Venezuela possesses a world-class, hydrocarbon source rock from one of the most prolific places for oil accumulation in the world. This source rock, the La Luna Formation, (Cretaceous in age) is located in eastern Venezuela's Maracaibo Basin. Local variations in depositional and diagenetic conditions have manifestly affected the preservation and dilution of organic matter to some degree, generating small-scale variability in the depositional environments, and thus creating a higher-quality source rock within the depositional sequence that can be more prospective than others. To understand the variability of the depositional conditions, variations in organic matter source, thermal maturity, depositional environments and the use of organic/inorganic geochemical parameters were crucial in this study. This combined source rock evaluation composed of geological and geochemical parameters indicated an excellent potential as an unconventional reservoir for oil and gas in the study area. Geochemical analysis (Pristane, phytane (Pr/Ph), distributions of regular steranes, hopanes, monoaromatic steroid hydrocarbons (MAS) and tentative identification of gammacerane) confirmed the excellent quality of the organo-facies with higher productivity and preservation. Thermal maturity parameters indicate that most of the studied cores are within the oil window. Liquid hydrocarbons in the study area occur in the northwest and southwest areas, and condensates and dry/wet gases occur in the northeast. The lithofacies association, the sequence-stratigraphic framework, relative hydrocarbon potential (RHP), and biomarker analysis identified the depositional environment as an epicontinental sea developed in a shallow marine, upper shelf euxinic environment represented by a series of third order sequences of Highstand and Transgressive System Tracts overlying the erosional top of the underlying Cogollo Group. These stark differences show the tremendous value that biomarkers provide in the exploration of prospective source rocks. Not only do they help to identify paleoenvironmental changes and redox conditions, but they also depict the best organo-facies and accurate maturity parameters of the rock.
Fu, Jin (CNPC Engineering Technology R&D Company Ltd.) | Wang, Xi (CNPC Engineering Technology R&D Company Ltd.) | Zhang, Shunyuan (CNPC Engineering Technology R&D Company Ltd.) | Chen, Chen (CNPC Engineering Technology R&D Company Ltd.)
Located in south of Eastern Venezuela Basin, Orinoco Oilfield is an onshore heavy oil field in South America. The heavy oil is known for its high content of acids, heavy metals and asphaltenes with a viscosity of 1000-10000mPa·s. According to the reserve report released by PDVSA by the end of 2016, JUNIN Block that is situated in east of Orinoco Oilfield has an OOIP of 178*108bbl.
Data of drilled wells and distances between offset horizontal intervals in Orinoco were both studied to improve ultimate production rates. 3-dimension borehole trajectories were designed and the most effective anti-collision measures were taken.
After optimziation 8-12 horizontal wells are distributed on one pad. As the horizontal interval extends, the stable production time is prolonged and the accumulative production per well improves. However, the recovery rate stops increasing when the horizontal interval is over 1600m in JUNIN Block. Economically a large space between offset horizontal intervals results in fewer wells and lower costs, but a smaller space contributes to a higher production efficiency per well. If the space exceeds 600m, the accumulative production rate increases much more slightly. A three-dimension well trajectory consists of a vertical interval, an angle building interval, an angle holding interval, an angle building & direction changing interval, a direction turning interval as well as an absolute horizontal interval.
Since Petrobras developed the first ever offshore deep reservoir (Lula) by scale in 2006, Brazil has been conducting a progressive campaign targeting hydrocarbons buried under deep water, which contributes to discovery of Lula, Carioca, Jupiter, Buzios, Libra and other giant presalt reservoirs in Santos Basin after Campos Basin, where there are 9 oil fields ranking among the top 20 offshore oil fields in terms of OOIP. By June 2017 over 160×104bbl oil and gas were produced per day in deep water of Santos Basin, taking up 57.1% of the total yield of Campos and Satos.
Creep deformation of ultra-thick salt beds, severe loss of limestones, poor drillability of formations and insufficiency of deep water drilling equipment all make drilling and completion challenges more complicated. Mud systems and casing programs are optimized to conquer creep of salt and formation of hydrates due to low downhole temperature. Turbines + impregnated bits are deployed to improve drilling efficiency of siliceous carbonates (Lagoa Feia A Group). Precise control of ECD and efficient LCMs solved engineering challenges caused by narrow density windows (Lagoa Feia B Group and Lagoa Feia C Group).
This paper submits the monitoring methodology applied to horizontal wells associated to the First polymerized water injection pilot project, developed in Zuata Principal Field from Hugo Chavez Orinoco Oil Belt (Venezuela). Zuata Principal is a mature field, formed by unconsolidated sands of deltaic and fluvial sedimentary environments, saturated with extra heavy crude of API gravity between 8.5 to 9.5, and viscosities between 2000 to 5000 cp at reservoir conditions. The basic units of production construction (Clusters) are mostly made of horizontal wells perforated in a radial pattern, which operate under the artificial lifting method of progressive cavity pump (PCP). The pilot project was developed in a deltaic environment. As a part of the surveillance plan of the project, it was established one methodology for the control of the producer wells, using the following sources of information: - Measurements of pressure and temperature at bottom hole (real time), using multiple pressure and temperature sensors placed in the horizontal section and temperature distributed sensors, meaning fiberoptic sensors.
Rodriguez, Inti (Petrolera RN LTD.) | Hernandez, Edgar (Petrolera RN LTD.) | Velasquez, Richard (Petrolera RN LTD.) | Fernandez, Johanna (Petrolera RN LTD.) | Yegres, Frandith (Petromonagas) | Martínez, Rosana (Petromonagas) | Contreras, Ronald (Petrolera RN LTD.) | Korabelnikov, Alexander (Petrolera RN LTD.)
