This study is based mainly on the Cubagua formation belonging to the Dragon field, where the intervals of interest of the deposits are poorly consolidated and the cementation of the grains of sand is poor, as to be able to withstand the efforts applied as a result of the passage of the produced fluids through them, being able to start the phenomenon of sandblasting. The realization of this work consisted of the use of the BP-Willson methodology
In order to get a full petrophysical evaluation from log-based traditional techniques in every location, the formation density is needed in wire-line log measurements; otherwise, with a limited amount of information in terms of porosity values, the reservoir characterization has more uncertainty. That is, the case study of the giant Bachaquero-02 reservoir, there is a lack of Rhob data in the spatial data sets that prevent a good assessment of the storage capacity in the petrophysical model and thus wrong original oil in place estimation. This paper, therefore, presents a solution to this problem; this work develops a methodology for predicting formation density values which establish a link between probabilistic interpretations from multi-mineral solution and deterministic predictions from multiple linear regression with the main objective of seeking a mathematical expression which describes the best fit for the Bachaquero Member and Laguna Member in each location. The manner of estimating formation density can vary according to the available data in well logs, as a first step, this technique uses classic lithology indicators from well logging such as gamma ray, spontaneous potential and resistivity index to calculate the most probable minerals in the rock with the purpose of assessing a probabilistic approach, the second stage is to create a prediction model with surrounding wells, the input data, which is the probabilistic outcome and measured logs, it is trained using a'least squares' regression routine that will find the best fit in the data for bulk density reckoning. A reliable formation density profile according to the lithology of the reservoir was obtained for each well. The model shows more than 0.9 of correlation coefficients between the density measured by wire-line services and the new bulk density reproduced in this method. Particularly, the Bachaquero-02 reservoir has a notorious heterogeneity along the stratigraphic column; the Bachaquero Member has different depositional environment and rock properties in comparison with Laguna Member which has poor quality reservoir rock. This workflow has the ability to incorporate reservoir heterogeneities in the probabilistic module without a problem. 2 SPE-191163-MS
Estimating reserves is one of the most important steps in the oil industry by which the hydrocarbon volumes in a field are evaluated economically. The principal objective of this work was to present an analysis of the main differences in the estimation of OOIP for assessing the reserves in the block II of Urdaneta-01 heavy oil reservoir, using both the rock typing approach of this study and the traditional open hole log analysis with standard specifications of the area, as well as identifying the impact into the outcomes of the following parameters, net pay thickness, porosity and water saturation through a full 3D Geomodel processing and calculations.
The complete petrophysical model for the rock type approach follows all mayor steps in computing rock type percentages, modified lorenz plot, stratigraphic modified lorenz plot, flow unit and rock properties per each well from laboratory measurements of key reservoir parameters such as porosity and permeability, while the standard open hole log analysis is set with official parameters values from the study area. For both methods a 3D-Grid model of block II is created with specific settings in order to see the spatial distribution of rock properties and oil volume reckoning.
The final result shows a contrast between the two models generated, that is, the total hydrocarbon volume is higher in the case of rock typing evaluation, there is a difference between the two models of 302 MM SBT. In addition, in terms of rock properties, the storage capacity and water saturation are the most sensitive parameters at the moment of calculations, at least 4 % difference between average porosity from log-based traditional techniques and the rock classification approach. A reliable OOIP was obtained when water saturation distribution can be controlled.
The properties of the fluids will be calculated through a nonlinear optimization (polynomial fit) that allows the generation of a pvt synthetic own of the area from laboratory data. A synthetic PVT was realized establishing a range of applicability through of correlations, correlation coefficients and graphs 1 to 1, fitting all the properties with an excellent correlation coefficient. The goal of the synthetic PVT was obtaining correlations to integrate the information of the area and represent the properties of the fluids taking the laboratory information.
Later it will be defined the impact that the properties of the synthetic PVT could generate in the prediction of production, oil original on site and decide what PVT to use in the reservoirs of the field. This PVT will be used in areas without representative PVT. It is important indicates that the structural elements limit the reservoirs.
Sand associated to oil production in Jusepin field located in east Venezuela, has generated damages in oil and gas surface facilities, resulting in unscheduled production stops caused by surface equipment breakdowns, which increases maintenance costs and impacts negatively on the company's productivity. Researches determined that well J-502 was causing these operational problems, in response it was decided to install a sand trap at the well head in order to evaluate its effectiveness. The device has a simple design without moving parts and counts with a separate solid storage area, which allows disposing the retained sand without affecting the production of the oil well. Its principle of capture is the speed reduction due to fluids expansion, based on Stokes’ Law. In addition, its inlet is connected to the well head and the outlet to flow line. The data used for the design of the equipment were: Oil API Gravity 31.5°, Oil Rate: 1969 Barrels per Day, BS&W 20.4%, Gas Rate 14.9 MMSCFD, Operating Pressure 1350 psig, the size of sand grains, which varies between 90 and 600 microns and its density (1,304 gr/cc). This information was used to calculate the dimensions of the equipment (Diameter and Length) necessary to decant the sand particles inside of it.
