Herrero F.,PlusPetrol |
Maschio L.,PlusPetrol |
Society of Petroleum Engineers - SPE/AAPG/SEG Unconventional Resources Technology Conference | Year: 2016
Vaca Muerta is an organic shale and one of the main source rocks for conventional reservoirs in the Neuquen Basin in Argentina. According to the 2013 United States Energy Information Administration (EIA) report, Vaca Muerta could produce 16 billion barrels of liquids and 308 TCF of gas (EIA, 2013). Up to the time of writing, only about 200 wells have been drilled to test Vaca Muerta, over 90% of them vertical. Multiple wells drilled by Pluspetrol in different Neuquen basin locations were selected for this paper to explore and test Vaca Muerta productivity. A wide range of data was gathered. Some examples are: a full set of logs, wet samples, petrophysic and geomechanic tests in cores, geochemistry in cut samples and PVT fluid samples. Most of the wells were completed with two fracture stages while some others had only one stage in order to test the most prolific horizons individually. During the production testing, a careful and detailed oriented surveillance program was designed to gather high quality data. Between 14 and 20 months of daily rates and pressure information is available. Additionally, several pump in/flow back tests and extended build ups (more than 40 days) were performed on these wells. Some of these wells flow naturally while others had an artificial lift installed providing information on different production conditions. This information was combined to make a full reservoir characterization. A full rate transient analysis workflow was carried out in six wells. This includes straight line plots, type-curve analysis, analytical model history matching and probabilistic forecasting. In addition, pressure dependent permeability and average reservoir pressure increase due to fracture injection fluids effects on well performance will be discuss in this paper. Finally, a set of conclusion with the findings are presented. The aim of this paper is to summarize the analysis and findings to characterize Vaca Muerta as an unconventional reservoir. Copyright 2014, Unconventional Resources Technology Conference (URTeC).
Osorio J.G.,PlusPetrol |
47th US Rock Mechanics / Geomechanics Symposium 2013 | Year: 2013
This paper investigates the qualitative correlation between microseismicity and the geomechanics attributes affecting the hydraulic fracturing performance in Vaca Muerta formation - LJE and PSO blocks - in Neuquén, Argentina. The paper includes typical results from ID geomechanics models in the area, a short description of the microseismic setup, and qualitative correlation between microseismic occurrence and some geomechanics attributes such as stresses, brittleness, rock strength and elastic properties. Results show that: fracture growing follows complex and asymmetric patterns; the high-pressure/high-stress behavior in the lower part of Vaca Muerta, where TOC is at maximum, causes stress anisotropy and impacts formation brittleness unfavorably; low pore pressure and stresses and high stress anisotropy favor fracture complexity; low values of cohesion, tensile strength and Poisson's ratio and high values of Young's modulus correlate with microseismic occurrence. Copyright 2013 ARMA, American Rock Mechanics Association.
Weiss J.R.,University of Hawaii at Manoa |
Brooks B.A.,U.S. Geological Survey |
Arrowsmith J.R.,Arizona State University |
Journal of Geophysical Research B: Solid Earth | Year: 2015
New observations from an active orogenic wedge help link the seismotectonic behavior of individual faults to wedge deformation rates and patterns over multiple timescales. We provide the first detailed constraints on the distribution and timing of deformation at the front of the Andean orogenic wedge in southern Bolivia, where a recent study suggests that great (Mw > 8) earthquakes could rupture the master fault underlying the wedge. We use stratigraphic relationships across fault-related folds and elastic dislocation modeling of seismic reflection horizons to obtain probabilistic estimates of wedge-front fault ages and slip rates. Our analyses reveal that at least half of the previously determined GPS-based wedge-loading and Quaternary whole-wedge shortening rates are absorbed across a 20-40 km wide wedge-front zone consisting of 1-4 en echelon and partially to fully overlapping faults and folds associated with blind thrust faults. The difference between our slip rates and the geodetic/geologic observations combined with evidence for activity across internal wedge structures supports the notion that nonsteady state mass balance conditions coupled with elevated erosional efficiency result in distributed wedge deformation. The orogenic wedge in southern Bolivia behaves in a similar fashion to the Taiwanese and Himalayan ranges; slip accumulates at downdip locations along the master fault and is released incrementally by earthquakes that rupture the wedge-front fault zone. The faults and folds comprising this zone pose a major source of seismic hazard. Accumulating slip is also released in the wedge interior and older, internal wedge faults must be considered in any future assessment of regional earthquake risk. ©2015. American Geophysical Union. All Rights Reserved.
