for the 120 wells, a data base was constructed with all the available and validated petrophysical data.

5.1 CLAY MODEL

To determine the correct clay model, X ray diffraction data, nuclear magnetic resonance logs and core thin section analysis were integrated. The different volumes, derived from the wireline logs, including magnetic resonance, were adjusted to those observed in the petrographic study of each sedimentary facies.

Magnetic resonance measurements allow the quantification of the porosity by associating the transversal relaxation decay time ( apparent) to the different poral spaces. The sum of the total area under the spectrum corresponds to the total porosity and by dividing this volume, using cutoff lines, the fractions of porosity corresponding to clay bound water (CBW), irreducible fluid (BVI) and porosity containing moveable fluid can be calculated. See Figure 9.

5.2 MODEL STRUCTURAL, LAMINAR AND DISPERSED SHALE

In addition, petrographic analysis and macroscopic nucleus shows that the formation of clay volumes presented differently distributed within the reservoir.

The type of clay present in a reservoir plays an important role in hydrocarbon production and the nature of thin film structures of turbidites causes the evaluation of sequences of sand - shale is a challenge, especially where shale can coexist as discrete bodies and scattered. One of the key points to predict the performance of a reservoir is to understand the nature of the distribution of clays in the reservoir. To that end, we propose the use of the method for calculating volume of clay laminar, structural and dispersed shale, which uses total porosity and total clay content, previously quantified with magnetic resonance or gamma rays to determine the distribution of clays

9

The model developed by Thomas Stieber quantitatively determining the content of clay and its distribution as an alternative to linear model of shale which is determined solely from gamma rays. The model relates changes in the gamma ray response to the concentration and distribution of the clays. When this information is combined with information on porosity is possible to determine the configuration of clay, sand fraction and porosity of the sand fraction. There are three types of clay: laminar, dispersed, and structural. The latter corresponds to lithic altered during diagenetic processes. Juhasz (1986) developed a system for the distribution of clays aces and determine the average arcillocidad, porosity and hydrocarbon saturation of the layers of sandy clay. This system is based on the relationship between total porosity and shale volume described by Thomas and Steiber, and by the saturation model Waxman – Smits

10. Juhasz

11 uses graphics versus cross-porous

shale volume to evaluate the formation, where two triangles are the graph of porosity versus cross VSH. Figure 10 then shows the graph Juhasz. To differentiate and quantify the three types of clay will require unconventional methods. In wells with core analysis was performed LSSA (Shaly Laminated Sand Analysis). LSSA The model was specifically designed to evaluate sequences thin sand - shale. The idea is to expose the petrophysical properties of the thin sand bodies interbedded with thin shales. Under the program, the term thin means that a tool does not resolve vertically profiling the properties of a sand or shale. This calculates porosity and saturation in intervals anisotropic and isotropic sand - shale. The model of sand - shale Thomas-Steiber is key in positioning the training in the fractions of sand - shale. The model allows the analyst to extract the true porosity of the sand and the distribution of the clays. Once the effect of lamination of the shale has been removed and only remain the properties of the sand to proceed with the calculation of water saturation in the sand. Using the LSSA, we found that the volume of clay present is mainly the laminar type, followed by clay dispersed. The clay is mainly scattered in the sand bodies, while the structural clay is virtually absent, which fits well with the data observed in the nuclei analyzed. In the following pages show graphs Thomas cross-Steib, from this study as well as examples of the analysis performed LSSA. Figure 11 A) is observed in the well Thomas_Steiber Graphic Corralillo-607. This graph is used to estimate the type of clay present. It is noted that there is a presence mainly of shale with a lower percentage of clay dispersed. Not seen a significant percentage of clay structure. While in the pit Thomas_Steiber Graphic Corralillo-624 as shown in Figure 11 B) shows that there is a presence mainly of shale with a lower percentage of clay dispersed. Not seen a significant percentage of clay structure. Figure 12 and 13 shows is the representation of shales, structural and scattered achieved for these two wells (Corralillo_607 and Corralillo_ 624). Figure 14 a) shows detail of Figure 12, showing the correlation of microscopic facies with shale volume and scattered obtained from Thomas_Stieber for well Corralillo_607. Figure 14 b), we observed detail of Figure 13, showing laminar Clays volumes and scattered from the well Corralillo_607 Thomas_Stieber for showing its correlation with facie identified in the field.