After installing the sand trap, the number of stoppage in the flow station dropped from 18 per year to none, preventing deferred production of more than 7,600 barrels of crude per year, with savings in maintenance costs up to 30,000 US$ per year. Likewise, after 84 days operating, it was able to retain as much as 4 cubic meters of sand (141 cubic feet). In conclusion, the success achieved demonstrated the effectiveness of this useful device and its profitability was proved through an economical evaluation. Finally, the sand trap represents an innovative and effective solution in cases where the sand cannot be retained from the bottom hole. For this reason, it would be recommended to implement this solution in wells with sand production problems, and in a greater extend, in downstream facilities such as flow stations, in order to enhance effectiveness by using a higher capability device interconnected to various wells instead of one sand trap for each well, this will reduce manufacturing and installation costs.
Kumar, Raushan (Chevron Corp) | Socorro, Daniel (Chevron Corp) | Pernalete, Marta (PDVSA) | Gonzalez, Karin (Chevron Corp) | Atalay, Nilufer (Chevron Corp) | Nava, Rafael (Chevron Corp) | Lolley, Chris (Chevron Corp) | Kumar, Mridul (Chevron Corp) | Arbelaez, Alejandro (Chevron Corp)
Boscan is a giant multi-billion-barrels heavy oil (10.5° API gravity and asphaltic) field in Venezuela. Although, a large part of the field is on primary production with a low recovery factor (<6%), water injection has been successfully implemented in portions of the field for over 15 years with improved recovery. High mobility ratio waterflood (HMRWF) behavior and associated key production mechanisms obtained from detailed field data analysis and dynamic modeling are presented. A novel and unique infill configuration is also proposed to further improve recovery in this high (or adverse) mobility ratio environment.
Water injection in such heavy oil (10.5° API) was considered not effective by the industry previously, due to adverse mobility ratio. However, water injection for pressure maintenance (WIPM) was successfully implemented using a pattern configuration, pseudo 1-3-1 inverted 7-spot (an additional row of producer between conventional pattern rows). Field data and reservoir simulation models show increased reservoir pressure up to the second row of producers from the injector. The pressure support is utilized to significantly improve recovery using the unique configuration at low water cut. WIPM has already resulted in significant reserves addition. Current production from water injection areas is ~40 MBOPD (or ~ 47% field production).
However, it is estimated that because of high oil viscosity, a significant amount of oil remains bypassed in the WIPM area. An infill opportunity was identified from an integrated reservoir management study that included detailed WIPM data analysis and dynamic (mechanistic and full field) modeling. A unique infill configuration is proposed that conceptually uses the current injectors with an additional row of producers between the existing first and second row of the producers. This configuration has the potential to economically unlock millions of barrels of bypassed oil and significantly increase recovery in this prolific heavy oil field.
This study provides insights into HMRWF behavior evaluating relative impact of displacement vs. pressure. The unique and novel infill configuration can be used to improve recovery, a step vital to monetize this large resource in the low-price environment.
Historically, the well documented diversity and complexity of formations throughout Venezuela have severely complicated the design and engineering of drilling fluid systems capable of maintaining the wellbore stability required to maximize drilling efficiency and reduce formation damage. Producing formations in Eastern Venezuela, are typically low-pressure consolidated sands with elevated bottomhole temperatures and differential pressures ranging from 3,000 and 7,000 psi.
This paper describes the technical development and subsequent application of an ultra-low-invasion drilling fluid additive, designed to deposit a thin, impermeable barrier over the pores and microfractures of weak, under-pressured and otherwise troublesome formations, to maintain wellbore stability and reduce formation damage. Three case studies will be presented to demonstrate the effectiveness of the technology to prevent differential sticking and other wellbore instability issues, minimize fluid-related non-productive time (NPT), increase overall drilling efficiency, and reduce operating costs.
Validated in 14 wells, the operating window of the Naricual Formation was expanded appreciably due to the use of the ultra-low-invasion drilling fluid technology. It was also demonstrated that stability was maintained in the open hole with 7,000 psi of differential pressure at 16,810 ft, which allowed an optimized well design that eliminated one casing section. The wellbore stability was confirmed with wireline pressure-point log measurements. Furthermore, through direct offset comparisons, the authors will detail significant improvements in wellbore stability and the subsequent prevention of losses and differential sticking in a different field, where more than 1,000 bbl of losses had been recorded across the Miocene and mid-Eocene sediments.
Moreover, core tests results will illustrate the efficiency of the thin, but tough filter cake, to prevent the invasion of drilling fluid into the formation matrix, thereby minimizing formation damage down to 4.5% (95.5% retained permeability). Thus, the original structure of the formation is preserved, effectively preventing formation collapse, differential pressure-induced crossflow across open zones, and importantly, pay zone contamination.
