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Abstract This study is based on data from Gulf-of-Mexico (three wells) and West Siberia, Russia (two wells). We find a clear correlation between the NMR signal and depositional environments that also were identified on conventional log diagrams and in cores. Key sediments associated with the regressive bar and coastal fluvial sand sequences (distributary mouth bar, distal bar, delta-front, and pro-delta facies) were defined by predominant type and distribution of porosity and recognized on NMR diagrams. Corresponding distribution of total and effective porosity, permeability and amount of capillary bound water characterized the major depositional environments. Seven rock types (lithofacies) were defined using statistical analysis of porosity/permeability laboratory data, SEM and thin-section description and mercury injection results; four of them were clearly correlated to various shapes of NMR response. The mixed type of porosity (associated with kaolinite cement) and interbeds with carbonate concretions (hardstreaks) were not recognized. The dissolution of feldspar grains in distal mouth bar facies results in significant enhancing effective porosity and permeability. An abnormally height porosity values (higher than 26 pu.) were formed as the result of feldspar and rock fragments total dissolution. Partial dissolution produces a micro-porosity that contains bound water. Results from both processes were recognized on NMR T2 distribution diagram. A dual porosity system was also identified on porosity-permeability cross-plot as two parallel areas. NMR signals characterize the spectral porosity distribution and therefore could be used for various facies differentiation. It provides a unique information on diagenetic alteration especially about total or partial grains dissolution. Best results on quantitative interpretation could be achieved by combining analysis of core data (SEM) and NMR logs. Introduction NMR measurements in reservoirs could be used for a wide range of applications. Although this technique is based on measuring porosity distributed via pore sizes, other parameters such as permeability, amount and type of movable fluids, surface-to-volume ratio also could be derived from initial signal. Recently NMR has been proposed as a unique method for pore and frcature pressure determination and early recognition of abnormally high pressured seals. We analyzed a NMR relaxation time T2 (the spin-spin decay time) distribution in various lithofacies in the regressive bar sequences, of early Miocene age, Gulf of Mexico and Lower Cretaceous age, West Siberia, Russia. More than 120 thin-sections and SEM images were evaluated and tied to spectral porosity distribution from NMR (nuclear magnetic resonance) logs in both basins. Out of seven lithofacies, associated with four major depositional environments, five had a distinct recognizable pattern of NMR data: MSIG, MBVI, MFFI and CBW. Lithofacies Description of the Regressive Bar Sequence Individual lithofacies description and depositional environment interpretation were based on three intervals of early Miocene age sands from offshore wells in Matagorda Island Field (MI622/23 blocks) and two intervals from wells in Samotlor Field. Sedimentological description indicates the cored intervals recovered as a part of coarsening-upward clastic (predominantly sands) sequence of delta front and distributary-to-distal mouth bar with possible presence of prodelta claystones at the very bottom parts. This sequence is overlapped with prodelta - delta front claystones. These conclusions are made based on core observations, and afterwards compared with literature sources and our previous interpretation. Major lithofacial units with correspondent type of predominant pore system characterize each of these depositional facies (see Table 1). Actual values are given for Gulf-of-mexico offshore study.