6- ESTIMATE OF FACIE. The estimation of facie allows us in the same well to estimate core facie up and below the core

where we have no information on the wall. From the description of core proceeded to the estimation of facie from neural networks using GR, Rt, Density, Neutron, clay (V_sh) and using the volume of dispersed shale and from Thomas Stieber. While several options were used in connection with software such as Horizont (Express) and ipsom (TechLog) was decided to apply the Tech Log. The estimation of facie is the main link to link the facie described in the core with the facie present in wells without cores. Once the core facie may be represented in all core pit, data from GR, Density, Neutron, Vshale and LSSA more like a procedure in which through Thomas Stieber, allows us to correct for laminar volume, structural and dispersed clays in the different facie present (only in the core). Figure 15 for Corralillo_607 well observed that most of the facie described are A1, B1 and B2, C2 and D as a minority in the channeled. The image records of wells are the best to recognize these facies by its high vertical resolution as shown in figure 15

A) and B). The biggest problem we face is that we only have two wells with records images of the 124 wells to define its sedimentary environment and facie variations. Therefore, the estimate was applied Ipsom facie described above. A finding that the estimated facie were performed with great success as seen in the images without core records as noted in figure 15 c). In this picture observed in the second track the depth and 3) only the static image in 4) MRI volume, where volume of fluid is observed moving yellow, irreducible water ocher (Irreductible water) and gray water bound to clays (Bound Water). In the last lane, Facies estimated from ipsom. As you can see the estimated facie have a good much with facie identified with the image. The photo shows the field of channel facie and facie for thinner lobes. In the well Corralillo_604 note that most of the facie described are B1 and C2. A minority C1 and D in the lobe. The image records of this well are the best to recognize these facie by its high vertical resolution as shown in figure 16 A) and B). When we look at the figura16 C) facie can be seen that the estimates were carried out with great success as shown in the records of images without a nucleus. Figure 16 C) observed in the second lane the depth and 3) only the static image in 4) MRI volume, where volume of fluid is observed moving yellow, irreducible water ocher ( Irreducible toilet) and gray water bound to clays (Bound water). In the last lane shows the estimated Facies from Ipsom. As you can see the estimated facie have a good much, with facie identified with the image. The photo shows how field lobes interdigitate with other lobes means thinner. 7- FACIES ASSOCIATIONS.

Based on detailed analysis and interpretation of sedimentary facie were recognized during the description of nuclei AGF_509 Wells, AGF_569, AGF_867, and COR_624 COR_607 and facie using ipsom estimated from where no information was available cores, defined seven sedimentary facies associations referred to the AF7 AF1 (Fig. 17), which allowed us to recognize in the sedimentary sequence studied depositional systems lobes and channels over which recognized the following: AF1: Channels (erosive channels linked to the upper lobes), AF2: Complex channel middle lobe (small channels within the lobe), AF3: Middle lobe (thin half of 30 to 50cm thick) AF4: external lobe (fine to very fine layers of 2-30 cm thick) AF5: Canal winding (only observed in the T50 and T30) AF6: mild proximal lateral accretion (seen in the T30 and T50) AF7: Distal Levee. (Seen in the T30 and T50)

8- PRODUCTION PROBLEMS WITH CLAY MINERALS. As we all know the type and special provision of the clays that form part of the matrix and cement

in the pores we directly determine the porosity and permeability of our reservoir. This first thing to understand is that how we influence them in our reservoir, we know that all of them will be provided from the data of X-ray diffraction, but also in this analysis we clays the total volume of all clays present in the sample. In other words, we mean that the clays that come from the alteration of feldspar as a lithic or a lithic volcanic shale will be represented in this volume. However, this volume should be taken as the sum of active and passive clay which will be interacting in our reservoir. To us, we want to know which of these clays is that passively and actively in our reservoir. This depends on the method of operation that we choose (injection water, fracture, acidification) as they are passive may become active depending on the type of work we do.