Alberdi-Genolet M.,Geosignals |
Cavallaro A.,YPF SA Direccion de Tecnologia Argentina |
Hernandez N.,YPF S.A. |
Hernandez N.,PlusPetrol |
And 2 more authors.
Marine and Petroleum Geology | Year: 2013
Heavy-medium oils (14.5-27.9°API) in a studied field of Malargüe area in the Neuquén Basin, Argentina have associated gas that produces between 0 and 4000 ppm H2S and 0.6-103 kg H2S/day. Being able to discriminate between biological and inorganic H2S sources is essential to the oil field's economy. H2S associated with anaerobic bacteria sulfate reduction (BSR) might be mitigated using biocompetitive technologies or bactericides, whereas abiotic H2S from geological sources can be controlled only by sequestration in surface facilities and oil field management if the H2S distribution in different oil pay-zones, field compartments and origin are well known.The isotopic signatures of the H2S (δ34S) range between +2.3 and +7.8‰, which suggests magmatic sources. Laccoliths in the Malargüe area, associated with Tertiary magmatic events were mapped out many decades ago. Petrographic descriptions of igneous samples are consistent with andesitic magmas that bore sulfur-bearing fluids, which are considered the principal source of H2S. Associated hydrothermal fluids, as recorded by secondary minerals, induced rapid TSR (thermochemical sulfate reduction) reactions as documented by mineral phases seen in SEM. Most of the H2S Neuquén Basin has been linked to BSR (bacterial sulfate reduction), however we document a geological origin for the H2S, which is tied to magmatic events.Organic geochemistry and fluid inclusion data allow for an early local generation of hydrocarbons linked to burial followed by a second pulse of light hydrocarbons, gas and H2S associated with the magmatic event. Water geochemistry and the lithology of oil pay-zones are used to predict the distribution of H2S in each well. Wells with less than 20 ppm of H2S are linked to meteoric waters and siliciclastic pay-zones. © 2012 Elsevier Ltd.
Arambulo V.H.S.,PlusPetrol |
Colque J.N.P.,PlusPetrol |
Alban E.D.A.,PlusPetrol |
Ahmed R.M.,University of Oklahoma
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2015
One of the most important functions of drilling fluids is to maintain adequate wellbore stability until casing is run and cemented properly. Lack of wellbore stability generates an enlarged non-homogeneous elliptical weaker borehole. This non-cylindrical shape of the wellbore leads to complex drilling problems such as poor hole cleaning, high solids production, stuck pipe, unsuccessful wireline runs, poor cement bond representing large cost to operators. Micro-fractured shale formation represents a challenge due to its natural lack of stability when exposed to conventional water-based mud (WBM). As a solution, oil-based mud (OBM) becomes a technical option to overcome the issues observed with conventional WBM. It tremendously reduces the chemical interaction with micro-fractured shales. However, environmental constraints of the OBM makes this option non-applicable for environmentally sensitive areas. According to recent publications, with similar complicated environments, Aluminum-Based High-Performance Water-Based mud (HPWBM) has shown good performance with features closely comparable to that of OBM. The Peruvian Amazon has the largest Peruvian oil and gas reserves. However, it is located in an environmentally sensitive area marked by a large biodiversity and native communities. Environmental concerns related to drilling activity are very restrictive. Furthermore, most operations are performed as "offshore on land" (i.e., helicopter-transportable operation) where drilling fluid management cost strongly affects the final Well's Authorization for Expenditure (AFE). Aluminum-based HPWBM has been successfully introduced recently in the Peruvian Amazon for drilling vertical and deviated wells resulting in considerable improvement in drilling performance and goal achievements. Issues related to shale instability were previously reported and financial losses forced operators to use Aluminum-Based HPWBM to reduce non-productive time and associated costs. Two groups of case studies from four wells drilled in Blocks 8, 56 and 88 blocks of the Peruvian jungle are presented in this paper. A Wellbore Quality Index (WQI) tool and Key Performance Indicators (KPI) are introduced to make comparison between aluminum-based HPWBM and previously used (i.e. conventional) fluid systems and to validate the effectiveness of the aluminum-based HPWBM system in stabilizing micro-fractured shale formations. A proper fluid design was selected during the planning phase of each project and fluid properties were monitored at the rig site to evaluate performance. In addition, wireline logging, casing runs, trips, wellbore quality and drilling performance were closely monitored to examine the impact of using aluminum-based HPWBM. Results show tremendous performance improvement introducing a new benchmark in drilling operation in the Peruvian Amazon. © Copyright 2015, Society of Petroleum Engineers.
