bluuebunny/crossref_metadata_2025 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

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

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

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

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

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

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

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

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

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

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

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

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.
Well Completion with Monobore Technology for Gas Production in the B6 LL 370 Reservoir in the Tia Juana Field, Lake Maracaibo, Venezuela
Authors: Mieres K. R. , Prieto V. , Banzer C. , Molina F.
Published: November 2015

The new opportunities of gas in western project (PNOGO for its acronym in spanish) is looking for new technologies to improve the efficiency of the exploration and production of gas reserves, in order to assure start-up and operational continuity of Ana Maria Campos Petrochemical Complex located in Zulia state. In view of this, it became necessary to evaluate the feasibility of building wells using monobore completion technology especially in the B6 LL 370 reservoir located in Tia Juana Field, Lake Maracaibo. Designing a monobore completion involves the construction of a wellbore whose internal diameter of the completion string is the same size from top to bottom. This type of completion has shown that this technique is feasible for the production of gas due to has yielded excellent results worldwide. The premises used for the selection of this completion were based on a review of geological, geophysical, petrophysical and reservoir characteristics, as porosity, permeability, well location in the structure of the reservoir, fluid production risk, among other features. Furthermore, production analysis and economic evaluations stablishing the new completion design. During this project, two wells have been drilled with this type of completion in this field whose diameter production casing was 5-1/2". The results indicate an average gas production of 5.6 million standard cubic feet per day (MMscfd) compared to conventional wells whose output is 1.7 MMscfd in the same reservoir. The decrease in the construction cost and operating time was 30% and 28%, respectively. The results show that using the technique of monobore completion is feasible and economically viable in the construction of wells in the B6 LL 370 reservoir.
Fast Wash Tank Design Algorithm for Early Production Facilities (EPF)
Authors: Reina E. , Vargas L. , Romo N. , Venegas H. , Delgado P.
Published: November 2015

An algorithm has been evaluated to offer a fast and simple design of a primary crude dehydration system consisting of a low capacity wash tank train, installed as Early Production Facilities (EPF) to achieve a crude oil specification not greater than 0.5% Basic Sediment and Water (BS&W) with average water cut at inlet of 30%.

The estimation method allows to perform routine calculations to determine the crude oil residence time available for water separation inside the equipment, water droplet diameter and water cut within the oil pad at different heights using a short-circuit factor (F) always greater than 1. As a result, short-circuit factor of 1.4 is verified to be a good value to ensure separation of phases in low-capacity tanks. In addition, tank dimensions are given based on API-12F specification for a nominal capacity of 500 bbl. for the 12 ft diameter and 25 ft height. Moreover, the designer must take into account different tank internal configurations to improve its efficiency.

Different dehydration configuration can be arranged using 500 bbl. low-capacity wash tanks installed in series. One (01) train consists of two (02) wash tanks, and as the required processing fluid capacity is higher, similar trains in parallel must be added to increase the dehydration system throughput.

Retention time and settling theory were used and applied to the system described above and determining that the oil quality is related to the maximum size of water drops carried-out over O/W interface and being smaller as the oil reaches the outlet connection which is close to the top of the tank. These sizing techniques allowed the BS&W and water droplet diameter being estimated as a function of the oil-column height, residence time and temperature.

Different effective heights through the wash tank oil pad are checked at various operational temperatures which allow the dispersed water droplets to settle out from the oil with different velocities and, hence, being able to evaluate several water cuts (%BS&W). EPF conformed by two trains of 4 low-capacity tanks each; working in parallel, provided a processing capacity of 12000 BFPD to meet a desired 0.5 %BS&W specification for given oil and water physical properties. Initial investment, operational costs and implementation time were favourably reduced during the early production stage until the permanent facilities were installed, thereby avoiding sophisticated technologies that could result in expensive and late industrial project deployments.
Well Production Performance in a Deviated ICD Completion: Case Study with Analogous Cased and Perforated Wells. Villano Field - Ecuador
Authors: Correa Ramon , Andrade Alejandro , Ippoliti Massimo
Published: November 2015

This paper aims to show the behavior of a 66° deviated well completed with Inflow Control Devices (ICD) after 5 years of production, making a comparison with two analogous wells that have a standard Casing and Perforated completion (C&P). At that time, this type of installation (2011) was the first case in Latin-America. The study is complemented with the performance of two ICD installed in parallel with two horizontal wells.

