bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimization of Casing Design for Wells Drilled in Llanos Region in Colombia. A Technical Analysis of the Problematic and the Adopted Solutions.
Authors: Romero Carolina , Alvarez Jorge
Published: July 2020

The objective of this paper is to present a timeline of the different well designs used in Llanos 34 Block that led to obtain the slimmest well design possible, indicate the challenges experienced with every well design, and the casing design recommendations and developments to mitigate these challenges.

Within this paper, we present the challenges that led to a new well architecture and the results in the field. The paper includes the detailed engineering analysis for the new architecture, including casing design, and torque and drag analyses. Additionally the paper compares the results in the field with the engineering analysis to validate the inputs and models. Finally, the paper includes a summary of the cost reductions of the new architecture and the lessons learned related to the models, operations and casing connection technology.

Different alternatives of well design were analyzed for the wells to be drilled in Llanos 34 Block, depending on the horizontal displacement required. Initially, a three section well was design with horizontal displacement of 4,000 ft or higher, considering a 9 5/8" production casing with a high collapse grade; and another option with a two sections well design when the vertical section was below 4,000 ft, with a 7" production casing. This alternative presented the opportunity to optimize costs and drilling time. The engineering analysis for the new architecture presented a challenge for running 7" casing in a longer open hole section; with very high values of torque expected. The casing connection manufacturer worked to improve the design of the connection to reach the required torque. In June 2016, the operator drilled the first well with the new architecture obtaining very good results, reducing cost and improving service performance. As a result, the new architecture became the standard with 46 drilled wells from June 2016 to June 2019. This paper includes the engineering analysis of new highly deviated wells and the casing connection technology developed for these new requirements.

The experience obtained by the optimization of the well design in Llanos 34 Block and the technical challenges faced by the production casing, can provide to different operators ways to optimize their well designs.
Synthetic Base Drilling Fluid Applications Under Extreme Pressure and Temperature Conditions in Gulf of Mexico
Authors: Hernandez Monserrat , Quissak Felipe , Córdova Monica , Torres Jorge
Published: July 2020

The design of an invert emulsion fluid that can hold up more than 24,000 psi and 435°F is a complicated and exhausting process. The challenges presented in the design of an UHPHT drilling fluid formulation are the base oil selection and the complete drilling fluid formulation. Flash point measurement of base oil before and after heat ageing to ensure that the base fluid were stable and the overall stability of the mud system need to be assured (rheology, gelation, fluid loss and weight material suspension) after both dynamic and static ageing for at least 96 hours at anticipated maximum BHST.

Laboratory pilot testing allows us to find a chemical balance where the rheology profile and mud properties fulfill the UHPHT project requirements. The laboratory testing protocol validation is the most important factor to prevent different issues during the drilling phase. This testing will be a contributor factor to conclude a well successfully.

Another phase of the design that we need to consider is an exact dynamic temperature modelling because a more precise Bottom Hole Temperature profile helps optimize the drilling process to increase the possibility of borehole stability.
A New Approach to Design Completion Fluids Including Hydrate Inhibition in Deep Water
Authors: Espinoza Juan Carlos
Published: July 2020

In the completions of deep-water wells with the presence of gas, it may be necessary to use gas hydrate inhibitors, in these cases the design of the completion fluid usually focuses on determining the concentration of hydrate inhibitor and meeting the criteria of maximum pressure and minimum crystallization temperature of the brines. The effect of the hydrate inhibitor on the PVT behavior of the mixture is usually ignored, the changes in the compressibility of the mixture (brine - hydrate inhibitor) may be different from that of the brine without a hydrate inhibitor, and could place the pressure hydrostatic outside the mud window geopressure, compromising the stability of the well.

To solve the problem that represents the design of the completion fluid for wells in deep water environments, in this work a methodology of design of the completion fluid is proposed that integrates compliance with the requirements of hydrate inhibition, crystallization, and stability hydraulics. The methodology guides the design of the completion fluid, until it meets all the requirements of the well. The proposed methodology addresses deep-water environments, however, it can be applied to HPHT wells or in all cases where PVT changes occur in completion fluids.
Design of a Computational Tool in Python for the Calculation of the Optimal Potential in the Huyapari Field - Petropiar
Authors: Acosta Rommina
Published: July 2020