Gandhi A.,University of Texas at Austin |
Gandhi A.,Anadarko Petroleum Co. |
Torres-Verdin C.,University of Texas at Austin |
Voss B.,University of Texas at Austin |
And 2 more authors.
AAPG Bulletin | Year: 2013
The concept of common stratigraphic framework was previously introduced to construct and cross-validate multilayer static and dynamic petrophysical models by invoking the interactive numerical simulation of well logs both before and after invasion. This article documents the successful implementation of the common stratigraphic framework concept to examine and quantify the effects of mud-filtrate invasion on apparent resistivity, nuclear, and magnetic resonance logs acquired in the San Martin, Cashiriari, and Pagoreni gas fields in Camisea, Peru. Conventional petrophysical interpretation methods yield abnormally high estimates of water saturation in some of the reservoir units that produce gas with null water influx. Such an anomalous behavior is caused by relatively low values of deep apparent electrical resistivity and has otherwise been attributed to the presence of clay-coating grains and/or electrically conductive grain minerals coupled with fresh connate water. Concomitantly, electrical resistivity logs exhibit substantial invasion effects as evidenced by the variable separation of apparent resistivity curves [both logging-while-drilling and wireline) with multiple radial lengths of investigation. In extreme cases, apparent resistivity logs stack because of very deep invasion. We diagnose and quantify invasion effects on resistivity and nuclear logs with interactive numerical modeling before and after invasion. The assimilation of such effects in the interpretation consistently decreases previous estimates of water saturation to those of irreducible water saturation inferred from core data. We show that capillary pressure effects are responsible for the difference in separation of apparent resistivity curves in some of the reservoir units. This unique field study confirms that well logs should be corrected for mudfiltrate invasion effects before implementing arbitrary shaly sand models and parameters thereof in the calculation of connate-water saturation. © 2013. The American Association of Petroleum Geologists. All rights reserved.
Levina M.,University of Texas at Austin |
Horton B.K.,University of Texas at Austin |
Fuentes F.,PlusPetrol |
Stockli D.F.,University of Texas at Austin
Tectonics | Year: 2014
Andean retroarc compression associated with subduction and shallowing of the oceanic Nazca plate resulted in thin-skinned thrusting that partitioned and uplifted Cenozoic foreland basin fill in the Precordillera of west-central Argentina. Evolution of the central segment of the Precordillera fold-thrust belt is informed by new analyses of clastic nonmarine deposits now preserved in three intermontane regions between major east directed thrust faults. We focus on uppermost Oligocene-Miocene basin fill in the axial to frontal Precordillera at 31-32° S along the Río San Juan (Albarracín and Pachaco sections) and the flank of one of the leading thrust structures (Talacasto section). The three successions record hinterland construction of the Frontal Cordillera, regional arc volcanism, and initial exhumation of Precordillera thrust sheets. Provenance changes recorded by detrital zircon U-Pb age populations suggest that initial shortening in the Frontal Cordillera coincided with an early Miocene shift from eolian to fluvial accumulation in the adjacent foreland basin. Upward coarsening of fluvial deposits and increased proportions of Paleozoic clasts reflect cratonward (eastward) advance of deformation into the Precordillera and resultant structural fragmentation of the foreland basin into isolated intermontane segments. Apatite (U-Th)/He thermochronometry of basin fill constrains to 12-9Ma the most probable age of uplift-induced exhumation and cooling of Precordillera thrust sheets. This apparent pulse of exhumation is evident in each succession, suggestive of rapid, large-scale exhumation by synchronous thrusting above a single décollement linking major structures of the Precordillera. © 2014. American Geophysical Union.
