bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Approaching for Rock Types and Lithofacies Synergy for the Hollin Formation, Palo Azul Field, Ecuador
Authors: Leal J. , Gaibor J. , Garces S. , Benalcazar E. 
Published: November 2015

Abstract
This paper discusses a different approach to defining rock types and lithofacies performed for the Hollin formation located in the Palo Azul field of Ecuador. The study includes a spectrum of depositional environments, which significantly influences geometry, diagenesis, and quality of the Hollin reservoir. This work integrates lithofacies and petrophysical properties using well log data, core, and sedimentological analyses to define rock types.
Sedimentological analyses were performed to describe existing cores, thin sections, and X-ray diffraction results. Flow units were identified using flow zone indicator (FZI) and reservoir quality index (RQI) methods. These units were classified as functions of flow capacity (K/Phi) based on capillary pressure (Pc) and other special lab analyses. Capillary pressure enabled the grouping of rock flow units in accordance with the K/Phi ratio, similar RQI, and irreducible water saturation (Swirr) values. These rock types (RT) were correlated with the lithofacies identified using sedimentological analysis.
The transgressive Hollin formation sequence includes fluvial mid-grained sandstones with cross stratification, tidal mid- to fine-grained sandstones with mud drapes and organic matter, and marine glauconitic sandstones with/without calcareous cement. Integrated sedimentological and petrophysical analysis defined five rock types (RT1-RT5). RT1 and RT2 correspond to tidal quarztarenites and fluvial sandstones with few discontinuous clay laminae, high permeability, and high porosity values. RT3 includes tidal fine-grained sandstones with abundant clay and organic matter in the matrix, which decreases flow capacity. RT4 is characterized by very fine- to fine-cemented tidal sandstones in which the diagenetic events close the porosity and permeability. RT5 is a muddy sequence of tidal/fluvial environments, marine shales, and well-cemented glauconitic sandstones. These rocks present negligible permeability and low porosity. In conclusion, the reservoirs deposited in tidal bars and fluvial channels have major flow capacity and storage characteristics, whereas the rocks of the shallow marine and sand flat environments present poor reservoir quality.
This integrated petrophysical and sedimentological work presents an alternative method for identifying rock types by using flow capacity and the integration of conventional core data, sedimentological analysis, petrographic and diagenetic description, capillary pressure, well logs, and reservoir information. The results from this method were incorporated in the geocellular model for reservoir simulation.
Challenging Horizontal Well Placement in an Area with High Geological Uncertainty Using Proactive Geosteering Techniques
Authors: Riofrío K. , Sánchez H. , López M. , Velásquez I. , Mejía E. , Armas C. , Reinoso G. , López D. , Bustamante C. 
Published: November 2015

Abstract
New technologies, including drilling horizontal wells, have evolved to enhance hydrocarbon production. Drilling profitable horizontal wells requires using available information to minimize uncertainty and proactive geosteering techniques to maximize production by navigating within the sweet spot.
When available information is based on 2D seismic and well correlation, advanced geosteering techniques are used to anticipate resistivity changes along the well trajectory, which can be used before and during the drilling process to successfully place a horizontal well. The geosteering process is performed using azimuthal wave propagation resistivity and gamma ray. For landing, an adequate stratigraphic correlation has been crucial. However, for the lateral section, geosignals and azimuthal resistivity measured at different depths of investigation from the top and base of the borehole have helped determine the section with best reservoir characteristics. This paper presents the results obtained in four horizontal wells in which proactive geosteering techniques have helped to position and navigate the wells along the sweet spot.
The Lower U Sandstone (Cenomanian) at the Sacha field has become the target for horizontal wells because of the reservoir characteristics present. Offset wells located in the flanks of the structure do not show the presence of water/oil contact in well logs; however, production data proves otherwise. Likewise, the deepest resistivity readings have shown a more conductive zone in the lower portion of the reservoir, which has never been crossed with a horizontal well. After a well is closer to the latter zone, azimuthal and average deep resistivities measure less resistivity than in the upper portion, whereas gamma ray values remain constant; these results are interpreted as clean sandstone. This information helped the team make the right decisions to minimize possible water breakthrough from this zone.
The horizontal well drilling process, using advanced proactive geosteering techniques, has helped determine that the flanks of the structure present a less prospective zone and contain less hydrocarbon saturation. Finally, the experience gained by the team, using these techniques and tools could help improve performance in future horizontal wells.
First Integrated Petrophysical Characterization in Limestone in Ecuador: M1 and M2 Limestones, Puma Field
Authors: Leal Jose , Hernandez Rubys , Romero Jose , Flores Pablo 
Published: November 2015