The current demand for fossil fuels will promote the search for techniques to increase hydrocarbon production, so methods are needed to accelerate the development of this resource. The use of computer tools in the oil industry is indispensable today; we use increasingly powerful algorithms that perform extremely complex analyzes, which enable us to obtain solutions to previously affected problems pending in the industry. Most of the time the lack of parameters forces engineers to limit the study of a well, making restrictions and predictions not so accurate, especially regarding production; Based on this, the main objective is the development of a computational tool that allows to calculate the production potential of the wells drilled in the Huyapari field, which will use the python programming language, encoded from such a way to perform the calculations under the statistical methods of the analogous wells, the Joshi equation and nodal analysis. This tool is divided into two phases: the first is the calculation of the potential for pre-drilling and post-drilling of wells; the second phase is the adjustment of the potential that is carried out by means of the individual nodal analysis of each well taking into account the current reservoir pressure and the immersion limit of the pump.
Hybrid Nanomaterials for Enhanced Oil Recovery: New Alternatives for Polymer Thermal Degradation
Authors: Ruiz-Cañas María Carolina , Manrique Eduardo , Romero Arnold , Quintero Henderson
Published: July 2020

One of the alternatives currently emerging as a solution to the problems presented by the HPAM in high temperature reservoirs is the use of nanotechnology as a tool to improve and potentiate the properties of the polymer. Nanoparticles have been used to improve the stability and viscosity of HPAM solutions and their properties could be an important tool to improve the thermal resistance of polymers. The scope of this work is the evaluation of new hybrid nanomaterial based on HPAM and nanoparticles of silica dioxide.

The new prospective hybrid nanomaterials for oil and gas including Enhanced Oil Recovery (EOR) applications in were characterized including its thermal properties with applied advanced techniques such as Scanning Electron Microscopy (SEM - EDS), X-Ray Photoelectron Spectroscopy (XPS) and Thermogravimetric Analysis (TGA). These techniques contributed to demonstrate the formation of a covalent bond between the nanoparticle and the HPAM polymer, which allows having an inorganic - organic interaction that, according to its thermal properties, has a great potential in polymer flooding, among other applications.

The results obtained with these techniques were compared with the synthesis precursors, which shows the morphological, structural and property changes of the new nanomaterial with respect to the synthetic polymer. The elemental analysis carried out by EDS demonstrate the presence of C, N, O and Si in the structure of the new nanomaterial based on silica nanoparticles.

The high-resolution spectra obtained by the XPS technique show the functional groups corresponding to the covalent bond between the polymer and the nanoparticle, which provides a greater thermal resistance to the nanomaterial with respect to the conventional polymer. This thermal resistance is determined with the thermogravimetric analysis, in which the polymeric precursor and the new nanohybrid are subjected to a high resolution temperature ramp with a change of 10ºC / min from 25ºC to 700ºC. The results present a competitive advantage to the commercial polymer throughout the evaluation range, which will allow increasing the application ranges of the HPAM polymers and potentially inducing an increase in the recovery of oil.
Surveillance System for Dehydration and Desalting Process Optimization by Chemical Mitigation for a Marine Terminal in Mexico
Authors: Claib Meinhardt Amin Adolfo , Guan Hua , Lopez Cisneros Luis Fernando , Perez De La Cruz Marco Antonio , Lorenzana Alberto , Guerra Carvallo Claver Hugo , Ruiz Roque Sergio Ivan , Ramirez Olarte Hector Eric , Balderas Perez Harvey David
Published: July 2020

Oil quality management is an ongoing challenge, and there are costly financial implications when the product quality falls below the required specifications for trading. Furthermore, it has been reported that upsets in the dehydration and desalting (D&D) process leading to off-specification oil quality are commonly experienced following well interventions (stimulations and cleanouts), particularly when dealing with heavy oil.

Detailed research of problems at one D&D facility was conducted, starting with the analysis of existing field data (mainly from well stimulation and cleanout jobs) and recommending and processing laboratory tests to identify the root causes. A chemical mitigation strategy was developed with the implementation of key performance indicators (KPI) and workflows in a production operations software platform, which includes a surveillance and smart alert system that displays KPIs on dashboards for chemical management, mapping for forecasting scenarios of well jobs, time to arrive to the D&D facility, and chemical injection forecasting. The production operations platform is used for input data and generating dashboards including data from SCADA and dynamic multiphase flow simulation online systems to obtain and build the gathering network locations for all jobs and the lapsed time to arrive at the D&D process, making back allocations to gathering stations.

About 30% of stimulation and cleanout jobs have affected the D&D process due to increased volume of suspended solids in the system; these act as natural emulsifiers at the water-oil interface, contributing to emulsion stabilization. When the emulsion is highly stable, the applied chemical treatment becomes ineffective downstream; the D&D process is therefore unable to effectively remove water and salt from oil. The irregularity of the demulsifier injection also adversely affects the efficiency of the process.

