Bellorin, William Enrique (Petrobras Energia de Venezuela) | Castillo, Jose Antonio (Petrobras Energia de Venezuela) | Lopez Kovacs, Sonia Isabella (Petrobras) | Riera, Ladimir Alberto (Petrobras Energia de Venezuela)
The study area has produced over 457 MMBbl of oil since its discovery in 1954. This study is focused on the R sand reservoir, one of the most important of the area. The original oil in place (OOIP) is 140 MMBbls and before the begining of the project, the accounted recovery of OOIP was 7.2%.
The field reactivation was performed after a thorough analysis that included a geological model review and creating a numeric simulation model. This resulted in an increment of the field production which reached up to 7000 Bbls/d of oil and an enhanced recovery factor of 13.6% by March 31st, 2005.
The main producing zone of the study area comprises Early to Mid Miocene (Oficina Formation); it is interpreted as interbedded sandstone, deposited in a fluvial environment with marine to shallow marine influence. Core analysis in one well shows that R sand was deposited in coastal plain influenced by tides and characterized by connected channels and outlets. The 3D seismic information available in the area made it possible to accurately define the structural model. After defining the static model and with the support of the engineering study, the reservoir development plan could be defined, which was oriented to improve and to increase the field productivity. It mainly consisted in drilling horizontal wells where succesful results were obtained after drilling and completing seven wells. This shows the impact of this type of wells in terms of economic benefits resulting in an increment in production and the recovery factor.
The study area, is located approximately 400 km to the south east of Caracas, in the Area Mayor de Oficina. Structurally, the field is located in the southern flank of the Eastern Venezuelan Basin, in the foreland platform zone (Parnaud et al., 1995) (Fig. 1). The reactivation project of the R Sand reservoir resulted from a previous study of characterization that allowed elaborating a plan of operation constituted mainly by horizontal wells producing with high volume electrical submersible pumps from 7,000 to 20,000 BFPD. To date 7 horizontal wells throughout the reservoir have been drilled; they produce between 300 and 1100 BPPD. At the end of 2003 an electrical submersible pump with capacity to produce 20,000 BFPD was installed representing the first in its class of Petrobras in Venezuela. The definition of the stratigraphic and the structural model as well as the simulation of the reservoir played an important role in deciding the location of the horizontal section of wells. The reservoir is delimited to the south by a main fault east-west oriented, that has a vertical throw of 400 feet, to the north a water oil contact at -6760 feet, to the east by a secondary fault of direction NE-SO of 280 feet of vertical throw and to the west by a structural closure against the main fault of the area.
The producing sands of the Oficina Formation of which the R sand is part of, are included in a foreland megasequence of the Maturin Sub basin which in turn is part of the Eastern Venezuelan Basin (Fig. 1). This Neogene foreland basin is superposed to a Mesozoic passive margin (Di Croce, 1995). The Eastern Venezuelan Basin is subdivided in the Guárico and Maturin Sub basins; they are separated by the Anaco fault system (Di Croce, 1995). The South and east limits of the Eastern Venezuelan Basin are, respectively, the Guayana Shield and the Deltana Platform (Di Croce, 1995). The Maturin Sub basin constitutes the main hydrocarbon unit of the basin. To the south of this Sub-basin, the important reservoirs are in the Merecure and Oficina Formation (Fig.2), with seals of shale within these units overlain by an important and extensive seal of shale of regional character corresponding to the Freites Formation (Upper Miocene). The API gravity of the crude is very diverse, varying from light crude to heavy and extra-heavy crude. As to the oil systems of the Maturin Sub basin, one of the most important ones is the denominated Guayuta-Oficina that is related to the fields of the South flank of the sub basin and includes the main source rocks of Late Cretaceous age, Querecual and San Antonio Formations.
In order to improve the seismic imaging and delineation of a reservoir, an OVSP was run in an exploratory well; Neuquén Basin; Argentina. A second purpose of this acquisition was to accurately locate an Intermediate Casing above the main target. Acoustic Impedance Inversion of the corresponding Zero Offset VSP plus the image interpretation generated from the OVSP data helped to define the position of a sill, which was one of the objectives in this project.