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.25)
- North America > United States > Utah (0.24)
- North America > United States > Gulf of Mexico > Western GOM (0.24)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.77)
- Geology > Mineral > Silicate > Tectosilicate > Feldspar (0.49)
- North America > United States > Utah > Island Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Samotlorskoye Field (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Since the mid 1990s, when an ambitious program to rejuvenate the Burgos Basin was undertaken, Pemex Exploración y Producción (Pemex) has embraced many of the technologies responsible for increasing gas production in South Texas. These include 3D seismic acquisition and processing, improved drilling and hydraulic fracturing technologies, new logging tools, and comprehensive core studies. However, a critical component to the success of these new technologies is the rigorous application of workflows that integrate the myriad elements required to identify reserves growth opportunities. Key steps in the workflow involve generating and integrating 3D seismic and well depth structures; seismic attribute tests, depositional architecture maps from logs and core, well logderived rock properties calibrated to routine core and SCAL data, volumetric mapping; comprehensive well history and completion analysis, EUR and drainage area bubble mapping; per-fault block recovery efficiency determination, offset analog comparison, and location selection, risking and ranking. Two such integrated studies conducted by Pemex with assistance from The Scotia Group (Scotia) identified substantial future reserves potential and demonstrated the effectiveness of this integrated approach. At Corindon-Pandura, in the northwest corner of the Burgos Basin, for example, integration of the depositional systems interpretation, seismic and structural mapping and analysis of EUR bubble clusters revealed an obvious structural component to reservoir performance that is contrary to the depositional architecture. The integrated analysis also indicated that the effective drainage radius of most wells was much smaller (21–115 acres) than the existing 300 acre well spacing. Comparison to contiguous production in Texas confirmed the need for closer well spacing and indicated that improved drilling and completion practices could increase per completion recoveries by 0.5Bcf. Numerous infill and step-out locations were identified at Corindon-Pandura, with reserve growth potential totalling189 Bcf. Drilling to date includes more than 16 successful completions with initial rates averaging 2.8 MMcfd per well. Similar results were achieved at Mojarrenas-Santa Rosalia where opportunities depended on identifying better primary porosity trends as well as resolving the complex structural influence on reservoir performance. The recent drilling results from the Corindon-Pandura and Mojarrenas-Santa Rosalia field complexes show dramatically the effectiveness of the integrated study workflows being implemented by the Pemex's Reynosa production teams. Characterization of the structural and reservoir complexities of the field areas has enabled Pemex to predict with reasonable certainty the development of target sands. More than 90% of the 72 wells drilled since completion of these studies have been completed and are producing.
- North America > United States > Texas (1.00)
- North America > Mexico > Tamaulipas (1.00)
- North America > United States > Kansas > Butler County (0.24)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Structural Geology > Tectonics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.68)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.46)
- Government > Regional Government > North America Government > Mexico Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Kansas > Rosalia Field (0.99)
- North America > Mexico > Veracruz > Tampico-Misantla Basin (0.99)
- North America > Mexico > Tamaulipas > Tampico-Misantla Basin (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- (3 more...)
ABSTRACT This study is conducted to test and evaluate the use of current methods of reservoir characterization, namely the permeability-porosity correlation, the J-function, and the Reservoir Quality Index (RQI) concepts, for reservoir description of heterogeneous carbonate formations. These approaches were compared with a new technique developed in this paper for improved reservoir description of carbonate reservoirs. This technique is called the Characterization Number (CN) technique and it is based upon considering fluid, rock, rock-fluid properties and flow mechanics of oil reservoirs. To compare these reservoir characterization techniques, measurements of porosity, absolute permeability, oil and water relative permeability and irreducible water saturation for 83 actual core samples extracted from eight different wells for a new oil reservoir in the U.A.E. are obtained. These experimental data are used first to develop a permeability-porosity correlation. Then, the J-function and the RQI concepts along with the newly developed CN approach are applied and evaluated for reservoir description of the UAE carbonate reservoir under investigation. The results show that the Reservoir Quality Index concept is capable of identifying the flow units while the J-function concept is quiet poor. Also, a more refined identification of flow units is obtained by using the newly-developed Characterization Number. This improved description for the Characterization Number approach may be attributed to the consideration of rock/fluid properties of flowing fluid(s) and flow dynamic conditions of its containing formation. INTRODUCTION AND REVIEW Reservoir characterization techniques are quite valuable as they