The completion of this work provided a clear understanding of the root causes and insights into KPI behavior. The integrated solution enabled real-time monitoring and optimization of the chemical mitigation through better data usage and interpretation using the production operations platform combined with the multiphase flow simulator online system. This enabled the operator to perform timely monitoring and to proactively take actions to reduce the impacts on heavy oil quality.
Economical and Technical Solution for Waterflooding Projects in a Mature Field: Modified Dump Flooding Well Completion Strategy
Authors: Meneses Sterling Alba , López Ruiz Yeniffer , Azancot Annalyn , Charry Lina , Correal Alvaro , Fuentes Llesica , Pastrana Wilmar , Silva Angel , Garcia Jose Norberto , Vasconez Nestor Danilo
Published: July 2020

It is a common practice to evaluate an injection pilot before a field-level implementation of waterflooding, but this requires early investment in facilities and construction time. An alternative solution is proposed as a modification of the dump flooding concept: Produce water from a low-salinity aquifer and inject it into an oil reservoir within the same well, using a closed system. The modification of the conventional dump flooding design consists of adding surface monitoring and control capabilities, which for this mature field is a local regulatory requirement

A comprehensive process for the completion design considered reservoir, well and operational conditions as both new and existing wells were considered as candidates for these completion systems. The design consists of a concentric completion with packers to isolate both the water aquifer and oil reservoir. Water is produced from a deeper low-salinity aquifer with excellent water quality through an Electric Submersible Pump (ESP) that also serves as an injection pump. At surface, the water rate is measured by a flowmeter and then injected into the same well through a concentric string to a shallower oil reservoir for secondary recovery. A simple closed-loop system at surface eliminates contact with oxygen, minimizing future corrosion problems. The high quality of the water (low salinity, without solids, O2, H2S or Fe) eliminated the need for water treatment.

Four wells have been successfully completed using this design, currently injecting at the required rates without presenting any functionality problem. Additional three wells are in schedule to be completed in order to accelerate waterflooding implementation in areas either remote or environmentally sensitive with no nearby water source. In these areas, implementing a waterflooding conventional pattern that requires connecting water producers and injector wells would require lengthy permission processes for long high-pressure lines and additional time for the construction of those water transport pipelines.

The completed modified dump flooding wells decreased the implementation time of the waterflooding pilot project from 2.5 years to 5 months. Additionally, the environmental footprint and facilities investment has been reduced by an estimated 90%. This is the estimated cost savings when comparing the investment in dump flooding well construction versus conversion of existing wells to water producers or injectors and the investment in facilities, including water treatment plants, to connect those wells.

This paper presents the main design and operational considerations before execution, deployment challenges, and lessons learned and recommendations from the execution of the first campaign
High Density Polyethylene Liner: Successful Alternative Against Corrosion and Wear Problems in Production Tubing of Mature Fields in Colombia
Authors: Duarte Poveda Gloria Isabel , Mateus Barragán Miguel , Estévez Lizarazo José Alexander , Doval Jorge Mario , Barragán Patricia
Published: July 2020

The production tubing in wells of mature fields in Ecopetrol located in the Middle Valley of Magdalena has shown a run life between 180 and 300 days. The main failures are due to corrosion and abrasive wear or friction mechanisms that, according to root cause analysis (RCA), could be the result of exposing the carbon steel to aggressive fluid, production sand and contact with sucker rod (beam pumping-BP or progressive cavity pumping-PCP).

Taking into account the positive experience previously obtained at field test and extended use of the HDPE liner in flow and collector lines with corrosion and abrasion problems, this work presents the results evidenced in laboratory evaluation and demonstration trial of the HDPE (High Density Polyethylene) liner to mitigate premature failures and prolong run life of production tubing.
Radio-Frequency Application for Oil Mobility Improvement in the Hollin Formation in Ip-15 Well. Pungarayacu Field
Authors: Llamuca Luis , Bonilla Andres , Mariño Rolando
Published: July 2020

In recent decades, oil producing countries have focused their efforts on incorporating new oil and gas reserves that support their long-term economic plans. An oil peak production in 2020 has been forecast by Belani (2006), and the challenge to find more reserves becomes greater as statistically the conventional to unconventional oil and gas resources ratio (2:8) may suggest that most conventional oil resources have been already found (Zou et al., 2015). This situation has risen concerns among oil dependent countries but have opened the gates for the development of unconventional oil resources in developed countries such as Canada, USA, China, etc (Belani, 2006). Crude bitumen is one kind of unconventional oil that poses a significant opportunity for development in Ecuador. According to a report by Gaffney, Cline & Associates (GCA) and Ivanhoe Energy in 2009, the Pungarayacu Field (Block 20) holds 6.4 billion barrels of oil initially in place (OIIP) and is considered the largest unconventional asset in the country. The challenge for its development consists of overcoming a low oil mobility associated to high oil density (ranging from 8 to 10 API) and viscosity values.

