bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Deepwater Gas Field Development Strategy for T&T
Authors: Nickie Ayasha 
Published: November 2015

Abstract
The phrase "a cleaner and environmentally attractive fuel," describes why the gaseous hydrocarbon, natural gas, is a favored fuel choice compared with other hydrocarbon fuels and coal. Its emergence as a preferred fuel has grown throughout the years and as such worldwide consumption and production have escalated.
Trinidad and Tobago is the top natural gas producer in the Caribbean with an average 2014 daily production of 4,069 MMscfd. With a vibrant upstream, midstream and downstream sector, Trinidad and Tobago makes maximum use of the natural gas value chain. Further maximization through growth in Trinidad and Tobago's downstream sector requires an adequate supply of natural gas in addition to the shallow water gas fields offshore Trinidad and Tobago which are currently the main supply source. Deep water gas fields have the potential to increase supply but unlike oil, the ease and economics of development are challenging. As a thriving gas sector, a myriad of infrastructure already exists which may aid with any further development.
An understanding of the magnitude of investment, its return to both operator and government and the well head price to economically produce natural gas from deep water fields is critical especially for potential domestic and Caribbean markets. For Trinidad and Tobago, an economic option to develop potential gas resources in deep water fields would bolster further downstream investment and by extension the economy. Regionally, potential markets can also be served via this supply. This paper therefore focuses on a deep water gas development strategy which utilizes Trinidad and Tobago's existing infrastructure. It presents a technical and economic evaluation of a deep water gas field based on three (3) recoverable resource sizes, one price structure and a production range of 500 mmscfd to 750 mmscfd. The development strategy along with associated capital and operational expenditure, Net Present Value (NPV) discounted at 6%, 8% and 10% nominal to January 2015, Government and Operator share percentages and internal rate of return (IRR) are highlighted.
The paper concludes that initial investment for a resource size of 3tcf to 5tcf would be between five (5)-eight (8) billion USD. Economic returns to both Operator and Government for these deep water, dry gas developments requires a well head price of greater than USD 3.50 per mscf. Government share % ranges from 19 % to 35% and for the operator, an NPV of USD 1.2 Bn to USD 2.3 Bn can be achieved.
Optimizing Well Evaluation: Real Time Monitoring Using Fiber Optic Conveyed in Coiled Tubing and N2 Lifting
Authors: Villanueva G. , Burgos J. , Humbert O. , Betancourt A. , Lopez M. , Sandoval L. M. , Arevalo J. C. , Hurtado J. , Meza D. , Torres C. , Gozalbo E. , Vela I. , Egas A. , Leon R. , Loyola R. 
Published: November 2015

Abstract
Well evaluation is the primary method used in the oilfield to determine the true well's production potential and reservoir characteristics. During a well evaluation, downhole parameters are commonly registered using downhole memory gauges, which can only be retrieved and read after the evaluation have finished. The problem with this conventional method is the uncertainty or ambiguity results and the inaccurate data of the downhole parameters; which often lead to inefficient tests times and difficulties for well test interpretation.The use of Fiber Optic for Real-time downhole measurements conveyed on Coiled Tubing (CT) and Nitrogen (N2) Lifting provide a unique live insight that allow us to monitor the well response while production or evaluation is performed, eliminating the uncertainties that surrounds traditional methods.
Nitrogen lifting with Coiled Tubing was introduced as an alternative evaluation method for the common Hydraulic Jet Pumping that proved advantages accelerating well response and increasing the accurate of the reservoir data for well evaluation and artificial lift design nevertheless this still faces the delayed on the pressure data and transient interpretation. Implementing the Real Time downhole measures (P, T) is possible to eliminate uncertainties of reservoir parameters that surround well evaluations, adjust job parameters on-site, optimize job resources and time and finally anticipate artificial lifting design.
This paper will present the results of the implementation of this new method in the area for well evaluation allowing real-time measurements of down hole pressure/temperature. Combining the fluid lifting with N2 through the CT, reservoir response is continuously monitored; thereby, allowing in advance an adequate design of the lifting system reducing nonproductive time. Real-time measurements and accurately data of the reservoir allow defining if a further stimulation treatment is needed. Actual treatment program can be continuously monitored or modified, to achieve optimal results.
The first trial using the system demonstrated that the application can be used with a high degree of accuracy and control for the parameters and treatment designs that are not achievable using conventional techniques as the Hydraulic Jet pumping, gauges conveyed in slick line, joined tubing and/or using surface data to predict downhole behavior.
Learning by Impact Driving Training: A Case Study from Ecuador
Authors: Pazmiño Aldaz K. , Kohatsu J. 
Published: November 2015