In order to know which will be active and passive which is necessary to identify the general types of textural distribution of these known to the world oil: Laminar, Structural and dispersed. This type of clay became known for his important volume on the surface area available for each of them can interact with the fluids that come into contact with them in the reservoir, or in other words by its cation exchange capacity (CEC ) depends on one side of the same textural distribution in the reservoir

12. We mean that if

we clays dispersed, they have a higher cation exchange capacity that if they were layered and layered CIC will be more than structural, if they were all the same composition.

As we know, not everyone has the same composition, and we can find more than one of them next to the pore. Therefore we discuss the chemical and physical properties of clays individually to know them better. The spatial arrangement of the clays in the pores of the sandstones are two: around the ring-shaped grains or rims (Pore Lining) or by filling the pore (pore filling). In Figure 5 we see SEM micrograph showing these types of spatial arrangement of the clays

13.

Smectite is arranged around the grains in the form of rims (pore lining) causes us problems in production because they are extremely sensitive to fresh water, so their pore lining and migrate tend to break during the swelling and the structure of smectite has a surface area large volume so that the bound water and capillary water in the micropores will be high, results in elevated water saturation. Smectite also be found in a pore filling and sometimes mixed with other clays pore filling, which is the worst combination

13 (Figure 4).

The kaolinite is a clay that is known for booklets or vermiform morphology in SEM micrographs. The main problems of these clays is that because its pseudo-hexagonal plates are very large have low power subject to the host grains, and therefore, any movement of the fluid set in motion, thus producing the migration of fine, almost imperceptible to principle by the size of the crystals under 4 microns, but the continuity of the migration of these clays make once they begin to migrate migrated fine silts, coarse to very fine sand and as appropriate, and it is there, when we can perceive the migration of fines (Figure 7).

The illite in the reservoir causes inconvenience because their pore lining reduce the size of the throat and act as a filter porary blocking every particle (organic or inorganic) of larger size. Illite also gives us a high irreducible water volume, due to the close of its microporosity and other causes migration of fines as well as kaolinite. We did not observe illite described in the pores only interstratified illite/smectite

13 (Figure 8).

Chlorite can be found in the reservoir in different ways: some of the grains forming ring pore lining, or by filling the pore "pore filling", or altering a volcanic lithic grains of biotite in a structural way "structural clay." The problem of chlorite occurs when they are exposed to acid treatments (HCl), in which are dissolved, then the Fe is released and reprecipitated with a gelatinous iron hydroxide, which have large crystals that contribute even more to the reduction of permeability in sandstones. Chlorites are common and abundant iron-rich carbonate cement as framboidal pyrite

13 (Figure 18).

9- DIAGÉNESIS

The importance of the description of the processes and cementation compactacionales are of vital importance in view to reducing the porosity and are used for determining the quality and reservoir rock. Compaction (mechanical and/or chemical) and the dissolution of the grains by the movement of fluids are the most important processes when intergranular volume reduction and the creation of secondary porosity in the reservoirs studied in Training Chicontepec. According to the criteria established by Smidth and McDonald for the recognition of secondary porosity are different classifications, but the most frequently observed here was the textural inhomogeneity

13 (Figure 5 and 6),

we have also observed complete dissolution of grains, where only was recognized by the rims of clay that have been preserved, this type of porosity is intragranular, although sometimes the intragranular porosity is only partial as shown in Figure 18 where the Al from feldspar to migrate and subsequently filled by clay. At other times we see móldica porosity by dissolution of fossils. The intergranular secondary porosity is important but secondary porosity generated once we can not differentiate how much primary porosity exists, we can only speak of secondary porosity (Smidth and McDonalds). Diagenetically we can see that the formation of pyrite framboidal indicates that the reactions were controlled by diffusion processes (which acts dissipating the concentration differences in favor of chemical potential gradients and electric) and convection (dispelling the different temperatures in the subsurface by circulation of fluids forming convection cells).