This work presents the application of Radio-Frequency (RF) for hydrocarbons thermal heating as an alternative for extra heavy oil recovery enhancement in the crude bitumen deposits of Pungarayacu Field in Ecuador. The activities conducted in this study include an approach to investigate, experiment and model the bahaviour of the reservoir temperature at a small scale under the influence of heat generated by microwaves. The study will demonstrate that hydrocarbon heating through the use of radio frequency represents a valid alternative for heavy oil extraction and discuss its feasibility based on an energy consumption analysis and some comparisons with upscaled projects using Steam Injection technology.
Subsea Systems Innovations and the Use of State of Art Subsea Technologies Help the Flow Assurance of Heavy Oil Production in Ultra-Deep Waters
Authors: Pedroso Carlos Alberto , Rosa Geraldo , Borges Priscilla , Nunes Kleber
Published: July 2020

Flow assurance in ultra-deep waters oil production is always a major concern. Atlanta field, which produces heavy oil in ultra-deep waters, is one of the most challenging project offshore combining several difficulties: hydrates formation, emulsion tendency, scale formation, foaming, high viscosities that can achieve 100.000 cp at sea bed temperatures, etc.

To overcome these challenges, the best subsea system technologies has been used, together with some small, but ingenuous, innovations.

The use of a 6" unbonded flexible lines, with TEC 2 insulation layers minimize the risk high viscosities in case of the expected shut downs.

To cope with scales, foaming and emulsion, chemical additives can be deployed into the wells through the biggest and unique umbilical installed in Brazil, which accommodates 15 hoses, 2 MV Electrical Cables of 3X150mm2 and 2 Eletrical Cables with 4x6mm2 and 2 eletrical cable of 4x2,5mm2.

Hydrates can block the flowlines stopping the production. When it occurs, the remediation is normally long and expensive. For hydrates, the cliché "prevention is better than remediation" is true. Hydrates can be prevented with proper procedures and preventers. But in case of hydrate formation, a pioneer hydrate mitigation panel, operated by ROV was installed in the wet christmas tree (deployed by cables).

And finally, to guarantee the production flexibility for production and maintenance, an innovative and unique subsea lay out, consisting of two Electrical Submersible Pump (ESP), one in-well and other in mud line skid, was developed and installed.

All this innovations and best technologies used together made Atlanta a successful case of heavy oil production in ultra-deep waters, triggering huge resources around the world.
New Generation Formation Testing ORA Platform Used to Test and Sample Tight Naturally Fractured Carbonate Under HPHT Conditions
Authors: Gama Villegas Raul , Mendez de Leon Javier , Navedo Flores Victor Jesus , Dubost Francois-Xavier , Pfeiffer Thomas , Edmundson Simon , Partouche Ashers , Lavin Vizcaino Manuel , Hernandez Espinosa Hugo
Published: July 2020

Reservoir sampling and pressure (RS&P) testing acquisitions are fundamental in Exploration settings to evaluate reserves and/or well productivity. Wireline Formation Testing (WFT) is well known in our industry for conventional reservoirs. However, there has not been any available WFT technology to perform these acquisitions in Naturally Fractured Carbonate (NFR) formations under HPHT conditions. A new platform developed for all terrains of formations and environments was used for the first-time in in Mexico, allowing to conduct a full RS&P program to delineate reserves in a large gas condensate reservoir.

The new platform consists of a new focussed radial probe inlet, featuring a dual flowline with dual downhole pumps to allow focused sampling mode. Given the larger flow area of the new probe system, flow tests can be conducted in sub mD permeability zones, typical in NFR carbonates, and fluid identification can be performed in-situ while flowing thanks to a group of new sensors. Sampling for PVT analysis is achievable, and sample quality is ensured via the focused sampling system. Post sampling buildups provide pressure transient test data which allow characterizing the layer productivity.

The new technology was employed in two appraisal wells belonging to the Veracruz basin in Mexico. The reservoir facies are constituted by packestone and wackestone carbonates belonging to the mid Cretaceous, over very large thickness. Reservoir quality lies in vugular porosity and micro-fractures; however, the matrix porosity is low. The petroleum system originates from the Upper Jurassic source rocks which led to gas condensate hydrocarbons at the reservoir level today.

Preliminary simulations indicated that despite the low matrix quality, with the new platform, it would be possible to test and recover quality samples within 4-8 hours depending on the invasion depth scenario and with a drawdown below 300 psi. Four conclusive tests were made in the first well which helped the operator delineate reserves and two conclusive tests were made in the other well fulfilling objectives and following the designed test durations and outcomes, in temperature conditions up to 182 °C and pressure of 20kpsi. The lowest mobility flow test and fluid identification was conducted in 0.06 mD/cP.

The new platform test results compared very well with actual test results that were conducted.