Rodriguez, Ricardo (PDVSA) | Villavivencio, Elvio (PDVSA) | Bellorin, Pavel (PDVSA) | Rendon, Lerrys (PDVSA) | Orozco, Jose (Schlumberger) | Quintero, Andreina (Schlumberger) | Chapellin, Alvaro (Schlumberger) | Mutina, Albina (Schlumberger) | Bammi, Sachin (Schlumberger)
The Orinoco Oil Belt (Faja) is the largest known heavy oil reserve in the planet. Geologically, its reservoirs are composed mainly of sequences of shales and unconsolidated sands. The properties of the sand units such as shale volume, water saturation, porosity, and thickness can present lateral heterogeneity at a few hundred feet scale. The high viscosity of the oil and its variation both laterally and vertically is one of the key features of the Faja. Prediction of water saturation from resistivity can be difficult due to multiple reasons, including the low salinity of the formation water and wettability changes.
For the field development, Faja reservoirs are drilled following a specific drilling pattern called a “macolla”. A macolla is composed of a vertical stratigraphic well followed by a group of two to four highly deviated wells (slant wells). These deviated wells play a fundamental role in cluster delineation, because they are key calibration points in the trajectory planning of the subsequent set of horizontal wells, which are completed with a slotted liner to maximize production.
Usually, in Faja, only vertical stratigraphic wells include comprehensive logging suites. These suites include elemental gamma ray spectroscopy, microresistivity images, sonic, dielectric, and magnetic resonance measurements at multiple depths of investigation. Moreover, due to the complexity of logging highly deviated wells in unconsolidated formations, many slant wells are not logged or logged only for correlation (gamma ray and resistivity logs). The ability to acquire more log data in the slant wells improves reservoir description and reduces the uncertainty in the planning of horizontal production wells.
The case study presented here illustrates the value of integrating data from vertical and slant wells in a macolla cluster. Comprehensive logging suites acquired in the vertical wells are complemented with through-the-bit logging suites acquired in the slant wells. Through-the-bit technology has recently been introduced in Venezuela and has proved to enable the acquisition of high quality logs through unconsolidated sand shale sequences in highly deviated boreholes. Rig time due to the logging operation and the risk of sticking of the logging string was also reduced.
This case study presents the workflow for and the results of the multiwell data integration in which different formation properties, including lithology-based facies, are propagated and incorporated into a 3D structural model. This workflow provides critical input to reservoir characterization and facilitates significantly the planning of horizontal wells.
The first thermal pilot project in the Huyaparí field (formerly Hamaca) in the Orinoco Belt in eastern Venezuela was designed to use'nonthermal' wells in an existing cold producing field to explore steam stimulation injection and production response while maintaining wellbore integrity and safe operations. The pilot project consisted of performing cyclic steam stimulations in active horizontal producers. The selected candidates were active wells producing extra heavy crude oil (8-9 API) from prolific unconsolidated sands with 30% porosity and 5 Darcy permeability. A selection process was implemented to identify wells based on favorable sand quality and dynamic reservoir conditions to address potential issues of relatively high-pressure high-temperature saturated steam injection conditions. A risk analysis was implemented to design the injection completion and workover program to maintain well integrity during high-temperature steam injection (550 F). Well injection completion consisted of concentric vacuum-insulated-tubing (VIT), thermal hydraulic-set packer, thermal wellhead conversion, and high temperature downhole sensors; all designed to protect Class B cement and 9.625-in.
According to EIA (
The complete evaluation methodology has 4 phases: 1) petrophysical evaluation, that includes multimineral evaluation, porosity estimation and calibration with mineralogical analysis; 2) TOC content evaluation, that includes TOC content estimation, using 3 methods: density logs
La Luna Formation and La Grita Member of Capacho Formation are mainly composed by carbonatic rocks, with high content of calcite (above 75%) and low content of clay minerals. In both units, the estimation of TOC content varies from 0.50 to 9%. Mechanical properties show moderate values of Poisson's ratio (0.20 to 0.32), high values of Young's modulus (0.80 to 9.60x 106 psi) and UCS (6.20 to 31.00x 106 psi). In the Cretaceous sequence, the state of stress changes according to geographic location in the basin, from normal in northwest region and central lake region, to transcurrent and reverse in southeast region. The brittleness index estimated for different methods varies from 0.54 to 0.85, which indicate that both units may be classify as brittle.
The integration of geomechanical and petrophysical analysis allowed identifying prospective intervals in both units, with thickness between 20 to 100 ft. Therefore, the study indicates that both units show very good conditions for horizontal drilling and hydraulic fracturing. Moreover, the comparison of various estimation methods of TOC content and brittleness index allowed to observe the uncertainty presented by these parameters in analysis of shale plays.