The analysis describes the ICDs completion for a deviated well, the reasons why the well was completed in this manner and the production results obtained for three wells (1 ICD and 2 C&P) using elapsed time comparisons. The analysis considered the historical Water Cut (WC), the Productivity Index (PI), and Fluid Performance (Oil and Water). Furthermore the use of diagnostic plots to identify the water production mechanism taking into accounts the main facility (water treatment) constraints during the production of the wells.

The deviated ICD completion allowed a Water Cut reduction of at least 10% after 5 years of production, delaying the premature water channeling with an positive reserve impact compared with analogous C&P wells. Moreover this type of completion provides a new way to complete deviated wells, with more than a 45° angle, where the quality of the initial cementation job is doubtful.
Unlocking a Mature Field Reservoir Potential through Optimized Fit-for-Purpose Hydraulic Fracturing
Authors: Ramones M. , Gutierrez L. , Moran M.
Published: November 2015

Production and recoverable reserves of mature oilfields can be increased through the application of Production enhancement and optimization techniques. In the Napo reservoir, where an important percentage of the total production comes from highly depleted sands with moderate permeability and high clay contents, the implementation of hydraulic fracturing stimulation, with the simple objective of skin by-pass is generally accepted, however the production performance and decline after these conventional treatments is not optimal, due to subsequent fracture conductivity impairment caused by clay and fines migration issues, which is the primary formation damage mechanism. For this reservoir, with a clearly identified damage mechanism combined with moderate permeability and significantly low reservoir pressure gradients (down to 0.1 psi/ft) a fit-for-purpose strategy to successfully stimulate and obtain sustained production was required.

A xthorough multidisciplinary study and well screening was carried out to identify the best candidates. This task incorporated petro-physical, stratigraphic, completion and production history analysis, as well as enhanced Hydraulic Fracturing modeling for dedicated optimum fracture geometry and treating fluid selection. The study presented on this paper shows the workflow followed of the candidate selection, treatment design, execution and the post-job evaluation and validation methodology implemented on the campaign. Also, well testing before and after stimulation treatments had enabled the validation of the strategy, followed by production monitoring.

After 14 months of production it has been proven that this production enhancement strategy has achieved sustained production, with an average production increase of 350% and average post-frac skin values of -3. The post stimulation production conditions have had a positive effect on the run life of electro submergible pumps and the reduction of workover operations. 

On Parahuacu and Guanta fields the achievement of a sustained production optimization through the application of a fit-for-purpose hydraulic fracturing strategy has unlocked the reservoir potential, quantifying an incremental production in excess of 390,000 bopd during 14 months after the hydraulic fracturing campaign. After 14 months of the campaign start-up, 990 bopd of incremental production associated to the Hydraulic Fracturing activity, Represents on average 30% the total field production, proving the effectiveness of this technique which is now part of the asset's production optimization strategy.
A Finite Horizontal-Well-Conductivity Model for Pressure Transient Analysis in Multiple Fractured Horizontal Wells
Authors: Chen Z. , Liao X. , Zhao X. , Dou X. , Huang C. , Chen Y. , Li L. , Guo X.
Published: November 2015

In this paper, a novel model was proposed for pressure transient analysis in multiple fractured horizontal wells (MFHW) with consideration of pressure loss within the wellbore. To facilitate solution of this problem, the whole system was divided into (1) reservoir subsystem, (2) fracture subsystem, and (3) wellbore subsystem. Incorporating with frictional and acceleration pressure drops, a mathematical model with finite horizontal well conductivity (HWC) was established. Employing Laplace transform, the mathematical model was solved. Transient pressure solutions of MFHW were acquired using Stehfest numerical inversion. Model validation was carried out by comparing with simplified cases in literatures. Case study and sensitivity analysis were conducted based on a real case from the Ordos Basin.