Abstract
Road traffic incidents are ranked by the World Health Organization (WHO) among the top 10 causes of fatalities worldwide. According to reports from the International Association of Oil & Gas Producers (IOGP), driving-related incidents continue to be the single largest cause of fatalities in the oil and gas industry.
With an increase in driving-related activities in its operations in Ecuador, an oilfield services company reinforced its approach for driving training in that country by developing a "Learning by Impact" component. Based on the principle that people learn by repetition and impact, the approach represents a change of focus compared to the previous training, which was mostly theoretical. The objective of the "Learning by Impact" initiative was to encourage safe driving behavior combined with good driving skills training in order to further improve driving safety performance.
The training program implements real-life situations such as rollover, frontal crash, seatbelt and motorcycle convincer simulator devices, reaction stick (using a cell phone), vehicle pre-inspection and role-plays. The training is consistent with IOGP 365 guidelines for driver safety improvement. Equipment was custom designed and built to provide simulators of vehicle accident situations. These simulators are portable, enabling the training program to be easily moved to multiple locations in the country wherever driver training is required.
This paper describes how the program was developed and implemented, and how the approach, with its focus on practical experience of simulated real-life situations, is considered to have been successful in increasing drivers' awareness of their behavior and its potential impact of driving incidents.
Successful Implementation of Hydraulic Fracturing Techniques in High Permeability Heavy Oil Wells in the Llanos Basin-Colombia
Authors: Italo Bahamon J. , García C. , Manuel Ulloa J. , Leal J. , Garay R. , Medina C. , Nieto J. 
Published: November 2015

Abstract
Hydraulic fracturing is the most common stimulation technique to make hydrocarbon production feasible and optimal worldwide. However, it has been preferentially focused on low permeability formations, and when applied to high permeability, it has been focused on sand control.
This article outlines the process and results of the hydraulic fracturing campaign for productivity purposes (not for sand control) in the basin of the eastern plains of Colombia given the petrophysical characteristics of the cretaceous formations, where thinking "out of the box" and separating from the existing premises, resulted in successful implementation of this technique in high permeability wells (~ 1D), high water cuts (up to 80% BSW) and heavy oil reservoirs (9–12 API).
The technical process consisted on several steps leading to the success of the campaign, which included: Formation damage study that identified candidate wells and damage mechanisms affecting them.Refining of the petrophysical model from pressure testing to establish incremental production.Adjustment of fracture models using varying anisotropy from special sonic log runs.Using state of the art technologies such as mobility enhancers and Flow back proppant additives as active ingredients of the fracturing fluid.
This article presents the outcomes of more than 40 wells intervened to date with an average volumetric increment of ~ 250 BOPD per well, consistent reductions of BSW up to 60% and optimized operations which let the operator consider the hydraulic fracturing as a production optimization option for the field under analysis.
Integrated Geological, Petrophysical, and Reservoir Properties of the Upper and Middle T Sandstones, Tarapoa Block, Oriente Basin, Ecuador
Authors: Espinosa J. W. , Good D. R. , Verdin C. Torres , Steel R. , Olariu C. 
Published: November 2015

Abstract
The Upper T Sandstone of the Tarapoa Block in the Oriente Basin of Ecuador demonstrates low resistivity despite often containing light gravity oil, the presence of which has been confirmed through tests and production. This situation merits an in-depth analysis to better understand the reasons for, and the impact of, the low resistivity as a key factor in conventional petrophysical analysis; and in so doing, improve the precision of determining the hydrocarbon content and productive potential of the Upper T reservoir in the Tarapoa area.
At first, it was considered that the principle cause of the low resistivity effect in the Upper T interval was the presence of glauconite which is deposited in a shallow marine environment, however, upon more thorough investigation, it was determined that, despite the real impact of glauconite, there are a number of other variables which contribute to this anomaly, such as thin bed sand/shale alternations, grain size variation in the sandstones, and the vertical resolution of the conventional wireline tools typically used.
A thorough analysis and understanding of the Upper T reservoir rock is justified in order to determine its real hydrocarbon potential, and to help in the calibration of the reservoir potential when proposing well locations. In addition, a better understanding of the variables impacting the reservoir quality and flow characteristics is of great importance when proposing test intervals and in the design of testing and production parameters.
A Successful Peripheral Water Injection in a Weak-Edge Aquifer Oilfield, Oriente Basin, Ecuador
Authors: Feng Yuliang , Ji Bingyu , Sun Hongjun , Wan Xuepeng , Solis Ivan , Tan Xuequn , Li Linlin , Zhang Shiyang 
Published: November 2015