provide a better description of the storage and flow properties of a petroleum reservoir and thus provide the basis for developing its simulation model. Also, carbonate reservoirs, in particular, present a tougher challenge to engineers and geologists to characterize because of their tendency to be tight and heterogeneous. Permeability and porosity of the reservoir rock have always been considered as two of the most important parameters for formation evaluation, reservoir description, and characterization. Beyond evaluating permeability and porosity, one can also use combinations of two or more rock properties to gain insight into the character of flow through porous media. The J-function and the Reservoir Quality Index (RQI) concepts are two of the ways that the oil industry has used to characterize the reservoir media. They incorporate parameters such as porosity and permeability into a single quantity that describes/characterizes the formation. The application of the J-function and/or the Reservoir Quality Index (RQI) concepts, however, may or may not determine whether a formation can be considered to have a single flow unit or multiple ones
- Overview > Innovation (0.71)
- Research Report (0.54)
- Geology > Geological Subdiscipline (0.74)
- Geology > Rock Type (0.46)
Abstract Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vuggy carbonate reservoirs. The vugs are generally considered connected either to the matrix or to the fractures in numerical simulation. One of the challenges of modeling these reservoirs is the partitioning of the porosities into two components since dual porosity reservoir simulators can only handle two rock components, namely matrix system and fracture system. The goal of this study is to characterize the vugs in these systems, and to determine the pore volume compressibility for the simulation of vuggy, naturally fractured reservoirs. Sequential laboratory experiments were designed and conducted to determine the amount of secondary porosity in the core samples. A combination of capillary pressure (centrifuge and mercury injection experiments) and NMR experiments was used to determine the vug or secondary porosity of the samples from pore size and T2 (relaxation time) distributions. The results were compared and reconciled with those from porosity logs and image logs. Pore volume compressibility tests and compaction tests were used to determine the compressibility of each sample. The compaction and pore volume compressibility tests were evaluated at different net stresses to determine the influence of vuggy porosity in the samples. The composite (sample) compressibility versus porosity plots showed that pore volume compressibility increases as secondary porosity increases. This dependence, which is strong at low net stresses, gradually disappears as the reservoir pressure decreases or the net stress increases. This implies that the effects of secondary porosity on pore volume compressibility of the total system are minimal at low reservoir pressures. Based on these results, pore volume compressibility was generated for various values of effective and secondary porosity and served as input data to the numerical flow models. The development of the vug porosity, pore volume compressibility and the construction of the simulation flow model are described in this paper. Introduction Carbonate reservoirs have complex pore systems, which present challenges in wireline log interpretation, conventional and special core analyses and reservoir simulation. Pore distribution ranges from microcrystalline to large vugs or caverns. The petrophysical and productive characteristics of a carbonate rock are controlled by two basic pore networks: an interparticle pore network and a vuggy pore network. Interparticle porosity may be intergranular or intecrystaliine porosity. These are primary porosities. Vuggy porosity is commonly present as leached particles, fractures, and large irregular cavities. The rocks of naturally fractured and vuggy carbonate reservoirs are therefore made up of matrix, vugs and fractures. The fractures and vugs constitute the secondary porosity. The fractures occupy a very small portion of the reservoir volume, have high permeability and dominate fluid flow. The matrix occupies a major portion of the reservoir, stores most of the hydrocarbon in place and has low permeability. The vugs in these reservoirs may be connected to the matrix or to the fractures. Dual porosity simulators consider only the matrix and fracture systems, and oil is produced through the fracture system, which serves as fluid conduits between the matrix and the wells. It is therefore required that the three porosities (matrix, vugs and fractures) be partitioned into the matrix and fracture systems. The characterization of the vugs is critical in assigning rock properties to the two systems during the construction of numerical flow models.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract The objective of this paper are:to summarize a recently developed coupled fluid-flow/geomechancs, dual-porosity model intended to describe the behaviour of naturally fractured reservoirs, and to analyze and compare four other existing models. Conceptual consistency is examined for each model within the concept of dual-porosity. The comparison provides important understanding and interpretation to the complex model parameters. Introduction Geomechanics is particularly important in petroleum reservoir management of naturally fractured reservoirs [Teufel et al., 1993]. Economical petroleum production from most naturally fractured reservoirs relies on the fracture permeability (including magnitude and orientation of anisotropy). Natural fractures basically are the product of evolving reservoir stress