The case study strongly shows that when ignoring the wellbore hydraulics, errors could be caused during the performance forecast. Results of sensitivity analysis show that, the dimensionless wellbore pressure of MFHW increases with the increase of Reynolds number; it decreases with the increase of reservoir-wellbore constant. The effect of pressure loss on pressure performance of MFHW will be exaggerated by increasing Reynolds number, or decreasing reservoir-wellbore constant.
Assessment of Different Artificial Lift Methods To Optimize Production Within the Paraiso Oilfield in Ecuador
Authors: Fructuoso T. N. , Suarez-Bastidas S. , Cueva D.
Published: November 2015

Assessment of the original artificial lift systems installed in place to determine better means to produce the existing assets and thus looking for ways to optimize and reduce lifting costs for the operator. Reciprocating rod lift systems with ultra long stroke mechanical pumping units were recommended and implemented to help achieve the desired flow rates.

The existing artificial lift equipment was evaluated to determine if a more suitable alternative could be designed for the flow rates and depth encountered at the assets. This alternative included the use of reciprocating rod lift systems with an ultra-long stroke pumping unit, high strength sucker rods, custom tailored rod pump for the application, and automation equipment to match well inflow to displacement capacity throughout the pumping cycle.

Three wells were converted from previous installations with hydraulic lift systems to ultra-long stroke reciprocating rod lift systems. Among the observed results upon the conversions were completed were: Reduced power consumption therefore a minor lifting cost per barrel, reduced work over costs due to nature of the interventions, and reduced surveillance expense with the use of automation equipment allowing the operator to monitor the wells remotely.

The ultra-long stroke reciprocating rod lift systems increased the lifting efficiency, reduced production costs, and provided the operator with more flexibility for producing their asset.
Oglan 2 Dir Well: A Successful Exploratory Project With Heli-Portable Logistics – The Role of Integration in Reaching the Goals
Authors: Atahualpa G. , Venturino G. , Zerpa E. , Correa R. , Guleryuzlu M. T. , Telles J. , Morán S.
Published: November 2015

Drilling an exploratory well in highly sensitive environments imposes a number of challenges for an Oil Company. One of these challenges is to provide Heli-portable logistic coordination to achieve a successful drilled well in the most cost/time effective manner keeping in mind that hundreds of people, equipment, supplies and fuel have to be transported to and from the rig in the safest way1. The solution implemented is based on the proven concept of integration of services. In this case, the methodology was adapted to the condition of the remote location with heli-portable logistics, in which the key factors are Logistics, managed by the Operator and Service Companies, shared Drilling Engineering, Risk Management, identification and selection of new technologies and pre-defined communication and responsibilities flowchart among Operator, Service Companies and Rig Contractor.

The initial time planned for the exploratory Oglan 2 Dir well was P-10: 32.7 days, P-50: 37.4 days and P-90: 49 days with an initial estimated NPT < 15%. The total duration of the well was 38.1 days, with an NPT of 15% due to operational difficulties encountered while acquiring downhole data and other operational events; however, 0% NPT was related to heli-portable logistics. Pre-established communication and responsibilities flowchart together with risk management allowed the achievement of goals and targets: coring 220 feet of Hollín Formation (main well target), acquire LWD on all the section and WL open hole logs in 81/2" section and, the most relevant goal, take fluid samples from Hollin and Napo Formations using a Saturn Tool.

