bluuebunny/crossref_metadata_2025 huggingface dataset:
Anisotropy from Deep Directional Resistivity LWD Measurements
Authors: Wendt Brett , Akindipe Tunde , Alexander Malcolm , Hupp Douglas , Bourgeois Daniel , Leveque Soazig
Published: October 2020

Deep directional resistivity LWD measurements have been shown to be sensitive to resistive transitions over a broad range of distances around the tool from tens to hundreds of feet. These detected transitional surfaces are primarily used to detect formation resistivity boundaries and assist with mapping geological profiles. The inverted formation dip and vertical resistivities are also resolved in the same search space. While the formation dip is used in conjunction with the reservoir-mapping interpretation results, the vertical resistivity, specifically the vertical and horizontal resistivity ratio, or anisotropy, has not received the same amount of attention.

Resistivity anisotropy is useful when calculating the formation resistivity in layered formations, as conventional resistivity tools measure the resistivity in one direction, which is perpendicular to the tool axis. With conventional induction and propagation resistivity tools, the electrical current preferentially transits the conductive lithologies, resulting in an apparent resistivity measurement that does not represent the true sand resistivity. The petrophysical evaluation often results in an apparent high-water saturation, which can result in incorrect decisions to abandon a prospect.

To understand two new fields located onshore Alaska, three horizontal appraisal wells were drilled with deep directional resistivity LWD technology. While the primary goal was to characterize the lateral resistivity profile and bed boundaries away from the wellbore, accurate water saturation calculations along the horizontal section are critical for making appropriate development decisions.

A review on how and why deep directional resistivity LWD technology is sensitive to anisotropy and how anisotropy is derived from parametric inversions is presented with a comparison between deep directional resistivity LWD measurements, 3D petrophysical modeling of propagation, and offset well triaxial induction anisotropy measurements. Integrating 3D petrophysical processing and triaxial-induction technology into deep directional resistivity LWD measurements add to the strength of the anisotropy output. The comparison shows that deep directional resistivity LWD measurements can be used independently to give accurate anisotropy results.

The result of this process provides a corrected resistivity measurement of vertical and horizontal resistivity in anisotropic formations for petrophysical models. Use of the corrected resistivity as a true resistivity (Rt) input for water saturation will ultimately drive better development decisions.
A Novel Method of Non-Darcy Well Test Interpretation for Ultra-Low Permeability Reservoirs
Authors: Li Li , Liang Wei , Yan Zhenghe , Wang Kun , Luo Qiyuan , Li Qinquan , Xiong Qi , Chen Xiao
Published: October 2020

Conventional well test interpretation methods do not consider the special seepage characteristics of ultra-low permeability reservoirs, resulting in pessimistic well test interpretation of permeability and undervalued skin effect caused by reservoir damage. This study has established a well test interpretation model considering stress sensitivity/start-up pressure gradient and mud invasion for ultra-low permeability oil fields. The well test interpretation results have been applied to guide the formulation of overall development plan in South China Sea.

The mathematical expressions of stress sensitivity and start-up pressure gradient were obtained by using real core experiments. The quantitative characterization of mud invasion time-varying skin was realized by using numerical core experiments. Based on the new characterization method, a seepage model considering three factors above was established. The real space solution was obtained by using Laplace transform and Stehfest numerical inversion methods, a series of new standard plates were drawn, and corresponding ultra-low permeability well test interpretation software was compiled.

Based on the numerical simulator considering stress sensitivity and starting pressure gradient, an average permeability of 5md mechanism model with 0.6m near well bore damage zone was built. A well test design was then implemented to get pressure buildup data for well test interpretation. The authors compared the conventional well test methods and improved ultra-low permeability well testing method with same data base. A conclusion can be drawn that both permeability and skin have been seriously underestimated by using conventional well test methods. However, the permeability and additional pressure drop interpreted by improved ultra-low permeability well testing method is coincidence with mechanism model, which proved the validity of our new methods. Thus the well test permeability obtained by new methods can be used for productivity evaluation of low permeability oil field development and the skin factor can be used to guide mud system preparation and formation protection process design.