These two cases highlight the possibility to test and sample fluids in HPHT conditions, NFR reservoirs with tight matrix properties with the new formation testing platform, in environments where previously formation testing was not possible. A significant amount of Mexican carbonate reservoirs faces this extreme environment.
Evaluation of Well Performance Using Data from Fiber Optics Sensors, in Wells of the Pilot Polymer Flooding Test. Orinoco Basin, Venezuela
Authors: Ramirez Andres , Vasquez Edgar , Quevedo Luis , Ulacio Ivon , Rojas Gonzalo , Rodriguez Oswaldo , Gamez Hector
Published: July 2020

In the case of this pilot test using polymer flood, evaluating the performance of injector wells was one of the main priorities. Losing injectivity is recognized as one possible cause of poor performance in the case of enhanced oil recovery processes, so estimation of the length of the well that contributes with injection, the identification of by passed zones, the diagnostics of the well behavior, and recommending solutions for a future project, were part of the objectives stablished at design of the project. For those reasons, we chose to complete the wells using a distributed temperature sensor (DTS).

After installation of fiber optic sensors system in the wells associated with the project, the acquired data was analyzed using different techniques: Comparison of the effective length obtained from the static model with the one obtained from fiber optic sensors, and also pressure test analysis, later the distribution of the injection rate in each case was obtained. Initially it was necessary to establish a base behavior: Real-time measurements of pressure and temperature, characteristics of the injected fluid, and petrophysical evaluation of the completed intervals, which was used as departure point for studies performed.

Maintaining a good injectivity in polymer injection projects normally is a major concern, in this case we present a real case of a polymer injection project in an extra heavy oil reservoir, which is producing oil with an average viscosity of 4150 cP at reservoir conditions. Polymer solution with a concentration of 1600 ppm was injected since 2017 and the injection is maintained so far without important reduction in the injectivity index. An estimated of the injection interval was established, and also estimation of the injection distribution in the horizontal section. The estimation was then validated with the results of the measured surface rate, and pressure transient test analysis. In average 30 % of the horizontal section of the well were receiving polymer solution, and then thanks to this new information zones not receiving polymer solution were identified. The results were used to improve the reservoir simulation models, and as diagnostic tool for pilot test.

This paper describes how a better understanding of the connection between the well and the reservoir, can improve the reservoir simulation models, decision making process, and well performance evaluation. Also the importance of determine the possible not swept areas in the reservoir, which could result in low volumetric swept efficiency, and as a consequence low recovery factor. Finally the results presented here could be useful to the general interest of engineers dedicated to polymer flooding projects.
The Use of Drilling with Casing to Set a New Standard for Drilling Operations in Argentina
Authors: Espinosa C. M. , Watts R. D. , Rebasa N. , Lojk C. I. , Roldan C. , Codega D. , Castiñeiras T.
Published: July 2020

During the last 7 years the number of projects and operators using drilling with casing has increased steadily in both the Vaca Muerta shale play and in the Golfo San Jorge mature projects.

The following paper summarizes the evolution of the use of this technology and the benefits it has brought to operations in Argentina. Additionally, as some premature failures occurred, the paper identifies some limitations of the technology and the lessons learned from those failures.

Within this paper, detail will be presented for the current use of Drilling with Casing (DWC) technology in shale operations and mature fields in Argentina. A summary the drivers and benefits of the technology along with its limitations will be presented. In particular, the paper will include the analysis of some premature failures with a set of recommendations to minimize the risk of failure.

Several operators are using DWC in their operations in unconventionals fields in Vaca Muerta and in mature fields in the Golfo San Jorge Basin. The highest percentage of the strings installed is for surface casing where the main target is to reduce Non-Productive Time (NPT) during drilling. The use of DWC has extended to almost all projects in Vaca Muerta, making it a standard technology for the surface casing section in one of the most important shale plays outside of North America. In the Golfo San Jorge basin, the DWC technology has been used to overcome drilling challenges of mature fields with extensive water flooding, wellbore instability, inflow control and differential sticking. The results have helped operators to reduce NPT. The technology has proven its reliability with more than 1200 strings installed in the last 7 seven years. However, some premature failures have occurred and resulted in an intensive investigation by the casing manufacturer. The failure analysis showed that fatigue was the most common mode of most of these failures. The challenge rose when the available fatigue modes could not predict or replicate the failures. Within the paper we detail the probable sources of loads that provoked the failures and some recommendations that will help to minimize the risks for the future.