Abstract
The first integrated characterization of limestone in Ecuador was performed in the M1 and M2 limestones in the Puma field of the Oriente basin. The characterization was performed by using available information from open hole logs and by applying the dual porosity methodology, which requires the use of porosity curves, including density, neutron, and sonic.
The method used enabled estimates to be made of secondary porosity, "variable M" system cementation exponent fracture porosity, fracture intensity index, and effective porosity of the system. The effective porosity model was calibrated with nuclear magnetic resonance (NMR) logs. The results were validated with pressure transient analysis (PTA), which confirmed the dual porosity system and fracture system properties, and identified the λ and ω parameters.
The petrophysical interpretation of the M2 limestone is characterized as a unit of good thickness with an interconnected pay zone, accurate fracture intensity for the entire section, and excellent effective porosity estimate (fracture plus matrix porosity). Because the matrix has connected effective porosity and includes the presence of fractures, this unit, according to the Nelson classification of fractured natural reservoirs (NFR), may be a Type II. The M2 limestone is thicker than the M1; its fracture intensity index and its correspondent matrix effective porosity are greater than M1 (NFR type I). PTA through λ and ω values confirmed the classification of the reservoirs.
This paper describes the first integrated petrophysical evaluation for M1 and M2 limestones in the Oriente basin of Ecuador. This evaluation involves a dual porosity characterization in which the connected porosity system helped to reduce the uncertainty in the original oil-in-place estimate. The method used could be applied in other Oriente basin fields to assess the potential of carbonate reservoirs.
Changing a Low Potential Viscous Oil Sandstone Reservoir to the Biggest Conventional Incremental Project in the Neuquen Basin
Authors: Thompson Anthony , Martino Luis , Oviedo Enrique , Sanchez Fernando , Barros Pablo , Campos Hector , Gandi Silvana , Morettini Elena 
Published: November 2015

Abstract
A group of mature oil fields in Argentina, that share the same sandstone reservoirs, were declining rapidly when applying established methodologies. New wells drilled away from the exploited areas, generally encountered a water column, while infill wells saw either low pressures or injected water. To revitalize these fields, a new approach to both field management and identification of new opportunities was required. This paper discusses the methodologies applied as part of the revitalizing approach, along with the newly identified opportunities.
The first of these field studied comprised multiple stacked reservoirs all producing oil through comingled wells; oil production and allocation to date was uncertain. An integrated modelling effort showed unexpectedly that reservoirs containing lighter oil were exhausted; however, the shallower, viscous oil-bearing reservoir (Rayoso Formation) was virtually untouched.
To improve the efficiency of the project, one dedicated multidisciplinary team was assigned to identify opportunities over the entire extent of the formation containing viscous oil (~ 860 km2). The key question was where to find the remaining oil within and across the fields.
This work enabled reservoir understanding, developed over a long period of time, during the first study, to be rapidly applied to subsequent ones. Frequent iterations between the static and dynamic models were used to test hypothetical scenarios, to speed up the modelling process and to reduced uncertainty.
Use of analogues across the sandstone reservoirs reduced the uncertainty associated with commingled production by comparison with fields where injection and production was reservoir specific. Through analogues we also determined that water was not injected in secondary sands and that this reservoir was being bypassed due to the presence of similar petrophysical properties but lower viscosity oil in underlying reservoirs.
This combined fields study resulted in significant new volumes being identified with less effort and time required in respect to studying each field separately, this reducing history matching times (from two years to a number of weeks).
As a result of this study, gravity forces and different PVT properties between reservoirs were found to adversely affect production in Rayoso, in addition to the high mobility ratio. A polymer pilot is currently being implemented, with another one currently being planned as the future outlook for these previously rapidly declining fields has now significantly improved.
Pull & Push. Usage of the Mechanical Energy of a Conventional Sucker Rod Lift in Shallow Wells
Authors: Tigrero H. , Lainez C. , Salinas M. 
Published: November 2015