13 Figure 18.

We know that iron from the Sierra Madre Oriental must have been transported by rivers agitated (oxic water) and low salinity water (taking with oxidized iron-rich minerals such as hematite and limonite), which when added to the deep sediments turbidites were found in a new regime of prevailing conditions, the same anoxic waters (less than 0.2 ml/l dissolved oxygen) and salinity 35.000ppm. These new conditions makes reducing Fe

3+ Fe

2+ pass and so we now have available Fe

2+ for the formation of

pyrite, sulfur is abundant in seawater as sulfate but in those depths we are in a reducing environment, so if there is available sulfur as sulfur (S

=). The fact that we are rich in pyrite and calcite as major minerals

formed Fe-rich diagenetic Fe tell us diagenetic zones with different states. First pyrite occurs in a state of reduction (Eh) higher than the Fe-rich calcite formation This is due to different reasons, firstly the formation of pyrite (S2Fe) needs to be taken in two sulfur different states: one in the form of zero-sulfur (S

0) and another as sulfur 2 - (S

=), so we can coordinate two iron sulfur with a

formula of Pyrite13

. On the other side to continue the diagenesis with depth we can see that pyrite precipitated framboidal stop because you reach the limit of S

0 available and from then on if we continue the burial, or continue

moving toward a smaller area will all negatively charged sulfur as pyrite is no longer stable and begins to precipitate as iron-rich carbonates ankerite, ferroan calcite or siderite. The provision of HCO3-, Ca, Fe, and S

= S

0 in the pore at the same time is governed by the reactions of

the solubility product of its ions (KPS) having always the pyrite precipitated before the ankerite or calcite rich in iron. Now you can find both in some samples or one or the other on different occasions, that should it?. While always generally pyrite precipitate before the iron-rich calcite, the solubility product of its ions (KPS), Calcite precipitated Fe before pyrite only when the concentration of its ions is greater than the KPS relationship Calcite Pyrite -Fe/KPS must be at least 7x10

+6 larger than the concentration of

pyrite. 10 – WETTABILITY. The wettability, clay minerals and diagenesis are a function of the characteristics of the rock, water and oil. As we all know the polar components (N-functional groups, S-and O-) tend to be wettable to water or oil. The polar components together have negative dipole are attracted by the positive charge on the surface of minerals. We know that the formation water pH can indirectly control the wettability of the reservoir because the surface charge of a mineral is sensitive to pH. So that the calcite (pH 4-7) has positively charged surface and preferably have wettability to oil by the attraction of the negative dipoles of the polar components of petroleum. The quartz surface will only have a positive charge when in the vicinity of a pH = 3. The clay minerals such as kaolinite, is where the face pseudohexagonal plates 010 (Miller Index) and 100 have positively charged surface, while the face surface 001 has a negative charge. Therefore, in the figure we can see that the faces 010 and 100, are always wet with oil, showing a vermicular morphology or accordion (Figure 7), not the classic booklets that water is wet. On the other hand, when the rims are composed of the minerals smectite and interstratified illite / smectite have negatively charged surface which is wettable by water, mainly due to the attraction of positive ions to negatively charged surface of these clays

13 (Figure 4 and 6).

11- CONCLUSIONS • Because of the complexity of Chicontepec, and the challenge to obtain a rentable production quota, it is vital to integrate the results of all the studies, including petrophysical, geological, reservoir and seismic, as well as all of the information coming from core analysis, field trips, wireline logs, fluid samples, etc. The integration is vital if we are to obtain a detailed description of the properties of the reservoir. • In order to accomplish and effective and efficient production of hydrocarbons, it becomes necessary to precisely describe its reserves and this largely depends on the application of a correctly elaborated petrophysical model. • The formation has a high degree of laminarity and so it becomes imperative to acquire high vertical resolution logs since the resolution of the logs is one of the most important aspects for discriminating the different lithological patterns and for clearly defining the limits of the different strata. The tools need to be sensitive to small changes in the sedimentary structure of a formation since the lack of resolution could cause deficits in the petrophysical interpret-tation. • Future petrophysical evaluations should include analysis LSSA (Thomas - Steiber) with the purpose to determine the different types of clays, correct the porosity for laminar shale volume and to better the physical representation of the reservoir. Thus, image and nuclear magnetic resonance logs must be acquired in wells where cores will be taken. • Periodical revisions of all the analysis must be performed and a complete plan to acquire any missing information needs to be created. This will result in a better understanding of the reservoir and consequently in a better definition of the wells to be perforated, their objectives, completion plans and will aid the selection of artificial system to increment the production of hydrocarbons. • In the cores of rock analyzed Southeast Chicontepec Basin, have been some major sedimentological features in environments interpreted as channeled areas, deposits and lobe-lobe transition zones channel lobes, sub-environments in half range and external. • Based on field data, it is known that the direction of flow lobes submarine has a preferential tendency towards the SE (southeast), while some of the deposits formed by landslides and debris flow, have a direction NE (northeast). • Based on the core information is obtained from the characteristics of the rock and you get ranked using petrographic studies with thin films or by using the scanning electron microscope.

