bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sand Handling Solutions Through the Use of Low Geometric Index Progressing Cavity Pumps, La Hocha Field, Colombia
Authors: Martinez Lozano Jorge Alberto , Cruz Torres Ediberto , Hernandez Castro Nadia Maoly , Coronel Avila Jorge Alberto , Soltys Tim , Ariza Gonzalez Gustavo Andres 
Published: June 2021

Abstract
A solution for extend run life with no intervention in a high sand cut and high viscous fluid application for La Hocha field (Huila, Colombia) is presented through the installation of Progressing Cavity Pumps (PCP) designed with aggressive geometries including low rotor swept angle and minimum geometry index concepts. This application has 100-300 BFPD flow rate, sand cut up to 40%, 16°API fluid and 850 cp @ 100°F.
This document shows the methodology applied in the selection of well candidates with high frequency of interventions due pump failures associated to sand production and well sanded. The effect of the PCP geometry design, cross sectional area, pitch length, helix angle, pump fit, and elastomer were evaluated consistently as selection criteria in order to verify their impact on PCP run life for sand production applications. The document aims to validate the PCP theoretical design principles with the statistic and results gathered from field during the past 3 years in La Hocha field application.
The "Fat Boy project" resulted in less intervention, well services, minimizing production delays and associated costs. The project started on mid-2012, due to successful results has been expanded and nowadays represents the 85 percent of the wells in La Hocha field. This is all part of a combined effort looking for reliable and cost-effective solutions for challenging applications. Progressing Cavity Pumps are used in a variety of oil and gas applications where their beneficial characteristics such as positive displacement, high efficiency, low internal shear rates and pulseless flow provide advantages over other artificial lift systems. PC pumps are available in several geometries which determine their suitability for specific applications assuring optimal performance and extended run life.
Analysis of Nitrogen Minimum Miscibility Pressure MMP and Its Impact on Instability of Asphaltene Aggregates - An Experimental Study
Authors: Elturki Mukhtar , Imqam Abdulmohsin 
Published: June 2021

Abstract
Minimum miscibility pressure (MMP) is a critical parameter when undergoing miscible gas injection operations for enhanced oil recovery (EOR). Miscibility has become a major term in designing the gas injection process. When the miscible gas contacts the reservoir oil, it causes changes in the basic oil properties, affecting reservoir oil composition and equilibrium conditions. Changes in conditions may also favor flocculation and deposition of organic solids, mainly asphaltene, which were previously in thermodynamic equilibrium. The main purpose of this study is to investigate how the most important parameters, such as oil temperature and oil viscosity, could affect the nitrogen (N2) MMP and the instability of asphaltene aggregation. Three sets of experiments were conducted: first, the determination of MMP was performed using a slim-tube packed with sand. The impact of crude oil viscosity using 32, 19, and 5.7 cp; and temperature using 32, 45, and 70 °C, were investigated. The results showed that the N2 MMP decreased when crude oil temperature increased. The temperature is inversely proportional to the N2 MMP due to the N2 remaining in a gaseous phase at the same conditions. In terms of viscosity, the MMP for N2 was found to decrease with the reduction in oil viscosity. Second, the effect of miscibility N2 injection pressure on asphaltene aggregation using 750 psi (below miscible pressure) and 1500 psi (at miscible pressure) was investigated using a specially designed filtration vessel. Various filter membrane pores sizes were placed inside the vessel to highlight the effect of asphaltene molecules on plugging the unconventional pore structure. The results demonstrated that increasing the pressure increased asphaltene weight percentage. The asphaltene weight percent was higher when using miscible injection pressure compared to immiscible injection pressure. Also, the asphaltene weight percentage increased when the pore size structure decreased. Finally, the visualization of asphaltene deposition over time was conducted, and the results showed that asphaltene particles started to precipitate after 2 hours. After 12 hours, the colloidal asphaltenes were fully precipitated.
An Enhanced Approach to the Remediation of Scale Induced Formation Damage - Offshore Trinidad
Authors: Francis-LaCroix Kyethann , King Joel , Moonilal Laura , Rauceo Reon 
Published: June 2021