The use of DWC and its benefits in Argentina could be replicated elsewhere reducing costs and improving efficiency. The set of reccomendations of the paper could help to reduce the risk of future operations.
Implementation of Extended Range Pump as a Solution for Low-Input Wells. Success Story in Llanos Norte
Authors: Nunez Walter , Del Pino Jessica , Garzon David , Pinto Duvan , Gonzalez Camilo , Pinilla Jaime , Gomez Alvaro
Published: July 2020

In the Llanos Norte area, ESP systems represent 92% of the installed artificial lift systems. According to the current production strategy in this field, there is a need for intervention in low quality sand. The design of the artificial lift system is affected by the uncertainty of the productivity index and expected flow rates. 25% of the completions designed for low flows have had deviations greater than or equal to 50% between the design parameters and the actual parameters. This condition has led to the search for alternatives for intervention and completion of this type of wells, this because the conventional technology of the pumps used historically in the field does not allow producing efficiently in such a wide uncertainty production ranges.

Service Provider, from the hand of the Operator implemented a pump called FLEX-ER (extended range pump). This solution allows extending the range of the efficiency cone of the pump from 50BFPD and up to 2900BFPD, this feature helps to mitigate the uncertainty in the available design parameters, keep the pump in the optimal ranges of operation, avoid the up and down wear of the stages, thus increasing the lifetime of the electrosubmersible system.

The implementation of this technology has allowed having an ESP equipment available to cover the production needs of the wells in low quality sands of northern plains. The wide range of operation of this stage allows to be protected against uncertainty in productivity and facing the changes that the well may have during its production stage. Additionally, the implementation evaluation model for 8 wells resulted in a projected saving of USD 1.4 million, as a consequence of the reduction in intervention costs, energy consumption and NPT reduction. According to these results, it is expected for the next well drilling and reconditioning campaigns, including the standardization of the technology in order to optimize the production processes of Occidental.

This paper aims to present the most important technology implementations, follow up and results as well as the impact in field performance KPI.
Pressure Transient Analysis PTA Diagnostics and Screening Criteria
Authors: Alcantara Ricardo , Ham Juan Manuel , Paredes Jorge Enrique , Petriz Jose Maria , Sanchez Guillermo , Briones Mario , Fuentes Gorgonio
Published: July 2020

The objective of this work is to generate a selection matrix that contributes to the decision making, contemplating all the necessary technical criteria to ensure that the information gathering is adequate and the Pressure Transient Analysis (PTA) could be advantageous for the reservoir characterization and the determination of well productivity parameters.

For this scrutiny we analyzed more than 500 well tests from 100 fields in Mexico and other parts of the world, onshore and offshore, carbonates and terrigenous, and different types of fluids (black oil – extra heavy, heavy, intermediate and light, volatile oil, retrograde gas and condensates, wet gas and dry gas), from which all the pressure responses obtained were compared in order to identify every associated problem and the causes that originated them from the design, execution and finally, during the interpretation of the PTA.

The importance of this work lies in improving the PTA through the allocation of different numerical values for each of the controlling factors involved at reservoir, well and at surface level, depending on its own impact on the results, so we classify them in Well Evaluation Conditions (WEC) and Reservoir Evaluation Conditions (REC).
Redefining Technical Limit – Managed Pressure Directional Drilling Solution in Mexico Zaap Field
Authors: Lopez Infante Jose Luis , Vizcarra Marin Hector Hugo , Fernandez Mendez Jorge Armando , Ngan Alex , Acosta Javier , Garcia Edgar
Published: July 2020

This paper will discuss the Managed Pressure Directional Drilling fit for purpose solution deployed to meet the drilling challenges in Mexico offshore Zaap field. This innovative solution integrates a new state-of-art Rotary Steerable System (RSS) with Managed Pressure Drilling (MPD) technology. Drilling hazards such as total losses, wellbore instability and stuck pipe were mitigated, and an improved drilling performance with reduction of NPT as compared to other directional drilling systems.

The solution requires the integration of two highly technical disciplines, MPD and Directional Drilling (DD). Hence, a Joint Operating & Reporting Procedure (JORP) and a defined communication plan are crucial for the effective execution. The solution is based on a rigorous Drilling Engineering process; including detailed offset wells analysis to deliver a comprehensive risk assessment & mitigation plan in collaboration with the operator to tackle drilling hazards without compromising the directional drilling requirements.

The paper will also discuss the effective communication plan between the directional drilling services, MPD services and rig contractors to ensure safe operational alignment. Also, the paper includes a planning and operational blueprint to reduce NPT related to total losses, stuck pipe & wellbore instability, increase drilling performance (ROP improvement) and quality wellbore for liner run afterwards in the Middle Cretaceous formation.