The thick (hundreds of meters) and extensive Auca Mahuida volcanic complex which covers most of the region, considerably reduces the signal to noise ratio of the seismic data; strongly attenuating the high frequencies of the data due to wavefields dispersion, hampering their separation at the processing stage. This effect is stronger in surface seismic than in borehole seismic, due to greater offset and two-way traveltime, so that VSP is used as a tool in this environment. Therefore, Q factor estimation (and consequently Q inverse filtering application) computed directly from Zero offset VSP, is a very valuable technique which allowed us to recover high
frequencies in the field area improving vertical seismic resolution and helped to define the reservoir with greater accuracy.
An acoustic impedance inversion of the VSP trace was later obtained, and its interpretation was very useful to predict impedance variations, related to lithology and formation changes in the deeper portion of the stratigraphic column. This was the first deep exploratory well (4750 meters) in this part of the basin, so the implemented technique led to define deep formation tops.
The acquisition was performed by Schlumberger using the multilevel 3C high-fidelity downhole tool, Versatile Seismic Imager (VSI). It was used two vibrators simultaneously in flipflop configuration for both source positions in order to reduce the operational time.
In this paper we describe the objectives, methodology and results of a Borehole Seismic Job performed in an exploratory well, YPF.Nq.LoAm.x-1 (Loma Amarilla), La Banda Block, Neuquén Basin. This block is entirely covered by volcanics from Auca Mahuida Igneous Complex. At the well location it was estimated 100 to 150 meters of surface volcanics.
So that, in this area, the 3D seismic volume acquired in 2003, presents a poor to fair signal to noise ratio; and low frequency content (Fmax ˜40 Hz). Fig. 1.
The main targets of this project were two igneous bodies, intruded as sills; the deeper one in Cuyo Gr.; and the shallower in the Vaca Muerta shales.
Fig 1: Visualization of Borehole, 3D Seismic, Satellite Image and Topography.
The presence of basalts in the area is affecting the recovery of high frequencies reflected in the subsurface; for this reason, surface seismic is very poor in terms of resolution and it is expected that the image obtained through the OVSP helps in the interpretation of the area. The job was planned in 2 phases, intending to acquire a ZVSP from surface to 2480m in the first phase, for the second phase a ZVSP from 2480m to 3580m and also an OVSP. The first VSP data was used to calibrate the model and determine the best position for the OVSP (based on survey design). In the second phase, Q factor was estimated using ZVSP, a migrated image was obtained
from the OVSP, and an Acoustic Impedance Inversion was performed using the ZVSP. Finally, all the information was merged to obtain a complete time-depth relationship, corridor stack and Q factor estimation.
Oil identification and quantification in low resistivity laminated sand-shale sequences is a major challenge for petrophysics and reservoir engineers; essentially because the thickness of the sand laminas is usually bellow the vertical resolution of the resistivity logging tool. The presence of this lithology generates electrical anisotropy where horizontal resistivity is highly affected by the conductivity of the laminar shale volume, while vertical resistivity is higher and more sensitive to the laminar sand electrical properties. Once identified the productive low resistivity problem the prediction of movable water, creates enormous uncertainty when it comes to decide if this laminated sand should be open to production in the well. All this issues have caused the underestimation of Oil-In-Situ volumes and the lost of thousands of oil production per day in the upper Misoa Formation Reservoirs in western Venezuela. The incorporation of resistive image logs in the geological analysis of upper Misoa Reservoirs, have shown the existence of thinly laminated sand-shale sequences with laminations of an inch thick and less.
Traditionally the sands with resistivity values of 20 ohm-m and above are considered as potential oil bearing reservoirs. This assumption has been made with conventional induction resistivity tools with transmitter and receiver orientation parallel to the borehole axis, therefore providing horizontal resistivity. Recently a multi-component transmitter-receiver induction tool has been used to derive both horizontal and vertical resistivity in a section of upper Misoa Formation with resistivity values in the very limit of the pay cuttof. The 3D array induction tool showed the vertical resistivity of this reservoir, to be as high as 80 ohm-m, adding up to 30 % more of oil saturation in the laminated sands. In the decision process of shooting this sands, the mobility of the water remained unknown; until, magnetic resonance measurements where included in the study. 2D analysis of T2 and diffusivity indicated that 90% of the water contained in the reservoir was irreducible, so it would not be produced.