state. Therefore any disturbance of the stress field, such as due to fluid production/injection, can affect the existing fractures (e.g., opening, closure, reorientation) and the associated reservoir performance. A coupled fluid-flow/geomechanics model thus provides a rational tool for a better understanding and management of a naturally fractured reservoir. There are five coupled fluid-flow/geomechanics dual-porosity models in the literature. The concept of dual-porosity introduces some difficulties in parameter interpretation and measurement. In this paper, we summarize our model [Chen and Teufel, 1997], and analyze/compare the other four earlier models. Three main purposes of this comparison:To identify and compare the physical interpretations of the rock volumetric changes; To check the internal model consistency within the adopted principles and assumptions of a given model; and To check the model continuity between the single-porosity and dual-porosity concepts. Background Theory of Coupled Fluid-Flow and Geomechanics. The theory describing fluid-solid coupling was first presented by Biot [1941, 1955] in which mechanical issues were emphasized over the fluid flow issues. Because of this, Biot's theory is less compatible with the conventional fluid-flow models (without geomechanics considerations) in terms of concept understanding, physical interpretation of parameters (e.g., rock compressibilities), and computer code upgrading. These issues, however, can be resolved if Biot's theory is reinterpreted along the line of conventional fluid-flow modeling, as done by Geertsma [1957] and Verruijt [1969], and Chen et al. [1995]. In essence, these reformulations provide better compatibility, continuity, and expandability to the existing fluid-flow knowledge and models. The original Biot's theory is a single-fluid/single-solid model, i.e., a single-porosity model from a fluid-flow point of view. Naturally fractured reservoirs are often modeled by the dual-porosity-type of concept to be described next. Concept of Dual-Porosity. The concept of dual-porosity (overlapping-continuum) involves two overlapping continua: matrix-blocks (primary pores) and fractures (secondary pores) [Barenblatt et al., 1960] (also Warren and Root [1963]). Each continuum possesses its own fluid-pressure field. We will use subscript n=1 to denote the matrix-block (primary pores) while n=2 for the fractures (secondary pores), and the subscript s for the solid phase. A bulk fractured medium, Vb, thus is viewed to comprise three components/phases: Vb=Vp1+Vp2+Vs, . . . . . . . . . (1) Theory of Coupled Fluid-Flow and Geomechanics. The theory describing fluid-solid coupling was first presented by Biot [1941, 1955] in which mechanical issues were emphasized over the fluid flow issues. Because of this, Biot's theory is less compatible with the conventional fluid-flow models (without geomechanics considerations) in terms of concept understanding, physical interpretation of parameters (e.g., rock compressibilities), and computer code upgrading. These issues, however, can be resolved if Biot's theory is reinterpreted along the line of conventional fluid-flow modeling, as done by Geertsma [1957] and Verruijt [1969], and Chen et al. [1995]. In essence, these reformulations provide better compatibility, continuity, and expandability to the existing fluid-flow knowledge and models. The original Biot's theory is a single-fluid/single-solid model, i.e., a single-porosity model from a fluid-flow point of view. Naturally fractured reservoirs are often modeled by the dual-porosity-type of concept to be described next. Concept of Dual-Porosity. The concept of dual-porosity (overlapping-continuum) involves two overlapping continua: matrix-blocks (primary pores) and fractures (secondary pores) [Barenblatt et al., 1960] (also Warren and Root [1963]). Each continuum possesses its own fluid-pressure field. We will use subscript n=1 to denote the matrix-block (primary pores) while n=2 for the fractures (secondary pores), and the subscript s for the solid phase. A bulk fractured medium, Vb, thus is viewed to comprise three components/phases: Vb=Vp1+Vp2+Vs, . . . . . . . . . (1)
Abstract This paper is dealing with modeling a heterogeneous reservoir rock from a Mexican offshore field. The problem is porosity characterization through the use of computed tomography images. The addressed issues include: association of secondary porosity with vugs and fractures, vug connectivity and spatial distribution, porosity associated to the rock, and vugs stochastic imaging. Porosity was obtained from computed tomography images, and calibrated with core data. From these images, exhaustive porosity variograms were obtained, showing a correlation range of about 20 millimeters. Further, use of indicator variables allowed vugs visualization, confirming the assumption that dissolution was the dominant process in vugs genesis. It is showed also that permeability has been enhanced through the connection of vugs by high porosity footprints. This detailed information has been used to reproduce geometry and spatial distribution of vugs through a sequential indicator algorithm. The stochastic images reproduce well vugs spatial distribution, explaining the secondary porosity role in the production mechanism in these reservoirs. Introduction A significant proportion of the hydrocarbon production of Mexico, 90%, comes from offshore fields located in the southeast of the Gulf of Mexico. These reservoirs are associated to fractured and vuggy carbonated rocks, where secondary porosity is a major issue. Their main characteristics include rapid variation of rock quality and irregular vug distribution. Both items should be addressed in a geological-petrophysical model to provide insights about