Drilling challenges in the Zaap field requires the utilization of both Directional Drilling technology and MPD techniques to improve drilling performance and reduce NPT respectively. Through processes, best practices and lesson learned, this paper hope to serve as the bellwether for the combined solution to achieve technical limit drilling performance in the Zaap field, offshore Mexico.
EOR Screening and Early Production Forecasting in Heavy Oil Fields: A Machine Learning Approach
Authors: Muñoz Vélez Eduardo Andrés , Romero Consuegra Felipe , Berdugo Arias Carlos Andrés
Published: July 2020

A new mathematical model was proposed integrating the algorithms of neural networks and gradient boosting for the selection of the optimal EOR method in heavy and extra heavy oil fields as well as to predict the oil production of the field in the first five years of the project. The parameters were selected from genetic algorithms using the technique of auto-machine learning.

The model was developed with a database of 919 fields, from different public sources, and consists of three stages: 1) A dimensional reduction of the initial variables using t-SNE (t-Distributed Stochastic Neighbor Embedding), passing from 12 variables to 2 final variables. 2) An estimation of the optimal EOR method from an Artificial Neural Network. And 3) the integration of 1) and 2), serve as the input for a genetic algorithm in order to forecast the production of the first years of the field after the project started.

The obtained results show a correlation of 87% for the classification neural network, and 93% for the genetic algorithm in the test database. Therefore, an integrated workflow was also developed, which takes the generated production profile and performs cash flow analysis, leading to the calculation of key financial parameters for determining project feasibility from given reservoir, fluid, and economic conditions input by the user.

The developed model is presented as an opportunity to experience the possibilities that artificial intelligence has in the oil and gas industry, and how it can be of great help in the prediction of variables for process optimization. Employing the optimal EOR method from the beginning of field development can increase long-term profitability. In addition, the developed screening software eases decision making for operators in selecting, technically and economically, the most feasible thermal EOR method for the development of heavy and extra heavy oil fields, maximizing asset value and E&P portfolio.
Experimental Investigation on Mass Transfer Kinetics of Hydrocarbon Gas Influx for Enhanced Offshore Well Control
Authors: Ojedeji Damilola , Nielsen James , Perry Scott , Chen Yuanhang
Published: July 2020

This paper presents an experimental investigation of the time-dependent desorption of methane from non-aqueous base fluids, for a better understanding of mass transfer processes involved in riser gas events. A laboratory-scale experimental apparatus was developed and used to experimentally evaluate the rate of desorption of methane from Internal Olefin (IO) and Internal Olefin emulsions, which are commonly used as base fluids for offshore drilling in the Gulf of Mexico. The main test column of this apparatus consists of multiple sections that can be accessed separately. Methane was injected from the bottom of the test section to saturate the fluids at given starting pressures. Upon reaching complete saturation, the pressure was rapidly reduced and the methane that liberated out of solution was measured to determine the rate of degassing over time. The experimental tests were performed under various starting pressures and with different Oil/Water (O/W) ratios of Internal Olefin emulsions. Experimental results are discussed to comprehend how pressure and base fluids affect the desorption processes in the test column. This study discloses how methane evolves out of base drilling fluids commonly used in offshore drilling. The results can be used to improve well control simulators and help to better determine riser gas equilibrium through enhanced modeling of time-dependent degassing.
Review of Current Status of Reserves Estimation Standardization in Latin America; A Third-Party Auditor Opinion
Authors: Espinoza Rolmys , Siciliano Yoanna , Escobar Esther , Romero Maria
Published: July 2020

In recent years, internationally recognized reserves estimation and reporting standards have been adopted in Latin America by government regulators and national operators. This paper describes the current regional situation from the perspective of a third-party auditor.

Potential investors need a clear understanding of how a country and its oil and gas sector companies evaluate their petroleum resources to optimize asset portfolio management and value. To this end, the current reserves estimation and reporting practices of several major Latin American oil and gas producers were investigated to identify the level of standardization by country. This review includes the application of the main resource classification standards used by the government regulators in the region and how they have influenced the estimation of reserves in recent years. The role of the third-party reserve auditor is discussed, including the importance of intangible influences which must be taken into consideration. The process of reserve estimation is complex and involves multiple skills, knowledge and judgement while applying a variety of international reserves standards to provide a reliable independent audit for operators or regulators alike. Documented examples of inadequate reserves audit are presented.

The SPE PRMS is the reserve reporting standard used by most of the regulators and operators, but those companies that are listed on the USA or Canadian stock exchanges use SEC and COGEH, respectively. Annual independent reserves estimation from third-party auditors is mandatory for most of the Latin American countries reviewed, although some continue to use in-house reserves estimations. Examples are given to illustrate how some government regulators use their own internal guidelines with additional considerations for reserves estimation and reporting. The paper shows that those countries where reserves estimation and reporting have been standardized, and which are audited by third-parties, have given more confidence to the global investment community.