Abstract
HN oilfield1, Oriente Basin, Ecuador, is located in the rain forest, well deployment is restricted by ground environment, and surface facility installation is under very strict regulations2. In this paper, a successful peripheral waterflooding3 application in the HN oilfield, was illustrated. Geological study, waterflooding design, project deployment and waterflooding optimization were thoroughly discussed in detail.
M1 of Mesozoic Cretaceous Napo Formation is a litho-structural composite reservoir, mid-high permeability, with thin sand layers4. The production was initialized in 1995 with natural depletion drive, and a 6.4% recovery of OOIP was achieved. In order to enlarge the waterflooding sweep volume, three injection wells were designed. Well location is optimized on the basis of fine interpretation of low relief structure and prediction of sand with average thickness of 15 ft by MPS method5. A proper injection-production ratio(IPR) was determined by using reservoir simulation to restore the reservoir energy but avoiding to reach high water-cut values on producer wells. Volume and properties of the aquifer was estimated by static-dynamic analysis. A "balanced injection" method was applied and real-time waterflooding adjustment was carried out to enhance waterflooding performances.
As liquid production and pressure declined sharply after 8 years' primary drive, in 2003, one injection well was drilled to performance peripheral water injection. The volume and properties of the aquifer were re-estimated according to the production history data and geological analysis. Oil production started to increase and reservoir pressure was restored. The BOPD in 2003 was 950bbl/d, and peaked at 2,300bbl/d in 2007. Later, another two injection wells were drilled to enlarge the sweep volume. But one of them was changed to inject in another zone. Injection volume, pressure, and injection mode were studied and optimized, the oil production peaked at 5,400bbl/d in 2010 as the results of injection optimization. The efforts of real-time waterflooding adjustment extended the high oil production period. By July 2015, RF reached 32.7% with 83.4% water-cut and an ultimate recovery was forecasted to be 45%. Due to effective reservoir management, maximized economic benefit was achieved on the basic economic evaluation. Suggestions on future adjustments were given for waterflooding operations in this field and similar oilfields.
The successful application of waterflooding demonstrated the potential of peripheral water injection in complex reservoirs and the importance of water flooding design. Due to integrated geological study, reservoir performance analysis, and reservoir management, waterflooding operations achieved its best performance with maximum economic benefits.
Interpretation of Micro Resistivity Image Logs and Core Tomographic Images in a Natural Fracture Reservoir Evaluation, Upper Magdalena Valley, Colombia
Authors: Mantilla M. , Davila D. 
Published: November 2015

Abstract
In the Upper Magdalena Valley, 70 kilometers south of Neiva La Hocha Field is located, on the low side of the San Jacinto Fault, structurally defined by a "Z" type anticline with dips between 45 and 90 degrees. Its geological information is obtained from wells and is standard requirement to run image logs to characterize the structure dip and fracture behavior. Uncertainty related to fractures trends and structural dip, are principal reasons of this analysis.
Micro resistivity image interpretation, core data, core tomography images, field closeness to a regional fault (between 0 and 600 meters) and reservoir production information have allowed identifying it as naturally fractured. Recently, a core was acquired, analyzed with high resolution tomography and integrated with micro resistivity image logs, to characterize and integrate the rock with well logs, then to extrapolate the results to other wells in the field.
The integration allowed confirming planes originally associated with structural dips, identifying fractures on the core that the image log resolution did not permit, interpreting fractures using core tomography radial images, similarly as in image logs. Several features were interpreted and based on fracture dip and strike direction three fracture families were defined, with a predominant strike direction of NW-SE.
This combined analysis helped to establish a fracture trend pattern or criteria that represents great information for future fracture and structural models in La Hocha field. Additionally, this pattern will be extrapolated to other wells with micro resistive image log in the field, adjusting and improving those results, obtaining a better model.
A Simple Yet Effective Approach to Estimate Time and Costs for the Drilling Project in the Tapir Field
Authors: Rodriguez Rafael U. 
Published: November 2015

Abstract
Budged estimation for a given drilling project is part of the dutties assigned to drilling engineers. The simplest way to make those estimations is using average costs based on previous wells, which works well to a certain degree.
Average time and costs sometimes include troubles experienced in wells that could increase the estimation.
This paper presents a simple procedure to make more realistic estimations based on the actual well design of the wells to be drilled and the information compiled from wells already drilled. The Tapir field in Andespetroleum was used to prove the effectiveness of this approach.
Time estimation for drilling operations is made from the information collected in a database, which considered the previous wells drilled in the Tapir field. Wells were classified by their directional profiles, their displacement, their direction and maximum inclination.
The collected information also included a record of average ROPs for each section of the wells, time spent for each trip, and also the time spent in other operations such as open hole logging, casing running, cementing, wellhead / BOP installation, etc.
Once the conceptual design of the new well is ready, wells with similar profile are searched into the database trying to find one well with the closest possible profile respect to the well being planned. This well is called the pattern well. Then, a simple spreadsheet is used to quickly estimate the time for drilling operations using the pattern well as reference.
Oportunities for time optimization are derived from the lessons learnt from each well.
On the other hand, the cost estimation uses a very simple spreadsheet that collects all the associated services involved in drilling a well. It is important to point out the advantage of having services that are paid using a lump sum (drilling fluids, directional services, cementing, etc) which provides a very simple way to estimate costs with a good degree of accuracy. The lump sum contract model for almost each service was adopted after several years of experience in the area that resulted in a good knowledge of the risks and operations associated.
An example of how to use this simple approach is showed and a comparison for planned versus real time and costs are also presented.
Geomechanics Coupled to Fluid Flow in Heavy Oil Reservoirs: Comparison and Innovation in the Modelling
Authors: Alvarez L. L. , Alzate-Espinosa G. A. , Naranjo A. 
Published: November 2015