Summary
PULL & PUSH is a method of alternative extraction that focus on shallow wells located at short distances according to the other wells.
This alternative of artificial lift consists of a steel cable that is attached to the rocker of the support well, it passes through a sheave located at the top of a chassis built over an assisted well, this steel cable holds the clamp that is tied to the rod. As there is a movement of the rocker of the well the mechanical energy is transmitted to the rod of the well assisted by the cable and that is how you obtain the production of both wells.
This new mechanism of production enabled to replace the system of Local Tool (LT) which the assisted well used to worked and it achieved to keep the production of the two wells with the use of one unit of mechanical pump.
It is important that the weight of the rods located in the assisted well won't be greater than the rupture strength of the steel cable and in that way that doesn't exceed the overweight of the rocker to not exercise and overload in the gearbox.
To be able to produce the two wells with only one unit it will reduce the operational costs since the system of original extraction of the assisted well LT exceeds 33% of the cost of extraction of sucker rod pump (SR), getting in that way an efficient mechanism of production.
Condensate Banking Characterization Using Pressure Transient Analysis and Numerical Simulation
Authors: Quispe Cerna C. K. , Moreno R. B. 
Published: November 2015

Abstract
Condensate banking refers to the formation of condensate around the well when the reservoir pressure drops below the dew point value during depletion. As a consequence, the gas relative permeability reduces, and the formation of two phases occurs in the reservoir. Various analysis have indicated three regions with variations in fluid saturation in the radial direction from the zone immediately around to the wellbore to the furthest area. Also, well productivity and heavy components fraction of the produced fluid are compromised.
This paper aims at evidencing the formation of the condensate bank, identify the flow conditions in the reservoir and verify the most appropriate analytical model for the evaluation of this type of reservoir. An analytical and a numerical model were built using collected experimental and field data. Pressure buildup tests were analytically evaluated in terms of single-phase pseudopressure and two-phase pseudopressure. The effects of relative permeability and fluid properties along the distance were also included in the developed models. The dynamic behavior of the reservoir was assessed through a numerical compositional model elaborated to describe and regenerate pressure transient behavior along the period between well tests.
The results allowed modeling the flow zones around the wellbore and estimating the gas permeability, as well as, the skin in the areas with single and two-phase flows. Through the numerical model, it was possible to attest the existence of the three regions and to elaborate a condensate saturation distribution profile as a function of radial distance. Resultant saturation distributions ratify the lower gas quality of heavy components and allow the prediction of the evolution of the condensate bank during the time. Further, the integrated assessment allowed us to validate the results, to forecast the reservoir production and to quantify the effect of the condensate banking in the production.
The contribution of this work relies on the proposed methodology, which integrates a numerical and analytical model based on gas-condensate flow phases, rock properties, pressure reservoir transient and production behavior. Results can also contribute to a better reservoir management and prevention of the possible productivity losses of the well.
Mariann 48 Well, an Extended Reach Well Drilled in the Ecuatorian Jungle
Authors: Sandoval Maya D. F. 
Published: November 2015