This methodology and concepts can be used as a guide for any heli-portable and/or remote operations with a pre- defined management and communication workflow among Operator, Service Companies and Rig Contractor reaching the main goal to meet AFE time and cost.
Re-grading Proven Reserves with PRMS
Authors: Harrison Bob , Senergy LR , Falcone Gioia
Published: November 2015

The Petroleum Resources Management System (PRMS) is a project based framework that classifies and categorizes a project's resources based on their likely commerciality and recoverability. The path from prospective resource to reserves is inferred to be ‘one way’, as re-grading proven reserves is considered a "rare event", but evidence suggests reclassification decisions are more commonplace.

According to PRMS, reserves should only be downgraded if there is "an unforeseeable event that is beyond the control of the company … that causes development activities to be delayed beyond a reasonable time frame". This rather loose definition allows companies to interpret the meaning quite differently. Some choose to leave ‘under threat’ reserves as booked, by claiming the projects are subject to force majeure that might adversely affect their commerciality. Others downgrade such reserves to contingent resources, at least until the critical contingency is removed and the volumes return to the higher class.

Two case studies involving reserves re-grading are given to highlight the applicability (or not) of PRMS to politically unstable areas and mature provinces, respectively. The first example from the Middle East tells how continued civil conflict and international sanctions has led shareholders to invest elsewhere, so that some operators have reclassified reserves. The second example tells how a North Sea operator, responding to pressure from government and partners, initiated a remedial program to get an asset back on stream, and in so doing allowed reserves to remain booked.

Decisions over whether or not to re-grade proven reserves are more prevalent than implied in the PRMS. Consideration should be given to amending the PRMS guidelines to reflect this observation.
Implementation and Performance of a Heavy Oil Pilot in Atacapi Field, Ecuador
Authors: Ramirez J. , Hoffmann M. , Izurieta C. , Podeley M. , Carrera O. , Lasluiza H.
Published: November 2015

A methodology was implemented to produce and transport heavy oil (12° API) from Basal Tena Formation in Libertador and Atacapi Fields, in a profitable way.

Before implementing the pilot project in January 2015, not a single well was producing from Basal Tena Formation in the southern part of Libertador and Atacapi Fields. Furthermore, commingled production is not allowed by the authorities unless reliable production allocation is guaranteed. The pilot project consists in mixing oil from two formations with different fluid characteristics in the wellbore. The heavier oil is combined with lighter oil, which works as a diluent; this process renders a blend suitable for production by submersible pump system and transport through pipelines. Both formations were tested and their fluids were characterized independently before starting commingled production.

Oil from Basal Tena Formation has an API gravity of 12° and a viscosity of 260 cP at reservoir conditions. The pilot shows that it is possible to produce, transport and quantify it after dilution; in this case 35° API oil diluent is produced from Napo T formation. Almost seven months after implementing the pilot, oil from both formations is still being produced, despite the fact that diluent contribution rate is not constant, as the production of the Napo T formation is declining because of water breakthrough. The key variable observed to quantify the production from each formation is the specific gravity of the produced blend.

Because of its success, this pilot is the first step towards the future development of these accumulations of oil in the Basal Tena Formation, not feasible without implementing a more expensive method, until now. This simple approach can be repeated in other areas in Oriente Basin.
Use of Banana Peel Based Filters to Reduce Heavy Metals in Wastewater
Authors: Palacios Adrian
Published: November 2015

Determine the filtration levels of banana peel to reduce heavy metals in wastewater —coming from drill pipe washing— including barium, cadmium, chromium, lead, nickel, and vanadium. The water used for this study was intentionally contaminated with high concentrations of the metals in a laboratory accredited by the Ecuadorian Accreditation Organization (OAE).

The moisture of the banana peel was determined through a compositional analysis. Then three methods were used to dehydrate them (sterilizer, sun radiation and ovens) to identify the most effective one to pulverize the peel and place them inside the filter, since the objective was to obtain a porous medium (filter) through which the contaminated water could circulate smoothly.

