INTEGRATED METHODOLOGY OF THE DISCRETIZATION OF THE POROSITY IN NATURALLY FRACTURED RESERVOIR.

Transcription

1 Title INTEGRATED METHODOLOGY OF THE DISCRETIZATION OF THE POROSITY IN NATURALLY FRACTURED RESERVOIR. Abstract Due to complexity associated to petrophysical characterization of the porosity in naturally fractured reservoirs, a methodology to discretize it in four main systems was developed: matrix, microfractures-microvugs, connected vugs and fractures. This methodology integrates three independent but related procedures, based upon the response of conventional logs and the comparison with core date and special logs. The first procedure is based upon the sonic log response to determine matrix porosity. The second determines the fracture porosity by means of the variable cementation coefficient (m) method. The third is known as the Probability of Occurrence of Flow (POF), which separates the vugs connected to fractures from the microvugs connected to microfractures and the matrix porosity. This methodology was applied in wells in the Cretaceous and Jurassic of Mexico fields. For the results calibration was used core information, image logs, Nuclear Magnetic Resonance logs and production information, which provides a good degree of confidence to the obtained results. Authors - Ing. Esteban Soriano Mercado (PEMEX) - Ing. Carlos Ulises Pérez González (PEMEX) - Ing. Efrén Rafael Solorzáno (CGGVeritas) - Ing. Paola Yineth Fonseca Chaves (CGGVeritas) - Ing. William Oscar Valbuena Barboza (CGGVeritas) Topic Petrophysics Presentation Poster

2 Introduction Reservoirs of the IVF natural type (Intercrystalline-fracture-vugular porosity) are highly heterogeneous and they present in some intervals, a low storage and a high permeability, whilst other intervals present a low permeability contrasting with a high storage. In order to produce these fields in an adequate manner, it is necessary to identify and determine the porosity percentage due to fracture systems, dissolution cavities and matrix. Based upon the combination of three independent procedures, an integrated methodology for porosity discretization was developed, with the aim of decreasing the uncertainty related to the porosity which stores the hydrocarbon, and the porosity associated to its flow. The development of complex porosity studies is fundamental for the numerical simulation of the field, as well as for the analysis of production behavior, aiming to optimize the production of the remaining hydrocarbon reserves. Integrated Porosity Discretization The pore system in naturally fractured reservoir rocks, presents several pore types, amongst which, we have the matrix, microfracture, microvugular, moldic, cryptocrystalline, and intercrystalline porosity, as well as connected or isolated vugs and fractures. Through the methodology presented in this paper, it is possible to estimate the proportions of 4 porosity types: MATRIX, MICROFRACTURES-MICROVUGS, CONNECTED VUGS AND FRACTURES. This distribution, and the way in which the porosity discretization model is considered conceptually, are presented in figure No.1 (left). The two first porosity types, matrix and microfractures-microvugs can be perceived and are measurable at the microscopic and thin section scale and generally, they have a greater storage capacity but a lower flow capacity than the other two porosity types. The connected vugs and the fractures are detected at a macroscopic scale, by means of image logs and core descriptions, and may have a lower storage but a greater flow capacity. Of course, big sized vugs could be encountered, which would be storing a great amount of fluid and the fractures would become a conducting medium of the fluid. In figure No.1 (right), the integrated discretization methodology is summarized. In the first part we have the porosities obtained from the Dolomitization factor, from which the matrix porosity (dark blue rectangle) is separated from the rest of the porosity. Therefore, this value is taken as the first division of the effective porosity; from the second technique, the value of the fracture porosity (red rectangle) is integrated, as it is separated from the remaining porosity. Finally, with the POF (Probability of flow occurrence) technique, two porosities are obtained: one, with a high flow capacity, which is assumed to include fractures and connected vugs; when fracture porosity is substracted an estimate of the connected vugs porosity can be obtained (yellow rectangle). The other porosity, with a low flow capacity, is assumed to include matrix porosity and microfractures-microvugs; when the matrix porosity is substracted, an estimate of the microrfracturesmicrovugs porosity (light blue rectangle), can be obtained. The first of these techniques is the definition and application of the Dolomitization Factor (FD). The methodology establishes that the effective porosity (total porosity corrected for clay content) consists of the matrix porosity, that is, the primary porosity generated at the moment of the deposition of the rock and a secondary porosity, which includes vugs and fractures, and is the result of the diagenetic processes which acted upon the rock after deposition.