The influence of stress sensitivity/start-up pressure gradient and mud invasion damage of ultra-low permeability reservoirs have been pioneering discovered, and well test interpretation plates and software considering three factors above have been implemented for the first time in the industry.
Continuous Steam Distribution Optimization using Pattern Recognition on High Frequency Data Streams
Authors: Popa Andrei , Guerra Tomas
Published: October 2020

In this paper, an assessment of a streaming dataset from all active steam injectors in a mature steamflood field is carried out to understand and identify data trends and patterns which indicate if a steam injector is out-of-design. The dataset utilized in this study comprises real-time data and data in motion available thanks to the newly instrumented asset. However, this high-frequency data, while available, was never analyzed before this study. This work showcases the first study of this kind that utilized high-frequency streaming data from steam injectors. As an exploratory study, it revealed powerful insights and patterns which explained not yet understood behaviors. The methodology employed involved management and analysis of large volumes of data and consideration of the steam distribution system network. The study revealed the root causes of out-of-design and questionable steam quality values, which led to a comprehensive report describing the events, recommendations, and remedial actions for 33 out of 111 active injectors. The business driver for this project relies on solving cases in which the real steam quality is unknown, or the injector is out-of-design, which affects the steam-flood delivery and, consequently, the oil production performance. The novelty of this study relies on the capability of identifying undesired events at very early stages. In similar oilfields under steam-flood operations, steam injectors performance is tested and analyzed every three to six months. Many undesirable events may occur and are ignored in the time window between tests. The study not only led to business value impact due to addressing un-optimized injectors but also started a new program for real-time monitoring.

This research demonstrates the value of using high-frequency raw data for steam injectors diagnosis, management, and monitoring.
Modeling and Upscaling of Viscous Fingering during Unstable Drainage Displacements
Authors: Zhao Bochao , Mohanty Kishore
Published: October 2020

Viscous fingering is a common phenomenon in viscous oil waterflooding, gas flooding and carbon sequestration processes. Wettability has been shown to have a significant effect on viscous fingering. The objective of this research is to model viscous fingering during drainage displacements, i.e., a non-wetting phase displacing a viscous wetting phase. We modified a previously proposed effective-fingering model for imbibition processes. Laboratory unstable coreflood experiments were history matched. Power-law correlations were developed between history matched model parameters and physical parameters such as the velocity and viscosity ratio. Fine-grid intermediate scale simulations were conducted with the effective-fingering model for domains with different degrees of heterogeneity. Coarse-grid simulations were run to determine the shape factor (one of the effective-fingering model parameters) needed to match the result of fine-grid simulations. The shape factor is a function of the correlation length, Dykstra-Parsons coefficient and viscosity ratio. This correlation can be used to upscale the interaction between viscous fingering and channeling in large scale simulations.
Study of Oil Recovery Mechanisms in Complex Natural Fracture Systems using Embedded Discrete Fracture Models
Authors: Vo Hai , Mallison Brad , Kamath Jairam , Hui Robin , Dufour Gaelle
Published: October 2020

Accurate evaluation of recovery mechanisms in fractured reservoirs is challenging due to the large permeability contrast at the matrix-fracture interface. Dual Porosity-Dual Permeability (DPDK) models are typically used in field-scale simulations but can be biased by their use of idealized fracture networks and matrix-fracture interactions. Unstructured Discrete Fracture Models (USDFMs) are able to capture the complex physics accurately but can be computationally demanding. Embedded Discrete Fracture Models (EDFMs) integrate discrete fracture networks with a structured matrix grid and are the focus of this study.

Our study considers dense and sparse fracture networks extracted from a field-scale fracture carbonate reservoir model. EDFMs are constructed for different matrix grid resolutions, and simulations are performed to evaluate gravity drainage, spontaneous imbibition, viscous displacement. In each case, EDFM results are compared with highly refined USDFM reference solutions and equivalent DPDK simulations.

We improve the EDFM single phase matrix-fracture transfer function to account for pseudo-steady state and fracture interactions. In the cases of gravity drainage, EDFM simulations converge to the fine scale reference solutions with matrix grid refinement. For the coarser grids, the new matrix fracture function gives much better results than the ones reported in the literature. For spontaneous imbibition, both EDFM and USDFM overpredict the rate of spontaneous imbibition with coarse matrix grids, but the overestimation is less severe than with DPDK. In viscous displacements, EDFM overestimates recovery with coarse grids and displacement efficiency diminishes with refinement. DPDK underpredicts recovery from viscous displacement at all resolutions.
Laboratory-Scale CO2 Huff ‘n Puff EOR using Single Phase Solutions of CO2 and CO2 Soluble, Nonionic, Wettability Altering Additives
Authors: Haeri Foad , Burrows Lauren , Lemaire Peter , Alenzi Adel , Shah Parth , Tapriyal Deepak , Enick Robert , Crandall Dustin , Goodman Angela
Published: October 2020