Abstract
According to our country needs and limitations to oil reserves access and since some productive areas are boundary to protected zones and moreover, Andes Petroleum Ecuador Ltd. concern about environmental impact to those natural reserves, the Company developed a plan to drill the longest displacement well in Ecuador (ERW).
Cooling Behavior of Underground Thermal Insulated Pipeline Systems Considering Stagnant Fluid
Authors: Montero F. , Romero I. , Delgado P. , Díaz C. 
Published: November 2015

Abstract
The application of thermal insulation in underground pipelines presents important operational benefits during normal flow, compared to those obtained by the operation of underground pipelines without thermal insulation. However, when an extended shutdown occurs, resulting in stagnant fluid in the pipeline, the thermal insulation applied does not present major operational benefits concerning temperature maintenance inside the pipeline. In this case, the fluid reaches lower temperature values after a determined shutdown period, in the initial sections of the pipeline, which may cause wax deposition, especially for heavy crude oils at very low velocities, and significant restart pressures to reach steady state conditions. The theoretical analysis of this behavior was developed by the application of a mathematical model using iterative calculations based on heat transfer theory, for a 10-inch nominal diameter pipeline, a 1.5-inch thermal insulation thickness (if applicable) and a 5.2-feet burial depth. These results were contrasted with those using commercial software for single-phase dynamic calculations. The most significant finding, contrary to what was expected, is concerned the cooling experienced by the static fluid in an insulated pipeline. This criterion shall be considered for designing buried pipelines which transport high viscosity fluids, especially in stagnant conditions (no fluid motion) and for restarting operations.
First Run Of A Lwd Micro-Resistivity Images Tool Contributes To Update The Local Geomechanical Model In The Tapi Field, Ecuador
Authors: Corozo O. , Camacho G. E. , Guerrero M. S. , Osorio H. A. , Medina D. , Ruiz R. E. , Dávila D. F. , Avellan F. J. 
Published: November 2015

Abstract
During the drilling campaign in the Tapi field, Ecuador, events of total losses and directional unexpected behaviors were observed. These issues represent a high risk in the operations and required a better understanding of the geological structures. The use of a new Logging While Drilling (LWD) Micro-Resistivity technology was used for the first time in Tapi field, Ecuador to study the geological and geomechanical characteristics of this field in detail.
The tool string was run as a penta-combo with a rotary steerable system with the purpose of getting a hole in gauge and consequently a better image quality. The LWD micro-resistivity images tool provided images of the borehole. The interpretation of the Micro-Resistivity Image started showing an average structural dip trend towards NE, identifying a main structural trend of the field.
Two post-drill geomechanical models based on wellbore stability were made in the Tapi I and Tapi II wells. Using the LWD micro-resistivity images technology the current geomechanical model was confirmed. Based on the geological information acquired through the image interpretation (natural fractures orientation, breakouts, faults, structural and stratigraphic dips), the geomechanical model uncertainties were minimized.
Optimizing the Reservoir Management of a Mature Oil Field: The Challenge of Shushufindi
Authors: Lopez F. , Biedma D. , Suter A. 
Published: November 2015

Abstract
In early 2012, the Ecuadorian state oil company had the vision of creating a joint venture between PETROAMAZONAS EP and CONSORCIO SHUSHUFINDI, with the objective of revitalizing and re-developing one of Ecuador’s major mature fields, Shushufindi-Aguarico. Since its conception the alliance has been very effective, increasing the oil production rate by 70% and reaching a peak production of ~ 80 Kbopd until December 2014.
This significant increase in production was mainly the result of an active drilling and workover campaign. However, with this paper we seek to discuss whether it is possible to maintain and/or increase production only through the continuation of drilling and workover activities or if there are other areas of opportunity, namely, the optimization of reservoir management, including improvements in the production/reservoir engineering practices and field operation philosophy.
In Shushufindi-Aguarico, the reservoirs in the field exhibit good petrophysical properties, strong aquifer pressure support and a favorable oil to water mobility, all of which results in good production rates followed by water breakthrough and rapidly rising water cuts. In this situation, sets the necessity of optimizing the production of total fluids, i.e. oil plus water and gas, which is a novel paradigm for this field and as such must be reviewed, discussed and practices changed where technically appropriate.
It is also noted that although this paper will focus on reservoir management, relevant aspects regarding surface facilities and installation requirements/constraints will also be included in order to provide the full context for the development of the subject and its possible implementation at the full field level.
Application of Cuttings Reinjection Technology Eliminated Environmental Liabilities in a Remote and Mature Field in Peru
Authors: Soriano Arambulo V. H. , Estrada Vera E. O , Ascencios Alban E. D. , Castañeda Mikriukova E. , Poclin H. R. , Perez Perez V. H. , Ahmed R. M 
Published: November 2015