Abstract
The remediation of flow assurance challenges in field's offshore Trinidad is a foci of oil and gas operators in Trinidad West Indies. These challenges are heightened by field maturity and the corresponding increase in water production. With this increased water influx, production chemistry and specific flow assurance challenges also arise. One of the primary challenges include the precipitation and deposition of inorganic mineral scales. Coupled with this, mineralogy data and core data studies indicated that the sands of some of the producing fields offshore Trinidad are highly susceptible to scale precipitation in the formation water (Holder, 1990). As such, measures are often implemented to assure the successful and economical flow of hydrocarbon stream from the reservoir to the point of sale.
In this geographical area, stimulation acid treatments were typically deployed for remediation of formation damage of which scale precipitation was a main type. However, based on the previous production histories, the production gains following these acid treatments were short-lived. In addition, the accompanying financial loss is often compounded by other flow assurance challenges that were precursed by scale deposition.
This paper will discuss the use of inhibitory squeeze application techniques as a preventative approach to formation damage resulting from scale precipitation. This application is the first of its kind performed in the Teak field. Thus, results obtained will highlight further opportunity to successfully stimulate other fields in this region prone to scale deposition. The results obtained from this application will be represented in the form of a comparative analysis. The production indices attained via the conventional means of scale remediation, will be compared with that achieved via the strategic placement of phosphonate-based chemistries. Additionally, methods employed to avert the challenges of squeeze treatments in offshore environments will also be discussed as well as lessons learned from this approach.
Unlocking Idle Production in an Offshore Sandstone Oil Field With Gas Hydrate Issues
Authors: Daramola Babalola 
Published: June 2021

Abstract
This publication presents how an oil asset unlocked idle production after numerous production upsets and a gas hydrate blockage. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with eight subsea wells tied back to a third party FPSO vessel.
Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the subsea pipeline between the well head and the FPSO vessel. A subsea intervention vessel was then hired to execute a pipeline clean-out operation, which removed the gas hydrate, and restored F5 well oil production. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects.
The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed to guarantee oil flow from F5 and future infill production wells. The test pipeline can be used to clean up new wells, to induce low pressure wells, and for well testing, well sampling, water salinity evaluation, tracer evaluation, and production optimisation.
This paper presents production upset diagnosis and remediation steps actioned in a producing oil field, and aids the justification of methanol umbilical capacity upgrade and test pipeline installations as facilities enhancement projects. It also indicates that gas hydrate blockage can be prevented by providing adequate methanol umbilical capacity for timely dosing of oil production wells.
Rate Transient Analysis in Two-Layered Reservoir Without Crossflow
Authors: Vasquez Michael B. , Adrian Pedro M. 
Published: June 2021

Abstract
Analysis of modern production data also known as Rate Transient Analysis (RTA) is a technique to perform reservoir characterization using the combination of bottomhole flowing pressure and flow rate data without the need to close wells. These methods allow the estimation of the Hydrocarbon Initially In-Place (HIIP), production forecast and main reservoir parameters.
Several RTA methods have already been developed to analyze different reservoir models such as homogeneous, naturally fractured, geopressurized, hydraulically fractured, however, in the case of layered reservoirs the studies are almost null although there are several studies conducted in the area of pressure transient analysis.
This paper presents the analytical derivation of the Palacio-Blasingame type curves to analyze production data of a two-layered reservoir model without crossflow or hydraulic communication between them.
A new set of type curves were generated by applying the Gaver Stehfest algorithm with Matlab to achieve the solution of the inverse of the Laplace space considering a constant flow of production flow and a flow regime in the radial pseudosteady-state, then applying the definitions dimensionless the proposed method was derived.
Synthetic data were generated with a commercial simulator to validate the method. Furthermore this paper presents a field case study application. The results were compared to the type curve for homogenous reservoirs, volumetric method as well as well testing results.
Results confirmed the applicability of rate transient analysis technique in a two-layered reservoir without crossflow with a single drainage area and the same initial pressure for all layers (same pressure gradient of formation), and different values of thickness of the layers, permeability and porosity.
Simulating Downhole Temperature Logging Data for Optimum Downhole Production Surveillance
Authors: Hashmi Gibran M. , Hamza Farrukh , Azari Mehdi 
Published: June 2021