This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniques for unconventional liquid reservoirs (ULRs) can be increased through wettability alteration by adding a dilute non-ionic surfactant to CO2. The use of surfactants to increase the water-wetness of rock surfaces has previously been shown to improve oil recovery during water-based hydraulic fracturing and waterbased EOR in ULRs. In this study, nonionic surfactants are dissolved in CO2 to attain analogous significant shifts in wettability toward CO2-philic and oil-phobic. This could provide another EOR mechanism for the CO2-based recovery of oil from unconventional formations.

The solubility of a nonionic, water-soluble, surfactant (Indorama SURFONIC® TDA-9, an ethoxylated alcohol with a branched tridecyl, oil-philic tail and nine ethylene oxide groups in the hydrophilic head group) in CO2 has been measured between 25 – 100 °C. This surfactant exhibits a solubility of roughly 1 wt% at pressures of 2000 – 5000 psia, with lower pressures required for lower temperatures.

Eagle Ford outcrop samples were first aged in dead Eagle Ford crude oil at high temperature to attain oilwet characteristics. The oil wetness of shale samples was verified by measuring contact angles of water droplets in air. Then the samples were immersed in CO2 or CO2-surfactant solution for 16 h at 4000 psi and 80 °C. Contact angle measurements were then performed to identify shifts in wettability. No substantial change in wettability were observed for samples exposed to CO2, however the samples exposed to CO2-surfactant solution revealed a significant shift toward water-wet.

Two CO2 huff ‘n puff experiments were then conducted for small, oil-saturated shale cores at 80 °C and 4000 psi. Faster oil recovery (i.e. more oil recovery in the first cycle) and cumulative oil recovery of 73% (after 7 huff and puff cycles) were achieved for the core immersed in CO2-surfactant solution (0.7 wt% surfactant) compared to 78% recovery for the core immersed in pure CO2.

Continuing tests will examine the effects of rock type, oil properties, temperature, pressure, surfactant type (oil-soluble vs. water-soluble ethoxylated alcohols), surfactant concentration, and the presence of brine. CO2-soluble propoxylated alcohols will also be assessed because the polypropylene oxide oligomer is more CO2-philic than the conventional polyethylene oxide oligomer.
Learning Cycle-Based Project Management and Its Application
Authors: Zhong Allan , Dockweiler David
Published: October 2020

As downhole environments becomes harsher, especially for high-pressure/high-temperature (HPHT) conditions, product developments based on empirical knowledge and learning from trial-and-error testing has increasingly become inadequate, leading to long project delays, cost overruns, and information silos. A different development paradigm, which is first engineering principle based, engineering simulation aided, and materials science coupled, has emerged. Within this paradigm, knowledge-generation centric projects were initiated for specific product families. These projects have high degrees of uncertainty and are thus iterative in nature. Project management per gate-based product life cycle management, which is typically applied in the oil and gas industry, is not suitable for this type of project. A lean product development-based, event-driven project management methodology, featuring iterative learning cycles and information sharing, is tailored for execution of these projects.

Our approach for management of knowledge centric projects is based on lean product development. It consists of four main components: proactive learning cycles, cloud-based visual management, visible knowledge, and integration events. In our pilot projects, proactive learning cycles involve three interrelated knowledge domains: mechanical design, engineering mechanics, and materials science. The starting points, end goal, and number of learning cycles are determined, but not the specific goals of intermediate learning cycles, which are subject to the findings of previous learning cycles. The findings of learning cycles yield visible or reusable knowledge that can be effectively shared, including causal diagrams, limit curves, boundaries in higher-dimension design space, etc. A cloud-based visual management process is established for participating global multidiscipline teams for a virtual weekly or biweekly "standup" project meeting. Integration events define convergences between disciplines, teams, and facilitate workflow.