Standardization has been fundamental in helping to attract development funding for the oil and gas sector in Latin America, as it brings clarity to decision making based on reliable estimates of recoverable petroleum volumes. This paper provides a review of information regarding the status of standardization of reserve estimation and reporting in Latin America. Best practices are shared, and some necessary areas of improvement are proposed. Getting it right can result in improved transparency and increased international investment.
Integrated Digital Solution for Enhanced Oil Recovery Through Optimization of Injection and Production Networks
Authors: Mogollón Jose Luis , Franco Miguel , Querales Maiquel
Published: July 2020

This study objective was to design a functionally integrated digital enhanced oil recovery (ID-EOR) solution enabling pseudo-real-time optimization of injection and production networks to help improve asset performance and maximize net present value.

ID-EOR indicators for each business process (e.g., injected fluid-to-oil ratio, productivity index, and recovery factor), automation opportunities, workflow logic and characteristics, flow diagrams, and mathematical models were identified and mapped for injection and production processes. A swim lane- based approach was selected to structure the various automated workflows. The swim lanes are (i) injector well short-term diagnoses and network regular update, (ii) reservoir model, (iii) production network regular update, and production well short-term diagnoses. A set of engineered workflows would perform a series of tasks delivering outputs that ultimately provide the users with diagnosis and/or recommendations. Workflows can be run individually or in tandem, and goals can be met by making decisions at the well, network, and reservoir levels, or with all the levels integrated.

One of the challenges to further advance ID-EOR solutions is the lack of quantitative data. Based on proprietary information, literature research, and stochastic analysis, 20 to 60% cost or resource reduction in fuel, power, maintenance and operations can be realized using digital workflows and automation. Stochastic analysis pointed to positive P50 present value of hundreds of millions of dollars, and negligible risk of unprofitability. In other words, the results obtained provided realistic expectations of benefits from digitalization and automation in the short, medium, and long terms.

ID-EOR solutions offer a path to increased profitability while reducing economic and operational project risks. The sensors, data transmission, processing, and storage technologies necessary are available, and most methods have been tested individually and/or partially integrated. The next step is a full integration trial in the field.

While almost fully integrated digital solutions have been previously implemented for waterflooding, this new concept design introduces a novel integrated digital solution to gather and diagnose data and make timely operational and engineering decisions to meet planned injection and production targets in EOR projects, and maximize the economic benefits.
Case Study: Implementing Continuous Circulation and Managed Pressure Drilling Techniques to Drill in the Challenging Perla Gas Field in Offshore Venezuela
Authors: Arellano Juan Jose , Pozzo Huerta Javier Enrique , Johnson Rachel , Poletzky Isabel , Kumar Bikram
Published: July 2020

The Perla Gas Field is a naturally-fractured carbonate formation in offshore Venezuela that often requires advanced technology to complete and optimize drilling operations while also minimizing nonproductive time (NPT). To overcome the challenges and reduce NPT demonstrated on a well drilled in 2010 in the Perla field, continuous circulation and managed pressure drilling (MPD) technologies were used to drill two subsequent wells in 2016.

Drilling in the Perla field is a challenge because of its narrow pore pressure and fracture pressure window, which increases the potential for issues such as lost circulation, kicks, wellbore instability, and connection gas. To overcome challenges encountered in 2010 while also decreasing NPT, a combination of MPD and continuous circulation technologies were selected to drill the wells. To navigate the tight drilling windows, MPD was selected for this campaign, with continuous circulation implemented to supplement the MPD process by removing any transient time or pump cycling effects during connections.

Continuous circulation allows the operator to circulate fluid downhole during the drill pipe connections. The system includes a manifold connected into the standpipe that performs the diversion, and subs installed onto the top of each stand of drill pipe, creating two independent flow paths for drilling an open hole section. MPD creates a closed loop system and allows the operator to safely add or remove backpressure at the surface in order to control bottom hole pressure (BHP).

In Perla, a well was drilled in 2010 with significant losses as a result of an unexpectedly narrow drilling window of 0.5 ppg equivalent mud weight between pore and fracture pressures (9.8 to 10.3 ppg, respectively). In 2016, the new combined solution enabled drilling of the lateral in both wells by maintaining a constant BHP during all phases, mitigating influxes or losses, removing static mud pressure spikes (breaking gels), reducing connection gas, and improving hole cleaning. A statically underbalanced 9 ppg fluid was used while targeting a 10.2 ppg equivalent mud weight throughout the length of the 8½ in lateral on more than 150 drill pipe connections to decrease tripping time, get liner to depth, and improve the estimated time to total depth, decreasing overall risk, NPT, and cost.

In exploratory and development wells, risks increase when different than expected well conditions are encountered during drilling. This case study provides an example of the viability of combining MPD and continuous circulation, a solution which is highly applicable in offshore Latin America, including but not limited to Venezuela.