Abstract
Reservoir management best practices originate from efficient well operations. The fluid flow profile from individual wells can change over time, sometimes unpredictably; as the reservoirs become depleted, changes in hydrocarbon properties occur, and water cut begins to increase. During primary, secondary, and tertiary recovery from conventional and unconventional wells, production surveillance is pivotal for optimum reservoir management. Determining the downhole production flow profile from multiple zones helps to manage drawdown pressure, regulate surface choke settings, and mitigate excessive water production.
This paper presents a rigorous mechanistic analysis of the heat transfer and fluid flow around the wellbore to aid in determining a generalized wellbore flow profile. The approach enables the calculation of multiphase rates independently of downhole spinner data and is based almost solely on temperature measurements. Because temperature measurements are reliable and more commonly available, the method provides a robust technique to determine flow contributions across a broad spectrum of surveillance applications. The technique is shown to work with other logs, such as capacitance, fluid density, and gas holdup tool, to relay more refined information about fluid phases during production.
The methodology presents an application of transient-temperature modeling for computing flow rates from temperature data obtained during a wireline run. The approach includes an analytical wellbore fluid transient-temperature model. Temperature calculations depend on mass flow rate and flow duration; therefore, an inversion technique is applied to match the measured temperature and calculated temperature for a given time duration to estimate flow rate. The model is observed to depend on determining an accurate geothermal gradient, particularly in cases of early time flow. The various heat transfer resistances in the system are calculated based on the completion mechanics. The method also accounts for the effect of friction and pressure drop in the wellbore on fluid temperature. The case study included demonstrates the utility and value of the transient model. The transient nature of the model also facilitates multiple applications. Real-time flow rate monitoring, zonal contributions, flow behind casing, quantitative determination of leaks, and completion integrity are all potential applications of the proposed method.
The transient-temperature modeling methodology can be used with production logging spinners to calibrate the model and provide a permanent downhole monitoring tool to help avoid costly logging reruns. The study provides a foundation for various applications arising from conventional production logging measurements and could be particularly useful in cases, such as offshore fields, where more evolved unconventional techniques can be difficult and costly to apply.
Proposal EOR Fiscal Incentives to Increase the Recovery Factor in Mexican Fields Implementing Enhanced Oil Recovery Methods through Sensitivity Analysis with Different Contracts
Authors: Espinola Oswaldo , Nunez Fernando , Malibran Pedro Tomas 
Published: June 2021

Abstract
The current business strategy of Operators in Mexico has considered finance Enhance Oil Recovery projects. Moreover, the potential in Mexico for EOR is represented by 80% of the total production coming from mature fields. However, these projects are difficult to be executed below current circumstances, oil prices and existing fiscal terms. For this reason, there is an opportunity to evaluate how to switch the situation and generate scenarios where it might be possible to perform such as complex project.
Therefore, this study presents a methodology from a technical and economical perspective that includes the selection of a representative reservoir, evaluating different production forecast scenarios below EOR schemes, comparing fiscal models and running sensitivity analysis to end up with an incentive adjustment, to evaluate the potential benefits of fiscal incentives and how they could be applied effectively to EOR implementation projects.
To demonstrate the potential of these projects in Mexico, a reservoir with specific characteristics had been selected to simulate the performance of a mature field where thermal pilot projects are conceptualized. Nevertheless, the focus of this study is to evaluate the current fiscal terms and taxes versus innovative fiscal terms with applied incentives.
This work pursuits to find a window of opportunity for complex projects that embraces current oil prices, appropriate fiscal terms, tax incentives, and technical considerations. Overall, the proposed methodology defines how to apply the appropriate incentive in combination with several parameter to enable the execution of these projects.
Finally, as a result of this study, it had been demonstrated that at given conditions and adding a package of incentives, there is a win-win schema where the Government and the Operators obtain higher returns than the conditions of exploiting the fields only with natural depletion. These proposed conditions can be used to promote economic benefits that encourage EOR projects and attract investment in Mexico, and consequently, increase recovery factor of mature fields.
Digital Workflow to Enhance Reservoir Management Strategies for A Complex Oil Field Through Real Time and Advanced Engineering Monitoring Solution
Authors: Alvarez Julieta , Espinola Oswaldo , Diaz Luis Rodrigo , Cruces Lilith 
Published: June 2021

Abstract
Increase recovery from mature oil reservoirs requires the definition of enhanced reservoir management strategies, involving the implementation of advanced methodologies and technologies in the field's operation.
This paper presents a digital workflow enabling the integration of commonly isolated elements such as: gauges, flowmeters, inflow control devices; analysis methods and data, used to improve scientific understanding of subsurface flow dynamics and determine improved operational decisions that support field's reservoir management strategy. It also supports evaluation of reservoir extent, hydraulic communication, artificial lift impact in the near-wellbore zone and reservoir response to injected fluids and coning phenomenon. This latest is used as an example to demonstrate the applicability of this workflow to improve and support operational decisions, minimizing water and gas production due to coning, that usually results in increasing production operation costs and it has a direct impact decreasing reservoir energy in mature saturated oil reservoirs.
This innovative workflow consists on the continuous interpretation of data from downhole gauges, referred in this paper as data-driven; as well as analytical and numerical simulation methodologies using real-time raw data as an input, referred in this paper as model-driven, not commonly used to analyze near wellbore subsurface phenomena like coning and its impact in surface operation. The resulting analyses are displayed through an extensive visualization tool that provides instant insight to reservoir characterization and productivity groups, improving well and reservoir performance prediction capabilities for complex reservoirs such as mature saturated reservoirs with an associated aquifer, where undesired water and gas production is a continuous challenge that incorporates unexpected operational expenses.
Artificial Intelligence AI / Machine Learning ML Drives Increased Capital Efficiency and Minimizes Geological Risk in E&P Operations
Authors: Aming Anthony 
Published: June 2021