After completing the low resistive sands, production logging tests and well production showed 1300 BBD with 4% of water. This case opened a great opportunity in western Venezuela fields where this type of lithology can be found in most of the wells drilled trough Eocene reservoirs.
Petrophysical evaluations of thinly bedded, laminated reservoirs, such as the upper Misoa Formation in Maracaibo Lake Basin, are incorrect if traditional, empirically derived ‘bulk volume' effective porosity effective saturation models are employed. Resistivity measurements in these reservoirs, with moderate laminar shale content, are besieged by the high electrical ‘parallel conductivity' effect of the laminated shales that results in the classic low contrast, low resistivity shaly sand problem as noted by Worthington (1997). These laminated shales however may have little effect on the intrinsic reservoir properties of the sand laminae. The use of improper models, in many cases, may result in underestimation of reservoir potential and hydrocarbon reserves by as much as 40%, as noted by van den Berg and Sandor (1996). Mollison (1999) developed an analytical model and sensitivity analysis, using an orthogonal tensor resistivity model, based on electrical anisotropy (RV/RH), that is a far more accurate and robust solution than single scalar parallel conductivity models. The tensor model is easily implemented for isotropic and anisotropic shales with isotropic sands. For the solution of anisotropic sand and shale, the laminar shale volume must be determined from some external model such as Thomas-Stieber and can be geologically validated with image log data. True laminar sand porosity must also be derived from the Thomas-Stieber (1975) model and is essential to true laminar reservoir characterization. Once determined the total porosity and water saturation of the laminar sands, irreducible water saturations must be consider and compared to total water saturation in order select the intervals with reduced chance of producing water. I order to achieve this task NMR and 2D analysis can provide an accurate volume of non-movable water bounded to clays and capillary forces.
Perez, Laura Elena (Ecopetrol SA) | Gonzalez Mosquera, Julio Gabriel (ECOPETROL) | Gomez Ramirez, Vicente (ECOPETROL) | Lozano Guarnizo, Eduardo (ECOPETROL) | Tirado, Luis Sarmiento (ECOPETROL) | Vargas Medina, Jose Arnobio (ECOPETROL)
In the current and future scenario of an increasing demand for hydrocarbons, many companies have oriented their efforts to maximize the recovery in mature fields. This paper presents the implementation and results of an integrated reservoir management strategy that allowed revitalizing a field, which was previously considered as a marginal and currently is one of the main assets of the company.
Yarigui-Cantagallo Field, Colombia, is a compartmentalized, varying-dip monocline, with three main tertiary reservoirs. The field was discovered in the 1940`s and reached its production peak of 20,400 STB/day in 1962 after two aggressive drilling programs. A third drilling campaign in the 1980's had poor results and no additional wells were drilled. At 1999 production declined to 5,000 STB/day. In order to mitigate production decline, and maximize final recovery, integrated reservoir characterization including structural, stratigraphic, and petrophysical reinterpretation, geostatistic modeling, advanced production analysis, PVT and pressure reinterpretation, and reservoir simulation have been conducted.
An effective reservoir management has been implemented, including infill drilling, optimized well completion, hydraulic fracturing and production optimization. As a result, production levels had increased up to 13,000 STB/day and 40 MMSTB of reserves have been incorporated. Future implementation of a waterflooding project and additional infill program will incorporate 35 MMSTB of reserves.
CO2 injection is one of the most efficient methods used to improve oil recovery, and, as world statistics shows, its use has increased recently. Under a high crude oil price scenario, field applications of enhanced oil recovery (EOR) processes are becoming economic in today's environment. The natural CO2 sources come to be an excellent opportunity because of its low cost. Since 60 years ago, 2500 km2 of carbonate formations containing CO2 were discovered in North of Mexico.
The Quebrache region contains several occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbonate formations in this region is present in concentrations that can exceed 90% purity. Due to the high concentrations of CO2, some wells were shut-in 60 years ago, others, have been developed for CO2 production intended for industrial uses and some others as a source of gas lift operations in nearby heavy oil fields.