Montiveros M.,PlusPetrol |
Echavarria L.,PlusPetrol |
Society of Petroleum Engineers - Progressing Cavity Pumps Conference 2013 | Year: 2013
Experience tells us that progressing cavity pumping is the logic choice for producing heavy sandy fluids. Nevertheless, under these conditions PCPs suffer from blocked suction, sanded pump and low runlife. In order to overcome these issues two technologies were tested simultaneously: charge pumps and medium nitrile elastomer. The fields involved in this study are El Corcobo Norte, Cerro Huanul Sur, El Renegado, Jagüel Casa de Piedra and Puesto Pinto which produce from the Centenario Formation and are located in the Neuquen Basin. These are non-consolidated sandstone formations with an oil gravity of 18°API that are produced following CHOPS philosophy (Cold Heavy Oil Production with Sand), where sand production is deliberately maintained through time. In 2010 the first charge pump PCP was installed, followed by six more wells in the course of two years. This system proved to be an alternative for high sand cut wells (4-5% continuous and up to 25% slugs) and also reduced by half flush-by interventions due to sanded pump. Also in 2010 started the trials with a softer elastomer (medium nitrile). The sanded pump failure rate was lowered (comparing pumps with the same volumetric capacity and in the same well), reducing downtime and hence increasing production. These pumps also showed higher operating efficiency and longer run life than high nitrile pumps. These results encouraged us to integrate both technologies, resulting in the installation of charge pump PCPs with medium nitrile elastomer during the last quarter of 2012. In 2013 we will field test pumps with enhanced geometry. This is all part of a combined effort for finding reliable and cost effective solutions for challenging applications. Copyright 2013, Society of Petroleum Engineers.
Maschio L.,PlusPetrol |
Society of Petroleum Engineers - 5th SPE International Conference on Oilfield Corrosion 2010 | Year: 2010
The San Martin field is east from Lima, in the heart of the Peruvian tropical forest (see Fig 1). It is home to one of the most important non-associated natural gas reserves in Latin America, a vital resource for the energy needs of the country. Tubing integrity in San Martin area has been a concern and a subject of continuous control due to the wells high gas rate, difficult logistic and economic importance. Multi-finger caliper logs were run in all the wells in San Martin field to control and assess tubing condition and integrity. Although the wells produced with low carbon dioxide (CO2) and water content, and no solids, preliminary reviews of the logs showed that only the wells with the highest production rate have wear signs of material loss. This paper recap an extensive investigation performed in all the wells in the San Martin area. In this document logs reports, calculation as well as the ASCII files revision and quality controls are shown. Subsequently, a synopsis of the wear mechanism, its trends, the variables that control it and the extent of the problem using a novel internal processing of the raw caliper data are discussed. Finally, a set of recommendations to reduce the wear effect is presented. Understanding the wear mechanism and documenting the lesson learnt are paramount not only to improve the operations in the San Martin field, but also to use this knowledge to improve the decision-making and management of the upcoming field completions in the same area. Copyright 2010, Society of Petroleum Engineers.
Aguero S.D.,PlusPetrol |
Ortiz Best R.,PlusPetrol |
Perea Garcia M.,PlusPetrol |
Society of Petroleum Engineers - SPE Canada Heavy Oil Technical Conference 2015, CHOC 2015 | Year: 2015
The current article describes waterflooding surveillance techniques applied in El Corcobo Norte and nearby fields, operated by Pluspetrol S.A., in the northeast margin of Neuquén Basin. The main productive target is the Centenario formation, a relatively shallow unconsolidated sandstone reservoir. The API gravity is 19° and the oil viscosity under reservoir conditions is between 150 and 250 cP. Producer and injector well completion is performed applying the so called CHOPS technique (Cold Heavy Oil Production with Sand), which consists of promoting sand production during completion by producing at high rates. Sand production causes the generation of caverns and "wormholes" that increase productivity/injectivity indexes that are necessary to achieve economical productions. Due to the low original reservoir pressure (30 kg/cm2) and fast decline of primary production, it was necessary to support reservoir pressure from the very beginning of the field's operation. The heterogeneity caused by the CHOPS technique and the high oil viscosity represent a challenge for waterflooding performance. However, important waterflooding response was observed in producer wells. Strong water wettability of the reservoir rock and reservoir continuity favor displacement and volumetric efficiencies. Waterflooding surveillance relies on strong data acquisition of injection and production, which allows, among others, daily injection/production parameter revision, weekly revision for producer well extraction, monthly revision for rates and VRR (voidage replacement ratio), and processing factors (produced or injected pore volumes a year). With the objective of promoting a homogeneous sweep and lower water cuts in producer wells a strategy was designed to determine specific injection and production rates. The constant application of this surveillance strategy and constant modification of injection and production regime have allowed to obtain recovery factor as high as 20% in the more mature zones in only 6 years of production and to sustain a production plateau during this time. On the other hand, this continuous modification generates uncertainties for forecasting the behavior of the field production and therefore the ultimate recovery factor. Additionally, actions taken to increase oil production in the field have led to severe producer-injector channeling issues, which affect negatively in oil recovery and need to be prevented in order to optimize ultimate recovery. Regarding this topic, empirical limits were defined to avoid channeling between producer and injector, and also remediation techniques were developed to recover channeled wells. Copyright 2015, Society of Petroleum Engineers.