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3D Geological Model of Bare Field reservoirs, Orinoco Heavy Oil Belt, Venezuela*
by
Arturo Calvo1
Search and Discovery Article #40148 (2005)
Posted April 3, 2005
*Adapted from extended abstract, prepared by the author for presentation at AAPG International Conference & Exhibition, Cancun, Mexico, October 24-27, 2004.
1Gerencia de Exploración, PDVSA-División Oriente, Puerto La Cruz, Estado Anzoategui, Venezuela.
Abstract
The Orinoco Heavy Oil Belt is located in the southern part of the Eastern Venezuelan Basin, to the north of the Orinoco River. It covers an area of 54,000 km2 in the Monagas, Anzoategui, and Guarico states. A three-dimensional geological model of the most prospective reservoirs located within the Tertiary Lower Oficina Formation has been developed in an area of 188 km2 within the Bare-Arecuna fields, using 3D seismic surveys and subsurface information from 48 wells. The reservoir characterization has been defined, based on seismic and geological interpretations and applying seismic-stratigraphic concepts. Additionally, sedimentology, petrophysical, and reservoir engineering data were used to define the geological model of the area with the purpose of detecting sandy reservoirs and calculation of the OOIP and the recoverable reservoirs. The depositional environment is interpreted to have been fluvial with braided channels of moderate energy. A two-normal-fault-system structural model, together with the stratigraphy and petrophysics, helped with the development of a three-dimensional static model, which allows formulation of plans for future exploitation and the evaluation of profitability.
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DatabaseThe database for this study consists of a 3D seismic survey within the Bare-Arecuna fields covering over 188 km2 and approximately 240 log curves from about 48 wells (Figure 1). These logs included Gamma-ray, SP, resistivity, density, neutron, and sonic. Another type of data included water and hydrocarbon saturations (Sw, So), intrinsic permeability (K), effective porosity and shale volumes (Vsh). All of these data were loaded in the GeoFrame© 3.8 computerized platform from GeoQuest©. The wellbase information, such as location, geographic coordinates, shot point maps, cultural, petrophysical, and production information, was loaded in the Finder© database manager. Sixteen cross-sections, covering the whole area of study, were constructed and analyzed, using the Stratlog© and Wellpix© software. The correlation of nine genetic units with their corresponding flooding surfaces and facies definitions was used to generate a set of maps in the CPS-3© software in order to visualize and model the structural setting of the different layers.
Seismic InterpretationThe interpretation of the seismic data, integrated with the well information, was used to prepare structural maps of the three main flooding surfaces and of the basement identified in the correlation of 48 wells located in the study area. Seismic velocities were analyzed in detail in order to have an acceptable conversion of time to depth of the interpreted seismic horizons (Figure 2). Structural correlation of three key flooding surfaces (FS-20, FS-62, and FS-68), as well as acoustic basement, allowed compartment demarcation throughout the seismic data volume and contributed to establishing reservoir limits through the integration of geophysical, geological, petrophysical, and production data. Structural analysis revealed several episodes of faulting, identifying the NNW-SSE and NNE-SSW faults as being the most important for hydrocarbon entrapment (Meléndez, 1998). Once the seismic correlation was completed, the variance seismic cube was generated in the GeoCube© application.
Geological FrameworkStructural MapsFaults were identified using 3D seismic data. Using the Charisma© software, time maps corresponding to four seismic reflectors and previously tied to geological tops, were converted to depth maps, and structural maps were prepared for the nine genetic units. Subsequently, the CPS-3© software was used to visualize and generate the final structural maps with the best geological subsurface configuration. The Original Oil in Place (OOIP) for these areas was estimated to be 233 MMSTB; recoverable oil was estimated to be 32 MMSTB (Figures 3 and 4).
StratigraphyThe interval of study covered the most prospective reservoirs located within the Tertiary Lower Oficina Formation, with an average thickness of approximately 1500 ft of fluvial sediments (Figure 5). Modern concepts were used to make stratigraphic correlations based on the definition of stratigraphic sequences (Galloway, 1989). Regional shales were identified that were deposited in the fluvio-deltaic environment of the prospective Oficina formation in the Bare area (Figure 6). The concept of facies was applied to define the sedimentological model for each genetic unit deposited between two flooding surfaces. Previously, the Gamma ray well logs were analyzed to identify the blocky, coarsening upward, fining upward, and serrate sequences. Six facies were defined in a fluvial system: A (braided channels sands), B (meandering channels sands), C (crevasse splay sands), D (sandy sequences), E (clays), and F (coals) (Flores and Arias, 1996).