properties such as porosity and permeability, giving the base for integration of static and dynamic measurements. In that sense, the goal will be to initiate an effort to characterize the vugs spatial distribution and their connectivity. Rock characterization must recognize the secondary porosity importance through evaluation of vug connectivity and porous space associated to vugs and fractures. This can be accomplished by investigating the spatial distribution of secondary porosity from computed tomography (CT) images of cores, and by reproducing quantitative aspects of these images through a sequential indicator simulation algorithm. Geological Setting Abkatun field is located in the southeast part of the Gulf of Mexico, approximately 80 km northwest from Ciudad del Carmen, as can be observed from Figure 1. Its structure is part of an anticline known as Abkatun-Kaanab-Taratunich-Manik, oriented NW 50° SE, and affected by saline intrusions. Oil production comes from two stratigraphic intervals: Upper Jurassic dolomitic carbonated rocks and Upper Cretaceous - Lower Paleoce dolomitic carbonated breccias. The Jurassic rocks were deposited in a transgressive sequence, from the west to the east in an inner shelf, which changed gradually to more open marine conditions. The regional stratigraphic column is shown in Figure 2. The main reservoir rock was deposited during the Upper Cretaceous, and varies laterally to dolomitic breccias. The Laramide Orogeny was active, and created a debris flow (breccias) deposited as clastic limestone along the shelf margin and the shelf slope for the Tertiary Paleocene. The main diagenetic event is dolomitization. Three main dolospars are identified: early cloudy core, intermediate semiclear rims, and late very clear rims. The latter appears to postdate all others events. Fluid inclusions in semiclear and very clear dolomite rims suggest a burial origin at the range of 2450 to 3800 m. Other important diagenetic event is leaching, which enhanced the primary porosity and created a complex network of high porosities and high permeabilities. Occasionally, fracturing connected this network, enhancing even more, the original petrophysical properties.
- North America > Mexico > Gulf of Mexico > Bay of Campeche (0.25)
- North America > Mexico > Campeche > Ciudad del Carmen (0.24)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.69)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.54)
Abstract A new formulation for determining formation resistivity factors of fractured porous media is presented. For establishing the mathematical model, a fractured medium is idealized as a cubic arrangement of cubic matrix blocks (Warren and Root model). Experimental results which validate the new formulation are given. The work is aimed at obtaining a reliable tool to aid in the interpretation of electric well logs of naturally fractured reservoirs. Introduction Naturally fractured reservoirs are among the most productive of the world. Reservoirs of this type are commonly found in Algeria, Iran, Iraq, Noth Sea and Mexico. An important aspect of fractured reservoirs is that flow properties of this type of systems are somewhat different from those of continuous porous media. For instance, diffusion, convection and pressure changes phenomena behave differently in both cases. Due to the huge amounts of oil that are extracted from fractured reservoirs, it is important to do extensive studies concerning the different phenomena associated with fluid flow through such systems. One of these phenomena is electric flow. Its study is fundamental for improving electric well logs interpretation techniques. There is experimental evidence showing that Archie's equation,1 which applies to continuous porous media, does not hold for fractured media. Consequently, the main objective of this work is to propose a new formulation for correlating formation resistivity factor and porosity of fractured media. The developement of the analytical model is based on two fundamental considerations:A simple and effective way of idealizing a fractured medium is through a cubic arrangement of cubes (Warren and Root model,2 Fig. 1) where the cubes represent matrix blocks and the spaces between cubes represent fractures, and the electric current flows essentially through the fractures. The first consideration is based on the fact that the Warren and Root model has given good results when applied to the interpretation of pressure well tests of naturally fractured reservoirs, and the second consideration is supported by direct laboratory experimentation. In this paper, experimental results of formation resistivity factor for cubic arrangements of cubes are presented. Also an attempt is made to fit an Archie's type equation to the experimental data, showing that it is not possible to obtain a good match. Likewise an analytical one-parameter model, based on physical considerations, is developed. It is shown that this model fits experimental data very well. Also, it is shown that it is valid for random packings of cubes. Experimental Work Consider a cubic arrangement of cubes made of an insulating material, as the one shown in Fig. 1. If the system is saturated with an electrolyte, and an electric potential difference is applied between opposite faces of the arrangement, a repetitive pattern of lines of current is established; that is, the distribution of lines of current around a cube is identical to the distribution around any other cube. In this case, it is said that each cube with its surrounding space constitutes an elementary cell with identical characteristics to the others. This repetitive property allowed the use of a single cell to determine formation factors of cubic arrangements of cubes by the procedure indicated below.