3 Figure 1. Graphical description of the porosity discretization methodology. According to the conceptual model, the effective porosity is calculated by means of the combination of the Density-Neutron logs and the porosity matrix is calculated with the sonic log multiplied by the FD; therefore, the substraction of these two porosities yields the vug and fracture porosity. The FD is calculated for each field as a function of the response of the porosity logs and the intrinsic characteristics of the rock, in order to correct the points detected by the sonic log, in intervals where the vug and fracture porosity is so high, that this log is affected. In figure No.2 (left), a sketch of this discretization technique is presented. Equation 1 shows the relationship which had the best fit to the studied field, but which is not necessarily applicable for all the cases, it should be determinate according to the intrinsic characteristics of each field. FD= ((((SPHI)*((NPHI*DT)+(DPHI*(DT-DTmat))))/(NPHI*(DT-DTmat))) (1) The second integrated technique in the discretization methodology is the determination of the variable cementation factor (mv). This is a parameter dependent mainly on the porosity, the lithology, the intercommunication of the pores, the degree of cementation of the rock and the size and distribution of the grains, among other factors. Normally, values less than 2 correspond to somewhat large fractures and vugs and probably connected, whilst the values greater than 2 are associated to microporosity with a smaller flow capacity, as shown in figure No.2 (right). Figure 2. Dolomitization factor and variable m. In order to determine the value of this parameter, different approaches are encountered in the literature. In this case, sensitivity analyses were carried out with two methods: one developed by Roberto Aguilera (2003) equation 2, and which is a function of the partition coefficient, and another determined by Gomez Rivero (1976), equation 3, which depends on the formation factor. Details on the equations and the nomenclature can be encountered in the quoted references.

4 mv= (log ((1/V * PHIE+(1-V*PHIE)/(øm ^-2))/(-log PHIE)) (2) mv= (mh * log PHIE 1.99-mH /0.87)/ log PHIE (3) After the calculation of the value of the variable m, the matricial porosity, which includes matrix and vug porosity, is determined, by means of the equation developed by T.I. Elkewidy and D. Tiab, equation 4 and the other part, which corresponds to fracture porosity, is determined with Aguilera s equation (2003), equation 5. PHIE_MAT (matriz+vúgulos) = (PHIE mv PHIE) / (PHIE mv -1) (4) PORO_FRA = (PHIE (mv+1) IIF)/ (IIF-1) (5) The index of intensity of fractures, IIF is a function of the total porosity and the variable cementation factor, as shown by equation 6. IIF=PHIT mv (6) Up to this stage, with the first technique, primary porosity, mainly linked to the matrix, can be separated from the secondary porosity, represented by the combination of vugs and fractures. With the second technique, fractures can be isolated, but yet the matrix and vug porosity are in the same medium. With the third technique, it is pretended to estimate the Probability of flow occurrence (POF) of the porosity. The fundamentals of this technique were originally applied for the estimation of the probability of occurrence of fractures by authors like Boyeldieu and Martin (1984), and Aguilera (1995), and applied in fields in Mexico, by Sneider (2008) with the name Plausibility of Fractures. Due to the quantity and importance of connected vugs in the pore system of the rocks in this field, it was assumed that the vugs contributed to both the storage and the flow of fluids. The technique is based upon the responses of three sets of tools: resistivity, radioactive and rugosity. The P_electric (probability of the electric logs) is mainly determined by the relationship between the different resistivity curves: deep resistivity (LLD), medium resistivity (LLM), shallow resistivity (LLS) and microresistivity (MSFL). The P_radioactive (probability of the radioactive logs) is mainly determined by the relationship of the Gamma Ray with the Uranium contribution removed (CGR) and the total Gamma Ray (GR). P_rugosity (probability of rugosity logs) uses as indicators the Caliper, the density log correction (DRHO) and the photoelectric factor (PEF). Combining mathematically the response of the previous relationships, the Probability of Flow Occurrence is obtained. Assuming that the value of 1 corresponds to a 100% flow capacity, we can relate this probability with the effective porosity and in this way, a distribution of the probable flow capacity for the whole evaluated interval, can be obtained. In order to get the relationships between the different logs, their behavior has to be analyzed with great care opposite a zone with fracturing and connected vugs, because each one of them may have a different response. There are intervals where some logs are greatly affected, whilst others do not exhibit any anomaly at all. After the normalized curves for all the logs have been obtained and the best indicators amongst them have been selected, the POF is obtained by means of the following equation 7. POF=1-((1-P_electric) (1-P_resistive) (1-P_rugosity)) (7) Figure No.3 presents schematically the theoretical foundations of this technique and its application to a specific interval. The yellow circles indicate a greater probability of flow occurrence and the blue ones, a lower probability.