Abstract
This paper presents how Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms in Exploration, Drilling Operations, Field Appraisal, Development and multiple 3D seismic volumes comparisons to minimize geological risk and uncertainty resulting in increased capital efficiency. We will present a high level overview of why this technology was invented and how it works. We will show you how you can use it to significantly reduce the time to achieve your organizational goals while reducing geotechnical risk and uncertainty and optimize the cycle time from Lead to Production. Outputs include a comprehensive analysis of your entire 3D Seismic Data Volume to identify and high grade, quality leads and prospects with high resource potential in the near, medium and long term. This approach will allow an evaluation of the field geological risk (reservoir distribution, trap, seal, source, hydrocarbon migration pathway from source into reservoir) and initial possible hydrocarbon content/type evaluation (e.g. DHI evaluation) without disrupting your current workflow. The results will quickly delineate possible structural and stratigraphic targets. This will also provide the Production Asset with additional support in their appraisal and development drilling programmes. Optimally place horizontal wells and injectors / offtakes in Improved Oil Recovery/Enhanced Oil Recovery (IOR / EOR) projects in areas of the field having the highest reservoir continuity to optimize the cycle time from concept to production. The case studies and examples presented will demonstrate how the technology and approach serve to increase the probability of success leading to increased capital efficiency and profitability.
A Simulation Study of the Effect of Injecting Carbon Dioxide with Nitrogen or Lean Gas on the Minimum Miscibility Pressure
Authors: Mansour Ahmed GH , Gamadi Talal , Saoyleh Hussain R 
Published: June 2021

Abstract
The objective of this study is to determine the effects of the concentration of injected gases on recovery factors. CO2 has been used for flooding because it requires low injection pressures to achieve miscibility. However, the availability of CO2 is an issue. CO2 required for the process is not sufficient for the reservoir under consideration. Moreover, its benefit-cost ratio (b/c) represents another issue; higher volumes of CO2 increases the economic expenditures. An alternative is to inject lean gas or nitrogen along with CO2 to achieve better recoveries at optimum costs and suitable pressure.
Slim tube simulation using a commercial simulator is utilized to measure the minimum miscibility pressure (MMP) of an injected gas mixture. The mixture contains CO2/N2 or CO2/lean gas. Using different concentrations in the injected mixture, an effect on the recovery factor is studied. The first 30 runs have 100% concentration of each individual gases i.e. N2, CO2 and lean gas. Based on these runs, the simulation model is validated using the co-relations present in the literature. Gas mixtures of CO2/N2 and CO2/lean gas were then simulated using the compositional model to test the effect on MMP by varying the concentration of each gas in the mixture. By changing the volumes of the gas in the injected mixture, we can find the optimum concentration of each component in the mixture in terms of MMP.
From the results obtained through simulation, it can be deduced that higher percentages of CO2 in the mixture would result in reduced minimum miscibility pressure. The addition of a secondary slug to the injected CO2 fluid increases the pressure required to achieve miscibility. Of N2 and Lean gas, Lean gas provided better results as it showed low miscibility pressure responses compared to the same amount of N2 gas. For example, for a case, 50% CO2 and 50 %N2 or lean gas mixture, the MMP for the lean gas mixture is 3500 Psi, while for N2 mixture it was 4667 Psi. However, lean gas is expensive as compared to N2 and N2 is easily available. N2, if used in optimum concentration along with CO2 can produce greater recoveries keeping the process cost-effective while satisfying other constraints. CO2 is widely used for miscible injection, but it presents problems like costs, corrosion, and asphaltene deposition etc. The study can give an idea of the success of carrying out EOR through gas flooding by using N2 and CO2 to enhance recovery at low cost. N2 is easily available from air and it is cheap.
20 Years of Independent Oil and Gas Audits: The Trinidad and Tobago Story
Authors: Welsh Christian Paul 
Published: June 2021

Abstract
Over the 20 year period from 2001 to 2020, the Ministry of Energy and Energy Industries (MEEI) of Trinidad and Tobago commissioned 19 gas and 3 oil audits conducted by independent consultants. Trinidad and Tobago's natural gas Technically Recoverable Resources (TRR) moved from a P1+C1 TRR to Production Ratio of greater than 30 in 2001 to less than 10 years as production has grown from a low of 1.5 Bcf/d to a high of 4.3 Bcf/d. Despite this, the opening of a new exploration basin in the Deepwater has resulted in greater than 100% technically recoverable resource replacement in the last three years for natural gas and a 770% increase in Prospective Resources for crude oil. The data from these successful audits have served to demonstrate the astute management by the Government and People of Trinidad and Tobago of the country's hydrocarbon resources.