- North America > Mexico (0.35)
- Asia > Middle East > Iraq (0.24)
- Asia > Middle East > Iran (0.24)
- Africa > Middle East > Algeria (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Computarized Tomography (CT) and Digital Photography (DP) are new naturally fractured reservoir engineering imaging techniques that measures density inside fractured cores and micromodels samples during laboratory experiments. An image processing method for determining, simultaneously, some of basic geometrical characteristics of homogeneous and fractured porous media such as porosity, specific surface, mean pore width, mean grain thickness, mean fracture width, and absolute permeability is presented.The proposed method is characterized by its simplicity and by use of a X-ray tomography equipment and a digital camera. The experimental procedure used to evaluate various geometrical characteristics is based upon the surface analysis of a sample for a digital camera and upon a cross-section of a core model for a X-ray CT. In view of this fact, the applicability of the method is extended for heterogeneous and anisotropic samples such as fractured and vugged cores and micro models. Four experimental cases, digital images included, are presented: homogenous, one fracture, one vug, and a combination matrix-fracture-vug.Finally, two experiments of imbibition in fractured systems of one and four blocks of Berea sandstone are presented, where digital image process in procedure has been applied in terms of water saturation. Introduction The behavior of flow of fluids through a porous medium depends, among other things, upon the internal geometry of the medium; hence the importance of developing efficient methods to determine the internal geometrical properties of porous materials. This paper describes an image processing method to determine simultaneously some of basic geometrical properties of the porous materials such as porosity, specific surface, mean pore width, mean grain thickness, mean fracture width, absolute permeability and fluid saturation. The mathematical formulation has been developed by Perez-Rosales 1, that the required data to calculate the various geometrical characteristics of a sample can be easily measured by analyzing a digital image of the sample with an evenly spaced grid of pixels. Theory A simple way to obtain information about the internal geometry of a porous material is to throw a point at a random over a cross-section of a sample. Through this procedure the porosity can be determined. By considering that the material is homogeneous and isotropic, and the point is dropped many times, the porosity f is given by Equation 1 Where N is the total number of times the point is thrown and n is the number of times the point falls within pore zones, N is also the area of the studied model in pixels in a digital image.
- North America > United States > West Virginia (0.25)
- North America > United States > Pennsylvania (0.25)
- North America > United States > Ohio (0.25)
- North America > United States > Kentucky (0.25)
- Media > Photography (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract This paper shows the methodology and results from the Integrated Study performed to the Abkatún, Pol and Chuc Reservoir Complex. These three fields, account for the largest light oil reserve in the Gulf of Campeche. Proven communication through the associated acquifer established the need of grouping the three fields in one simulation model. The main producing formation is a fractured, vuggy carbonate breccia. The complex nature of porosity in the Breccia, received a special treatment. Vug percentage and vug connectivity maps were created to properly distribute vug porosity into matrix and fracture systems. Based on special core analysis and core flooding simulation, relative permeability and capillary pressure pseudo curves were developed to mimic the flow in the composite matrix + vug system. Emphasis is made to show that this study is the result of a sustained effort to acquire data throughout the life of the reservoirs, its analysis and interpretation by geoscientists, reservoir, production and facilities engineers. Introduction Reservoir models generated through integrated studies are the main tool for Reservoir Management. In most of these studies part of the input data, comes from existing correlations and data from neighboring fields with similar conditions. During the producing life of the Abkatún-Pol-Chuc Reservoir Complex, data acquisition programs have been performed which involve welltests, conventional and production logs, coring, fluid sampling, interference test and tracer studies since the start of water injection. These information after a complete quality control analysis, proved to be of great value providing key parameters for reservoir description throughout the study. A relevant aspect of the study was the definition of porosity in the Breccia Formation. The vuggy nature of the reservoir rock required construction of vug