Abstract
Cuttings re-injection (CRI) technology is a reliable waste management option for eliminating environmental liabilities and reducing surface contamination risks associated with traditional disposal techniques. The technology complies with the strictest regulations enabling oil and gas exploitation in areas where it was not before possible.
Three wells were drilled in the Chambira field (Block 8). Drilled cuttings from those wells were stored in pits for three years due to the lack of a conventional disposal method that meets Peruvian regulations. Two years later in 2013, CRI technology was selected as the waste management option for disposing the cuttings. An old abandoned well, CHAM-124XCD, was conditioned and prepared for re-injection. Cuttings were removed from the pits and transferred to the processing unit where they were mixed with water and additives to form a suitable slurry, which was injected down the hole into an interbedded formation. This first CRI application in Block 8 eliminated the environmental liability of the Chambira field. All drilled cuttings accumulated from previous drilling operations were successfully injected. Approximately 100,000 bbl. of waste (including spacers and displacement fluids) was disposed into the Chambira formation. As a result, three (full-size) cutting pits were cost-effectively cleaned.
This paper shows that the selected cyclic injection technique enabled disposal of all cuttings without disturbing the initial stress state of the formation. After the injection, minimal changes in horizontal stress and fracture propagation pressure were observed; thereby, demonstrating that the injection strategy was appropriate for the formation. The results from this operation indicate that cuttings re-injection technology can be a very effective method for eliminating drilling cuttings in remote and mature fields.
This paper presents a successful CRI application in a remote Peruvian oil field as a reliable and cost-effective solution for cuttings disposal. Properly customizing available equipment at the site enabled complete disposal of the accumulated cuttings, which were major environmental and financial liabilities for the operator. The customization methods developed during the re-injection operation in Chambira field are new and applicable for similar formations in other fields.
Shear Effects of Gear Pump on Oil-Water Flow
Authors: Zhang Mo , Wang Shoubo , Mohan Ram S. , Shoham Ovadia , Gao Haijing 
Published: November 2015

Abstract
Production equipment, such as pumps and chokes, cause shear in oil-water mixture flow, forming smaller droplets in the system, which may lead to operational and separation problems. The objective of this paper is to provide new data on droplet sizes under different shear conditions in oil-water flow and compare it with model predictions.
New experimental data on droplet size distribution are acquired for a gear pump with an in-line camera, utilizing the bead sizing tool. The acquired data capture the effects of the dispersed phase volumetric fraction and shear intensity. Two prediction models for a centrifugal pump, namely, Pereyra (2011) model and Kouba (2014) model, are modified to enable droplet size distribution predictions for a gear pump. These models use the log-normal distribution and Rosin Rammler distribution methods, which have been found to match the acquired data very well.
The results demonstrate that droplets tend to decrease in diameter when the shear intensity increases. Moreover, the higher the dispersed phase volumetric fraction is, the larger the resulting droplets will be. The modified prediction model of maximum droplet size (dmax) is valid for dispersed phase volumetric fractions up to 15%. Comparisons between the acquired data and the proposed droplet size distribution prediction, which utilizes the modified dmax model, is very good with Normalized-Root-Mean-Square Deviation (NRMSD) between 4% and 6%. The proposed analysis can be extended to study other shear causing devices.