The Morichal reservoir at the Cerro Negro Extra Heavy Oil Field (Petromonagas JV) is starting its mature development phase after more than 18 years of production. In order to improve the current recovery factor which is around a value of 3%, maintain the production and reduce operational costs, two different strategies were defined: First, the use of the Jobo Member (overlaying sand deposits) to dispose the wastewater produced from the Morichal reservoir and second, the use of the shallow aquifer deposits of Las Piedras Formation as a water source for future massive implementation of EOR projects (Polymer and steam flooding), evaluating the potential origin of this water based on its physical and chemical properties. Both geological units are part of the drilled stratigraphic column of The Cerro Negro field, what brings technical and economical advantages such as high density of geological information available and the reuse of abandoned wells. This paper aims to describe the study case of the Cerro Negro Oil Field where on one hand, a static and dynamic characterization of Jobo Member was carried out in order to define the potential areas to be used as a wastewater disposal of the Morichal Member production. Based on the geological characterization, dynamic evaluation and surface facilities analysis, it was selected as the best area to dispose of more than 35,000 B/D of water derived from the production of 330 horizontal wells drilled; as well as, support the strategy of producing wells with high water cuts in zones of perched water and close to water contacts, where an important volume of oil is located which until now has been bypassed. On the other hand, the aquifer characterization of Las Piedras has allowed us to define the volume and composition of water available to use as a secure and probed water source during the EOR project implementation.
Herrera, Carianna (Geophysics Department of Venezuelan Foundation for Seismological Research, FUNVISIS) | Sánchez-Rojas, Javier (Geophysics Department of Venezuelan Foundation for Seismological Research, FUNVISIS) | Aldana, Milagrosa (Earth Science Department of Simón Bolívar University, USB)
The objective of this research was to estimate the best gridding interval that avoids aliasing in maps of ground gravity measurements in the northwestern region of Venezuela, before using any interpretive method. To achieve this goal, the self-similarity of the network was studied, since significant improvements in the characterization and design of gravimetric datasets using fractal dimension have been previously reported. The fractal dimension of the distribution of gravity stations in the network was determined by means of the box-counting method. It was obtained that the fractal dimension of the northwestern Venezuela gravity station network is 1.58, for a map generated with all the stations. This dimension corresponds to a minimum size of 10 km for the interpolation grid. Maps generated using the grid size obtained from the fractal analaysis seem to depict more acurately the observed gravity of the region. Maps with a grid size lower than this value showed anomalous structures that cannot be clearly correlated with the geology of the area and could be the result of interpolation errors; while those with a greater grid size showed very smoothed contoured lines that could hide detailed information.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 213B (Anaheim Convention Center)
Presentation Type: Oral
Most of the wells in this block were drilled in relatively homogeneous sands with good thickness; however, large extraheavy-oil reserves are trapped in a more geologically and operationally complex deltaic reservoir sand. This paper describes the combined application of multilateral and geosteering technologies to one of these wells and details the results of the application. To drill in one of the most complex deposits in the Junín block, technological solutions have been provided to position the horizontal path in the best location within the reservoir through the use of geosteering azimuthal deep- resistivity (ADR) tools to ensure the entire horizontal section is located in a highly productive area, combined with technological solutions to increase the drainage area with a drainage system designed for advanced multilaterals, thereby doubling the drainage area and maximizing well production.
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Liu, Zhangcong (PetroChina Research Institute of Petroleum Exploration&Development) | Luo, Yanyan (PetroChina Research Institute of Petroleum Exploration&Development) | Fang, Lichun (PetroChina Research Institute of Petroleum Exploration&Development)
The foamy extra-heavy oil reservoirs in the eastern Orinoco Belt, Venezuela with high initial dissolved gas oil ratio and flow ability in situ, have been exploited by the Cold Heavy Oil Production (CHOP) method, with recovery of only 8%-12% OOIP. SAGD has proved to be one of commercially active post-CHOP processes. Whereas during the SAGD process the dissolved gas as non-condensable gas accumulated at the edges of the steam chamber causes a resistance to heat transfer between steam and oil, thus slowing down growth of the steam chamber and oil recovery. Therefore a novel SAGD process using alternate imbalance operating-pressure (AIOP-SAGD) is studied for the purpose of improving foamy oil SAGD performance.
The novel SAGD process involves multi SAGD well pairs, and with the growth of steam chambers, a significant pressure gradient is deliberately created between two steam injection wells. Moreover the higher and lower operation pressure of the two injection wells is periodically alternate. In this work, the potential evaluation and optimization of foamy oil AIOP-SAGD are studied, through extensive simulations utilizing a sector model, which is from a sector with representative oil and reservoir characteristics of Eastern Orinoco Belt, considering the mechanism of foamy oil and thermal recovery.
Simulation results indicate that the AIOP-SAGD process shows significant improvement in oil recovery, at least 10% higher than traditional SAGD. The mechanism includes two aspects: firstly the pressure gradient between two adjacent SAGD well pairs brings a sweep of dissolved gas from steam chambers; secondly, based on the flow ability of foamy extra-heavy oil, the pressure gradient helps to exploit oil between two SAGD pairs which is typically difficult to be recovered with conventional SAGD. The optimization of operating parameters shows that the optimal start time of AIOP-SAGD is when the oil rate of SAGD reaches the peak and the steam chamber extends to the top of the reservoir. High steam quality helps improve the performance of AIOP-SAGD. Moreover the parameters of alternate time, imbalance time, imbalance pressure difference were optimized.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.
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.