The impact of our project management approach is highlighted through a pilot project on sealing system design fundamentals. Cloud-based visual management enabled close collaboration between global teams and disciplines. Integration events helped to heighten urgency, prioritize issues and tasks, change course based on the previous learning cycle, and make fast technical and program decisions.
Application of Augmented Intelligence and Edge Analytics In Upstream Production Operations: An Innovative Approach for Optimizing Artificial Lift Systems Performance
Authors: Saghir Fahd , Gilabert Helenio , Mancuso Bernardo Martin
Published: October 2020

With the advent of robust and powerful IIoT Edge Devices, it is now possible to deploy Machine Learning models at the boundaries of a production network, i.e. using Smart Nodes directly at the wellhead that runs analytics in near real-time. These Smart Nodes, when paired with Augmented Intelligence capabilities, allow subject matter experts to interact with Machine Learning models and help improve their accuracy over time. This, in turn, helps increase confidence in data-based results and enables operators to make informed decisions.

This paper will define and discuss an end-to-end architecture on how Augmented Intelligence, in tandem with Edge Analytics, can be implemented in the upstream production environment. Results, methodologies and lessons learnt from an Edge Analytics solution deployed on Rod Pump wells will be discussed in this paper.
Effects of Constant Pressure Boundary on Multiphase Flow Behavior in Horizontal Wells
Authors: Uzunoglu Harun , Fan Yilin , Pereyra Eduardo , Sarica Cem
Published: October 2020

Multiphase flow behavior in a wellbore is inherently coupled with a reservoir, which is controlled by pressure boundaries. Most of the previous experimental studies in the laboratory have been performed at constant liquid and gas mass flow rates boundary conditions. This study experimentally compares the gas-liquid flow behaviors between constant pressure and constant mass flow rates boundary conditions in a toe-down horizontal well and investigates the effect of constant pressure boundary on the system stability.

The experiments were conducted in a large-scale experimental facility to study the flow behavior in a toe-down horizontal well. They were performed at two different permeabilities for a constant pressure boundary (CPB) condition. Results were compared against experiments with constant mass boundary (CMB) conditions from different aspects, including outflow performance relationship (OPR), liquid holdup, and dynamic analysis. The experimental study on system stability was analyzed for three different operating conditions, namely, constant flow rate, constant gas liquid ratio (GLR), and constant liquid permeability. Similar tests were also studied using a numerical simulator.

The results show that the time-averaged OPR and liquid holdup from constant mass and constant pressure boundary conditions match well. However, the amplitude of pressure and flow rate fluctuations are different, which causes the instabilities on the left side of the minimum of the OPR for high gas permeability reservoir at CPB conditions, where production persists for the CMB. The amplitude of pressure and gas rate fluctuation depends on reservoir permeability. It is found that the multiphase flow behavior in the wellbore for a constant mass boundary is closer to that for low permeability reservoirs, which commonly occur in shale plays. The total liquid inventory decreases as superficial gas velocity increases, and the fluctuations in superficial gas velocity have no evident impact on its behavior. Both experiments and numerical simulations show that system instability also depends on reservoir permeability. Stable production still exists on the left of the minimum OPR if the permeability is sufficiently low.
Field Trial of Methane Emission Quantification Technologies
Authors: Allen David , Stokes Shannon , Tullos Erin , Smith Brendan , Herndon Scott , Dewitt Langley , Flowers Bradley
Published: October 2020

Governments in the U.S, Canada, Europe and other countries have promulgated methane mitigation regulations, and many companies have undertaken voluntary programs beyond regulatory requirements. As programs expand, emerging technology developers have responded with the development of multiple monitoring, detection and quantification systems for methane emissions. Methane detection and quantification systems operate at multiple spatial and temporal scales and when these methods are compared against each other and against inventories of methane emissions, analyses must carefully match spatial and temporal scales. This field trial compares multiple methane detection and quantification methods and compares the measurements to engineering estimates of emissions. Engineering estimates of the detailed temporal patterns of methane emissions at oil and gas production sites reveals the challenges of comparing measurements of individual sources that are not exactly synchronized. Because some detection and quantification methods can interfere with one another, most inter-comparisons are based on asynchronous measurements and approaches for inter-comparing ensembles of measuements are suggested.
Evaluating Perforation Erosion and its Effect on Limited Entry by Distributed Acoustic Sensor DAS Monitoring
Authors: Pakhotina Julia , Zhu Ding , Hill A. Daniel
Published: October 2020