• Petrographic studies have found that Chicontepec Formation sandstones are immature, dominated substantially lithic fragments, of which between 40% and 88%, commonly are fragments of limestone, and the rest litarenitas feldspar, which indicates that the major sediment corresponding to the calcareous detritus from the Sierra Madre Oriental to the west of Tuxpan Platform to the east, and south Teziutlán Massif. • From diagenetic studies (with important autigenéticas clay content, mineral autigenéticos) we can infer and predict important events happening in the reservoir on the problems of the clays during drilling and production of hydrocarbons. Knowledge of swelling during drilling them is of vital importance to the designation peroration sludge used. During production, meet near the wettability and what will be the susceptibility of different facies at the time of establishing a work of fracture stimulation, acid or water injection is no less important. • Studies of the cores allowed us to make an estimate of facies from the use of programs that use neural networks for the construction of these facies from core data and data Gamma Ray, Resistivity, Density, Neutron and Vshale. Learning these popular these facies allows to wells where only basic information is available and thus unable to establish the composition of the different facies associations when there was no core. • Knowledge of facies maps, geometry, width, height, architecture of sand bodies and their correlations, closely linked to facies indicates that diagenetic knowledge of each of these sequences (T30, T50, T65, T70 , T80, T90, T100 and T105) is critical to successful future development Corralillo field. This should be increased in study or thesis work in towns and taken, and make new nuclei to complement this existing information and verify the proposed model, or update the same in case of finding new findings and differences. • The proposal to use high technology in the future study wells, it is only in order to understand and difficult to understand even more the reservoir, looking to exploit the lowest of budgets and improve their recovery. The authors we thank management of Pemex for permission to publish this paper and would like to thank the engineers Noe Santillan and Javier Arellanos (Mexico National University) by share his knowledge in the course and field trip on the complex reservoirs turbidite.

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12- REFERENCES.

1. BITTER, M. R., 1983. “Sedimentology and Petrology of the Chicontepec Formation, Tampico-Misantla Basin, Eastern Mexico”. Thesis for the degree of Master of Science., B.S. University of Kansas, Geology. p. (inedit).

2. BITTER, M. R., 1993. “Sedimentation and provenance of Chicontepec sandstones with implications for uplift of the Sierra Madre Oriental and Teziutlan Massif, East-Central México”. In: J. L. Pindell and R. F. Perkins (eds.): Mesozoic and Early Cenozoic Development of the Gulf of Mexico and Caribbean Region: A Context for Hydrocarbon Exploration. Transactions, 13

th Annual Gulf Coast Section of Society for Sedimentary

Geology (GCSSEPM). Research Conference, pp. 155-172. 3. Bouma, A. H., “Sedimentology of some Flysch deposits: A graphic approach to facies interpretation”,

Elsevier, 168 pp., 1962. 4. MUTTI, E. (1977). « Distinctive thin-bedded turbidite facies and related depositional environments in the

Eocene Hecho Group (south-central Pyrenees, Spain)”. Sedimentology, 24, 107–131. 5. MUTTI, E., 1979. “Turbidités et cones sous-marine profonds”. In : P. Homewood (ed.). Sedimentation

Detritrique (fluviatile, littorale et marine). Institute de Geologie, Universite de Fribourg, Fribourg Switzerland, pp. 353-419.