Recently, a plan of acquisition of information and studies to evaluate the CO2 proven reserves has been designed. In addition, analysis of wells deliverability of these natural CO2 reservoirs, located in the southwestern portion of Tampico, has been carried out. In order to understand better this field, a geological model was built and its dynamic behavior and potential was examined through several well tests. Results of the interpretation of these tests showed excellent results associated with a reservoir of good permeability, high conductivity, large drainage radius, etc. According to the geology of this region and the geochemical signatures observed, the CO2 of Quebrache field has an inorganic origin.
This paper discusses the evaluation of potential supply of CO2 of Quebrache reservoirs for EOR projects in the North of Mexico. The main region studied contains estimated proven reserves of 1.9 Tscf of CO2; however, this volume could be extended to larger amounts associated to areas under study. The CO2 from Quebrache field could be the beginning of a new era of EOR projects in Mexico. A field example of potential EOR application in a mature oil field is shown.
The interest in and demand for natural gas in the past few years has dramatically shifted the focus for many operators. Plunger lift, which for many years was viewed as a last resort, and somewhat of a nuisance, has gained an all time high in popularity and effectiveness and applicability. Much of the guesswork in evaluating candidates has now been replaced with exotic programs that combine Nodal analysis with performance based calculations.
In recent years both equipment and applications have improved, and the production range of plunger lift now includes many wells previously not possible to produce with plunger lift. Being able to correctly assess applicability, and identify the best type system is reducing the trial and error process previously associated with plunger lift evaluations and operations.
This paper describes the use of neural network approach as a time series tool to represent the field as a black box, to make predictions of fluid production.
The classical tools available and widely used are numerical reservoir simulation and analytical methods, like decline analysis and material balance. These classical methods are not problem-free. Although the analytical methods are easy to use, sometimes they do not provide good results in several situations (changes of injection rates, opening or closing production intervals, etc.). On the other hand, numerical reservoir simulation, which usually gives better results, it is a very complex tool that may require several months to build a flow model of a field, especially when the field to be modeled is a mature field with several years of production history. Besides that, the flow models require an update from time to time, usually once a year, that also requires a lot specialized work for a long time.
Neural network techniques were applied in two sets of data from real fields to evaluate the possibilities of using this technology in this specific problem using only a small amount of production data as input for the predictive method. For that situation a short term prediction was performed. A synthetic reservoir was also used to generate a long production history in order to test how the technique would behave in a long term production forecast. For both cases, a comparison with classical methods is presented. Neural network architecture design and optimization techniques are also discussed. Results showed that the neural network models performed better than the decline curve analysis in all cases.
The conventional material balance methodology for fractured fields considers a single system with double porosity, compressibility, saturations, etc.
The method proposed in this paper employs a double reservoir concept.
The stratigraphic record of the Altiplanicie del Payún area, in the Northern Platform of the Neuquén Basin, Argentina, includes Tertiary sills and laccolites that reach thicknesses of up to 600 m. Occurrence of thermally immature oil-prone shales of the Late Jurassic Vaca Muerta and the Hauterivian Agrio Formations is profusely documented in the area. However, when sills have intruded the Vaca Muerta shales, source rock sections become mature, displaying a wide-ranging maturity spectrum spanning thicknesses that exceed 400 m.
Commercial oil accumulations (20-33°API) and oil shows are found along the entire column, both in sandstone/carbonate reservoirs and fractured intrusives reservoirs. Oil-oil and oil-source rock correlations suggest a local generation related to the thermal effect of the intrusive bodies. Concurrently, diamondoid analyses point to mixtures of high-mature (cracked) with low-mature hydrocarbons: oils generated and cracked close to sills are considered to be mixed with oils generated from more distant source rock sections less affected by the thermal effect of the igneous bodies, as they migrate towards the sills and shallower reservoirs.
A 2D model that included the thermal effect of the three main igneous bodies of the area was satisfactory achieved, accounting for thermal maturation, oil and gas generation, migration and accumulation. From the modeling, hydrocarbons migration is favored by elevated generation pressures, source rock fracturing and convective water flows.
The integration of geochemical data and 2D-modeling of petroleum generation and migration related to the thermal effect of the igneous bodies led to the better understanding of this atypical petroleum system.