connectivity maps to distribute vug porosity into matrix and fracture systems. This porosity received a special treatment to build relative permeability and capillary pressure pseudo curves for a matrix-vugs composite system. Data Collection and Validation Sorting and validation of data was done at the beginning of the study to use as much as possible of the information gathered in 16 years of producing history of the reservoir complex. In this phase among other activities, representative PVT analyses were chosen for each of the three reservoirs. Welltests and cores suitable for analysis, along with temperature gradients and produced fluids properties were also selected. Oil, gas and water production data were reviewed together with operating conditions of the surface network. A preliminary evaluation of the measuring system posed some uncertainties in the individual well production allocation, due to low periodicity of well tests in some wells, lack of individual well measurement and the mixing of production streams in the separation platforms. Since production data plays an important roll in the history match process, a detail analysis of the measurement system in the whole Region was proposed. The measurement study proved the applicability of production data to the reservoir model history match process. Table 1 includes the general characteristics of the Abkatún, Pol and Chuc Reservoirs.
- Phanerozoic > Cenozoic (0.47)
- Phanerozoic > Mesozoic > Cretaceous (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Abkatun-Pol-Chuc Field > Pol Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Abkatun-Pol-Chuc Field > Chuc Field (0.94)
Abstract The large, naturally fractured reservoir under investigation is unique with its highly heterogeneous carbonate characteristics. The largest hydrocarbon bearing formations are not only naturally fractured, but also have matrix and vuggy porosity. Special relative permeability, capillary pressure, and compressibility relationships were developed to simulated multi-phase flow in this triple porosity system. Well and interference tests were re-analyzed at several stages in the project to provide input to geology on fracture properties and later to condition the fracture properties coming from the geologic model. The calibrated model acceptably matched the historical pressure and the production of oil, water, and gas for the reservoir complex. Introduction The study area in the Bay of Campeche encompassed more than 900 km and included three separate structures (Figure 1). These structures provided the trapping mechanism for the Abkatun, Pol, and Chuc fields. There are 55 major normal and reverse nature faults that were identified from seismic, conventional borehole logs, and borehole image logs. The reservoir has an overall average thickness of 570 m. The reservoir consists of Upper Cretaceous to Lower Paleocene carbonates of varying composition and fracture intensity. The upper, main reservoir is named "Breccia", and belong to the Early Paleocene. This formation consists of clasts of varying lithology and size, and has secondary porosity in the form of vugs, which vary in size from millimeters to meters in diameter. This paper documents key elements involved in construction of a representative numerical model of a triple porosity reservoir. The main objective of the project was to construct a model that can be used as a predictive reservoir management tool. Triple porosity reservoirs have been described in the literature in many different forms 1,2. The triple porosity reservoir under investigation in this work is unique with its highly heterogeneous carbonate characteristics. The largest hydrocarbon bearing formations in the reservoir are not only naturally fractured, but also highly vuggy. Some of the vugs are connected through the fracture network while others are non-connected and trapped in the matrix medium. Numerical simulation of the behaviour of multi-phase flow within this triple porosity system required special multi-phase flow functions i.e: relative permeability, capillary pressure, and compressibility relationships. General There is no one standard approach for numerical modelling of multi-porosity reservoirs in the oil industry. Most of the time, data availability dictates the approach. Technical approach taken in this project was designed to use all static and dynamic data in the construction of a representative numerical model. In order to achieve that level of integration, additional iterations were found necessary in every phase of the project.
- North America > Mexico > Gulf of Mexico > Bay of Campeche (0.54)
- North America > United States > Texas (0.46)
- Phanerozoic > Mesozoic > Cretaceous (0.68)
- Phanerozoic > Cenozoic > Paleogene > Paleocene > Danian (0.54)
- Geology > Structural Geology > Fault (1.00)
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.68)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.67)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- (4 more...)