Limited entry is used in multistage fracturing to attempt to distribute fracture fluid among multiple perforation clusters evenly. As the slurry is pumped through perforations, the perforation holes can be eroded because of abrasion by the proppant, and therefore become enlarged, resulting in less effective limited entry and lower efficiency of the fracture treatment. Distributed Acoustic Sensing (DAS) is a method used for monitoring of fluid flow during hydraulic fracturing. By evaluating the changing DAS responses at perforation cluster locations during fracture pumping, DAS can be used to evaluate perforation erosion. DAS is a measurement of acoustic energy induced by fluid movement with fiber optic sensing cables. A raw acoustic signal recorded by the interrogator is transformed into an energy response (Frequency Band Energy), which is used for further interpretation of fluid volume distribution among perforated clusters on each stage of the fracturing treatment.

Based on previous laboratory experiments and computational simulations, there is a correlation between the Frequency Band Energy and fluid flow rate. As the flow rate is a function of fluid velocity and perforation area (diameter of perforation), the same flow rate could be attained with a combination of different velocities and areas, leading to a non-unique solution when interpreting DAS measurements. We transferred the correlation into the relationship between velocity and Frequency Band Energy, using the perforation area as an additional parameter. It enforces avoiding non-unique solutions in the interpretation process.

Perforation diameter is a function of erosion rate, which depends on the proppant concentration and velocity of fluid passing through the perforation. In order to connect correlation parameters with the diameter of perforations, computational simulations of fluid injection were conducted with different perforations geometries. Based on these simulations, a function that connects the area of perforation with a correlation parameter was obtained. It allows us to include the diameter of perforation in the analytical equation explicitly.

The application of the enhanced correlation in the interpretation process leads to increased accuracy of the fluid distribution calculation. For each time step, the velocity of the fluid, the mass of proppant, and the diameter of the perforations are computed, allowing the calculation of the flow rate in each perforation cluster. Perforation erosion is included in the model. Examples using field data are presented in the paper.
Distributed Sensing and Real Time Visualization of Gas Kick Dynamics in a Full-Scale Wellbore
Authors: Williams W. C. , Taylor C. E. , Almeida M. A. , Sharma J. , Waltrich P. J. , Chen Y. , Feo G. , Kunju M. , Santos O.L.A. , Ogunsanwo O. A. , Paulk D. , Kortukov D.
Published: October 2020

Early detection and quantification of gas kicks during drilling and completions is essential to proper well control and in the prevention of blowouts. The utilization of distributed sensing techniques, acoustic (DAS) and temperature (DTS), enables real-time elucidation of these multiphase flow events. Identifying and validating event signatures (fingerprinting) in these sensing technologies is crucial to informing operators of how to interpret these data streams. Performing full-scale analysis allows these events to be properly characterized, given the complexities in the fluid mechanics and gas dynamics.

This project utilizes a 9-5/8 inch and 5200 foot deep wellbore at the LSU PERTT Laboratory retrofit with distributed fiber optics (DAS and DTS) and 4 permanent pressure-temperature gauges to sense and visualize gas kick dynamics downhole in real time. Several experiments were performed involving the injection of nitrogen kicks through a chemical injection line and also by bullheading down 2-7/8 inch tubing in both stagnant and circulating water. Variations in flow rate, kick size, and backpressure are investigated including gas migration during shut-in. DTS and DAS data are collected downhole, along with gauge pressure and temperature at four depths along the wellbore. Data is consolidated with the rig recorded surface data to create a complete picture of the experiments.

Several observations are possible with this new methodology. First, the gas kick is immediately visible (audible) entering the wellbore by the sensors and the gas front was traceable in real time as it rose to the surface, allowing for detection of a kick, improved estimation of kick size, and easy calculation of rise velocity. Second, the distribution of gas axially in the wellbore was visible and provided insights into the duration of the event. Third, the compressibility dynamics can be visualized with the DAS thus elucidating details of bubble and slugging sizes and dynamics and when discrete gas has completely circulated out of the wellbore. The frequency ban filtering of the data further augments the fidelity of gas bubble sizes and dynamics. These initial results provide a proof of concept for using downhole sensing for real time riser gas dynamic detection and characterization.
Production Optimisation Using a 24/7 Distributed Fibre Optic DFO Sensing Based Multiphase Inflow Profiling Capability
Authors: Sadigov Teymur , Ramsay James , Cerrahoglu Cagri , Salt Michael , Thiruvenkatanathan Pradyumna
Published: October 2020