Petrophysical AnalysisIn order to evaluate petrophysically the interval of interest, data were gathered from tapes (SP, density, neutron, Gamma ray, sonic, and resistivity logs) and from the Finder© database. The data was then edited and depth-matched. Data from cores, such as mineralogical analysis, X-ray diffraction, and lithological core description from well MFA044 ( Casas, 1999), were used to create the petrophysical model, which consists of sandstone, illite, kaolinite, and fluids (oil and water). The petrophysical parameters were estimated from the core analysis and Pickett plots: Saturation Index (n)=2, Saturation exponent (m)=2, Coefficient of tortuosity (a)=0.81, and the Water resistivity (Rw)=0.34. In order to calculate the total net pay, the following cutoffs were used: Shale Volume (Vsh) < or=30%, Effective Porosity (fe) > or=20%, and the Water Saturation (Sw) < or=50% for which relative permeability curves were used (Bureau of Economic Geology, (1997) (Figure 7).
ConclusionsBased on the integration of stratigraphic, structural, and petrophysical analyses, the 3D geological model in the area of the Project MFB165 was defined, and subsequently, the static model of the existing reservoirs in the study interval. The whole database was preserved in a "rescue" file; then up-scaling to the dynamic model will allow for establishing the best strategy of future exploitation. Through the construction of the stratigraphic model and, specifically, the correlations made in 16 sections, 15 flooding surfaces (FS), with an additional marker (R4), establish the limits of nine genetic units; from bottom to top, they are designated as 90, 70, 69, 68, 65, 63, 62, 60, and 50; there are three sands of economic interest: U1- 2, S1-2, and R4. Stratigraphic analysis corroborates the pinchout of the Cretaceous to the southeast. The structural model was assembled, through integration of four seismic horizons and 23 fault planes interpreted along three seismic surveys in the Arecuna- Bare area. This process subsequently allowed generation of structural maps for 15 flooding surfaces. The structure observed with 3D visualization corresponds to a homoclinal bowed slightly to the north, with dip of the sedimentary sequence in the basal sands of the Oficina Formation, not greater than 1°, contrasting with the inclination of the basement, which is greater than 2°. The structural model corresponds to an extensive system of two very defined episodes: the first with faults of northwest-southeast direction, displaced slightly by other faults with northeast-southwest trend. The two families of normal faults have dips around 80°, throws not greater than 90 feet, and cutting the Basement to the top of the Oficina Formation. The petrophysical evaluation for the sedimentary sequence studied is as follows: average values of porosity around 29%, permeability of 1498 millidarcies, water saturation of 36%, oil saturation of 64%, and 13% clay content. Likewise, the values in the sands of commercial interest vary as follows: porosity—28-32%, permeability--1354-4040 millidarcies, oil saturation--66-74%, and clay content--12-14%. Through the calculations, 54 petrophysical maps (porosity, permeability, water saturation, net thickness, net pay) were obtained for nine genetic units, along with reservoir maps for three sands of interest. The OOIP was estimated to be 233 MMMSTB and recoverable reserves to be 32 MMSTB.
ReferencesBureau of Economic Geology, 1997, Targeted horizontal wells for maximizing recovery of heavy oil resources: Arecuna Field, Venezuela: The University of Texas at Austin Internal Report for Corpoven S.A., Puerto La Cruz. Casas, J., 1999, Core data for the Ameriven Project: PDVSA-Faja Internal Report for Ameriven S.A., Caracas. Flores, D., and Arias. W., 1996, Caracterización del Yacimiento MFB-53, Trampa B-15, Faja Petrolífera del Orinoco: Ingepet ’96 Internacional, Petroperú. Lima, Perú. Galloway, W., 1989, Genetic stratigraphic sequences in basin analysis I: Architecture and genesis of flooding-surface bounded depositional units: AAPG Bulletin v. 73, p. 125-142. Meléndez, L., 1998, Interpretación Sísmica 3D, Área Arecuna-96: PDVSAEPM Internal Report for the U.E.I-XP San Tomé. Puerto La Cruz. |