The peel of an average size banana weighs about 50 g. After being dehydrated at a temperature of 60° C, using a sterilizer (Autoclave), it was possible to obtain around 10 g of micropulverized shell, which can decontaminate 0.5 liters of water. By using 10 ml of micropulverized shell to filter a liter of contaminated water with heavy metals, it was possible to observe a 70% reduction in Barium, 93.62% in Cadmium, 90.99% in Lead, 93.82% in Nickel, and 65.52 % in Vanadium.

The implementation of a banana peel based filter on treatment systems for industrial wastewater can effectively reduce heavy metals and even exceed the results of conventional filter methods, such as activated carbon, which reduces the levels of these metals by approximately 65%.
Computed Tomography for Petrophysical Characterization of Highly Heterogeneous Reservoir Rock
Authors: Skinner James T. , Tovar Francisco D. , Schechter David S.
Published: November 2015

A correlation between Computed Tomography (CT) number, matrix porosity, and permeability is presented that enables the petrophysical characterization of highly heterogeneous reservoir rocks with a level of detail that is not achievable by direct laboratory measurements. A total of 143 ft. of 4 in. diameter reservoir core from the North Burbank Unit (NBU) in Oklahoma were imaged using a state of the art medical computed tomography scanner. The CT number, which is a function of the density and composition of the rock was observed to correlate with both porosity and permeability values that were measured discretely along the core using conventional laboratory techniques. A mathematical expression was fit to the data that allows the prediction of the porosity and the permeability of the core within the 350 µm isotropic resolution that the CT scanning unit is capable of.

We also show that in the case of reservoirs with high vertical heterogeneity, where permeability variations of hundreds of millidarcies occur within one foot, the selection by visual inspection of core plugs for laboratory measurement of petrophysical properties leads to a flawed characterization of the stratigraphic column as some of the plugs are taken along bedding planes, and therefore are comprised of more than one rock type. We propose the use of CT-scan imaging to identify different rock types and take core plugs that are representative of unique rock types as a better practice for rock characterization.

Our work has greatly improved the knowledge of the stratigraphic column of the NBU and has provided a better understanding of the degree of vertical heterogeneity in the area. The detailed knowledge of permeability and porosity obtained from the CT numbers of the cored well can be used for the adjustment of petrophysical models based on well logs to enable the extrapolation of the detailed petrophysical characterization of the cored well to other NBU wells that have not been cored but have log data. The implementation of the proposed technique will help optimize well completion, sand perforation, water and gas shut off treatments, and EOR schemes implementation among other activities.
Reliability Reduction of the General Electric Turbines Due to Incompatibility Issues Between the Fuel and the Biocide
Authors: Ibujés-Flores P. M. , Eguiguren-Gutierrez F.
Published: November 2015

In 2013, there were situations that altered the normal operation of the turbines, attributed mainly to the fuel used (diesel) that is produced in the "Topping" atmospheric distillation plant located in the Northern Production Facility (NPF).

There is evidence that there is a continuous presence of significant amounts of highly viscous substances throughout the diesel system that feeds the General Electric turbines located in the oil separation plants of the NPF and the oil re-pumping station of Shushufindi.

Diesel from the "Topping" plant receives a monthly biocide chemical treatment against fungi and bacteria in storage tanks. However, agents such as moisture and oxygen have interacted with minority compounds (0.024% S and 0.015% P) of the biocide, producing highly viscous substances.

High viscosity substances resulting from oxidation and polymerization reactions in the aqueous phase formed from sulfur and phosphorus compounds cause clogging of the control valves of fuel entrance to the injectors, thus, reducing the reliability and availability of the turbine.

Based on the analysis performed, it was determined that the cause of the generation of highly viscous substances was the monthly dosages of biocide in the storage tanks of diesel (300 and 476 mg/l). To solve this problem, the dosage of biocide has a conditional restriction, i.e., whenever the proliferation of fungi and bacteria reach 103 and 104 col/ml, respectively, in the tanks, the biocide is added.

As a result, the availability of the turbines in NPF (General Electric) and Shushufindi (Solar) increased from 96.51% and 97.98% to 100.00% and 99.53% respectively.