5 Figure 3. Probability of flow occurrence (POF) determination. Conclusions The application of the integrated porosity discretization methodology results in a better knowledge of the pore system. This will allow the approximate determination of the percentage of contribution to the total porosity of the different porosity types, and infer in which intervals the storage of fluids will be predominant and in which intervals the flow of fluids will be most likely. Acknowledgements The authors wish to thank to Geo. Jose Carlos González Del Angel (PEMEX), Ing. Arely Villaveitia León (PEMEX) and Jose Vicente Rodriguez Rodriguez. Nomenclature POF = Probabilidad de Ocurrencia de Flujo, % Øm = Porosidad de matriz, método R. Aguilera, % IIF = Índice de Intensidad de Fracturas SPHI = Porosidad del registro Sónico, % mv = Factor de cementación variable NPHI = Porosidad del registro Neutrón, % m H = Factor de cementación inicial de Gómez Rivero DT = Tiempo de Transito, us/ft BPD = Barriles por día DPHI = Porosidad del registro de Densidad, % V = Coeficiente de Partición, % DTmat =Tiempo transito de matriz ponderada, us/ft PHIE_MAT = Porosidad Matricial, % PHIE = Porosidad Efectiva, % Referencias Aguilera R, Naturally Fractured Reservoirs, PennWell Books. Tulsa, Oklahoma. Second Edition, Aguilera R., Aguilera M., Log Interpretation Petrophysics, Naturally Fractured reservoirs,servipetrol. Ltd. Calgary, Canada, Beck, Schultz and Fitzgerald, Reservoir Evaluation of Fractured Cretaceous, Carbonates in South Texas, SPWLA Annual Logging Symposium, Brown, R., Application of Fracture Identification Logs in the Cretaceous of North, Louisiana and Mississippi, GCAGS Meeting, Buller, Kenyon, Rasmus and Miller, Evaluating Porosity in Oomoldic Carbonates, Technical Review July Elkewidy T.I. and Tiab D., SPE Application of Conventional Well Logs to Characterize Naturally Fractured Reservoirs with their Hidraulic(Flow) Units; a novel approach. Gómez R., A Practical Method for Determining Cementation Exponents and Some Other Parameters as and aid in well log Analisys, The Log Analyst, October, Raymer and Biggs, Matrix Characteristics Defined by Porosity Computations,SPWLA 1963, ALS. Raymer, Hunt and Gardner, Improved Sonic Transit Time to Porosity Transform, SPWLA 21st Annual Logging Symposium,1980. Sneider, J, Curso Taller Integration of Rocks, Log and Test Date, sección Fracture Plausability. Watfa and Nurmi, Calculation of Saturation, Secondary Porosity in Complex Middle, East Carbonate Reservoirs,SPWLA 28th Annual Logging Symposium, Wyllie, Gregory and Gardner, Elastic Wave Velocities in Heterogeneous and Porous, Media, January 1956.