6. MUTTI, E., 1992. “Turbidite Sandstones”. AGIP-Istituto di Geologia, Universitá di Parma, Italy, 275 p. 7. MUTTI, E. AND NORMARK, W. R., 1987. “Comparation examples of modern and ancient turbidite systems:

Problems and concepts”. In J. K. Legget and G. G. Zuffa (eds.). Marine Clastic Sedimentology: Concepts and case studies Ghaharn and Trotan, pp. 1-38.

8. MUTTI, E. AND RICCI LUCCI, F., 1972. “Le torbiditi dell’ Apennine settentrionale: introduzione all’ analisi di facies”. Memorie Societa Geologica Italiana, Vol. 11, pp. 161-199 (traslated into English by T. H. Nilsen , 1978). International Geology Review, Vol. 20, No. 2, pp. 125-166.

9. Thomas, E.C., and Stieber, S.J., “The Distribution of Shale In Sandstones And Its Effect Upon Porosity,” SPWLA 16

th Annual Logging Symposium Transactions, 1975.

10. Waxman, M.H., and Smits, L.J.M., “Electrical Conductivities In Oil Bearing Shaly Sands,” SPE Journal, Vol.8, No. 2, pp. 107-122, 1968.

11. Juhasz, I., “Assessment of the Distribution of Shale, Porosity and Hydrocarbon Saturation in Shaly Sands,” 10

th Annual European Formation Evaluation Symposium, Paper AA, 1986.

12. Estrada, E.; Beaufort, D. y Alain Meunier 2006 “Aportes de nuevos métodos petrográficos cuantitativos a la evaluación de la calidad de roca reservorio de hidrocarburos. Aplicación a areniscas de la Formación Bajo Barreal (Sector Oeste de la Cuenca del Golfo San Jorge” Mémoire de Reserche, Université de Poitiers, France.

13. Estrada, E. 2010. Estudios Sedimentolo-gicos y Diageneticos Laboratorio de Campo Corralillo. Pemex-Baker Hughes, 182pp (inedit).

Figura 1. A) Geographic location and area of study within Chicontepec Basin. B) Age of the Formation Chicontepec

Figura 2. Ancient submarine fan model for showing the development and the mechanics of turbidite deposits in areas of the

continental shelf, continental slope and basin (Modified from Mutti-Ricci Lucchi, 1972)

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Figura 3. Facie A2 in the well Corralillo 624

Figure 4. Photo petrographic microscope and electron microscope of Facie A1 Corralillo_607 well.

Figure 5. Photo petrographic microscope and electron microscope Facie B1 in Corralillo_607 well.

Figure 6. Photo petrographic microscope and electron microscope Facie C2 in Corralillo_607 well.

Figure 7. Photo petrographic microscope and electron microscope Facie C1 in Agua Fria_509 well.

Figure 8. Photo petrographic microscope and electron microscope Facie D in Corralillo_607 Well.

Figura 9. Porosity model Nuclear Magnetic Resonance.

Figura 10. Picture modified of Juhasz. (1986).

Figura 11. Picture of Thomas_Steiber . A) Plot in the CORRALILLO-607 Well. B) Plot in the CORRALILLO-624 Well.

Figure 12. LSSA analysis performed in the well Corralillo-607.

Figure 13. LSSA analysis performed in the well Corralillo-624

Figure 14. LSSA analysis showing Laminar Shale and Dispersed Clay. A) In Well Corralillo_ 607 compared with petrographic facies.

B) In the Well Corralillo 624 compared with outcrops.

Figure 15. A) Determination of Facie in Corralillo_ 607 Well. B) Correlation of facie with Image Well. C) Correlated well with image estimation from Ipsom facies and volumes of fluids from nuclear magnetic resonance.

Figure 15. A) Determination of Facie in Corralillo_ 624 Well. B) Correlation of facie with Image Well. C) Correlated well with image estimation from Ipsom facies and volumes of fluids from nuclear magnetic resonance.

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Figure 17. Facies association found for the study area. (Modified from Mutti-Ricci Lucchi, 1972)

Figure 18. Facie C2 of Agua Fria-867 well showing framboidal pyrite, calcite and iron-rich secondary porosity in the thin layer above

and pore filling calcite, pyrite and illite/smectite, intragranular porosity in the SEM photomicrograph.