Abstract
Nowadays, a large percentage of oil daily production in some Latin American countries comes from heavy oil reservoirs. The oilfield development and reservoir exploitation strategy for this kind of reservoirs must take into account the impact of geomechanical issues on modelling any reservoir production scenario, either for a single well or sector model simulator. The modelling or simulation tools used to represent the performance and behavior of heavy oil reservoirs present some limitations such as they are not fully coupled and they only use a nonlinear elastic constitutive model to represent the mechanical behavior of the reservoir. Both examples show major limitations to figure out a closer analysis to the true behavior of heavy oil reservoirs. The geological formations related with mentioned reservoirs usually present a mechanical behavior similar to materials with very low capacity to support changes in the stress-state and to present permanent and unrecoverable deformations after loading and unloading processes. Therefore, to analyze the behavior of heavy oil reservoir is mandatory to use modelling tools that incorporate a coupled analysis between fluid-flow process and strain-stress using an elasto-plastic constitutive model.
The elasto-plastic constitutive model defines the plastic and elastic phenomenon caused by loading and unloading that occurs in the heavy oil-reservoir. Several research centers have been focused to design experimental tests to learn more thoroughly the results provided by this model, and the results have been satisfactory. However, laboratory tests are not easy to access in most of cases, so it is necessary to have a numerical simulation model that allows knowing the mechanical behavior of the reservoir associated for any production scenario or strategy.
This paper presents the results from a coupled model, which integrates both the geomechanics and fluid-flow equations for a single-well case using different constitutive models. This model could provide an overall result of the mechanical behavior of unconsolidated sand under production of high viscosity oil. The results comparison for the three considered cases, just fluid flow, an elastic lineal behavior of the rock and finally an elasto-plastic behavior, provides a great difference between the stress-state among cases with a dramatic change in the formation permeability, and therefore in the reservoir pressure.
This numerical model is a useful approximation to improve the characterization of heavy oil reservoirs. As a result, heavy oil reservoirs will have a more successful production intervention or recovery process.
Thermal Induced Fracture Effect with a Lower Cool down Reduction - Case Studies for Ecuador; Villano and CPF Water Disposal Wells
Authors: Andrade A. , Correa R. , Vaca S. , Chango M. 
Published: November 2015

Abstract
The objective of this paper is to display the Thermal induced fracture effect (TIF) observed in Villano water disposal wells by decreasing the injection water temperature by 20°F (Aug 2012) and 10°F (Dec 2013) through to the installation of air-coolers at surface. Furthermore the application of fracture surveillance workflow and the design, execution and results of a controlled temperature and pressure test in CPF disposal well (Apr 2013) are also presented.
The methodology aims to share the results obtained in two different cases ocurred at different times in Villano Field within the Hollin Sandstone formation, allowing improvement of the injectivity in the disposal wells. This work includes comparison of the results and identification of key factors in order to maintain maximum injectivity (100% Producer –Re-Injection water system). Additionally, the implementation of a monitoring program was necessary for a daily surveillance of the injection temperature and well behavior. Finally, field tests performed in another location (CPF) in which the injection temperature was controlled by a heat exchanger. The results were used to evaluate the differences between the documented cases and the Villano TIF cases.
Thermal fracture effects in Villano increased the injection rate by 34K bwpd which resulted in significant savings as new disposal well was not required. The thermal effect was reached with a low temperature reduction (20°F and 10°F), instead of the 50°F+ documented; the maximum reduction in the thermo elastic stress was around 26.5 psi/°F (Propped Fractured well) and 21.7 psi/°F (Non – propped fractured wells) which decreased the injection pressure by 530 psi 217 Psi respectively. Surveillance data suggests that the fractures will remain constant or will continue to grow by maintaining a low temperature. Documented studies advise that the effect is maintained when the temperature is increased however, tests performed in CPF disposal well confirmed that the effect is not permanent if the injection conditions are removed. In the particular cases of Villano and CPF fields, the injectivity is directly proportional to the temperature.