This paper shares the results from the first successful deployment of a real-time, multiphase inflow profiling technology applied to BP operated Clair Ridge asset. Uncertainty around distribution and the dynamic behaviour of the fractured reservoir required the deployment of Distributed Fibre Optic Sensing (DFOS) capabilities as part of the well completions across a selection of the well stock, to enable in-depth real-time flow surveillance and maximize recovery from the field. Unlike conventional wireline conveyed sensors and logs that provide static measurements of flow conditions, the DFO data will be used to provide a more comprehensive, dynamic inflow distribution across multizone completion uniquely including flow in the annular space behind blank sections.

This paper summarizes key findings from the first deployment of a new real-time technology solution that employs novel signal processing techniques using the DFO data as key sensor inputs to detect relative inflow rates of different fluid types along the wellbore during production. The solution presents inflow logs for each fluid phase in near real-time through proprietary streaming analytics capabilities embedded in a cloud-based software solution. This facilitates 24×7, real-time flow surveillance across wells equipped with fibre in the field. This paper also presents early results from the use of the technology on the first platform drilled production well and discusses how these real-time insights have been effectively applied to provide significant business value, including but not limited to new well start-up optimization, well management and zonal fluid inflow allocation. The paper also detail the use of the technology for water inflow detection and quantification and discusses the implementation of drawdown optimization strategies based on the insight to control water inflow that have already resulted in significant production benefits.
Development of a Realtime Gas Monitoring System Architecture for Manned and Unmanned Oil and Gas Processing Facilities
Authors: Idachaba Francis
Published: October 2020

This paper presents the development of a real-time gas monitoring system with alerts transmitted to the office domain, and the team leads whenever the gases are detected. The system monitors the presence of the hazardous H2S gas. It sends signals to the control room in the manned plants so that operators can take the necessary precautions when stepping into these locations. It also sends alerts to the office domains when the permit to work is being prepared for any facility. It provides a continuous real-time update of the gas present in the location to a cloud-based platform. This is beneficial as it will enable plant operators to take the necessary precautions to both protect themselves and also protect the facilities if the gas discharge spreads across the plant's zone classifications
Tracer Evaluations for Seawater Fraction Monitoring During Offshore Seawater Flooding
Authors: Wang Yanqing , Li Xiang , Lu Jun
Published: October 2020

Seawater breakthrough percentage monitoring is critical for offshore oil reservoirs as seawater fraction is an important parameter for estimating the severity of many flow assurance issues that caused by seawater injection and further developing effective strategies to mitigate the impact of those issues on production. The validation of using natural ions as tracer to calculate seawater fraction was investigated systematically by studying the natural chemical composition evolution in porous media using coreflood test.Results indicate that chloride, bromide and sodium can be regarded as conservative tracers to calculate seawater fraction as long as there is considerable concentration difference between seawater and formation water.Behavior of calcium shows acceptable error in seawater fraction calculation especially at high temperature and low clay content reservoirs. Application of barium and sulfate reaction model in coreflood test works not as well as in bottle test because of not taking account of fluid flow in porous media.Magnesium,potassium, and boron have significant interactions with core matrix, and thus cannot be used as tracers directly to calculate seawater fraction. Behavior of all ions gives a guideline on selecting suitable ions as tracer. Besides, ions evolution is helpful in understanding the mechanisms of low salinity waterflooding.
Experimental Performance of Steam-Based Hybrid Technologies to Improve Energy Efficiency in a Colombian Heavy Oil Reservoir
Authors: Perez Romel , Garcia Hugo , Manrique Eduardo , Rodriguez Hector , Mehta Sudarshan , Moore Robert Gordon , Ursenbach Matthew , Sequera-Dalton Belenitza , Gutierrez Dubert
Published: October 2020

Due to the large amount of heavy oil reserves, thermal recovery projects have been developed in Colombia in the last decade. Several fields under Cyclic Steam Stimulation (CSS), and Steam Flooding (SF) plans are currently underway at field scale. In the country there are also significant reserves of heavy oil which are still under cold production which represent an important opportunity to implement novel technologies that improve energy efficiency. Such technologies should be implemented based on the maturity of the current recovery process and reservoir characteristics. Implementation of steam-based hybrid technologies are under evaluation in Ecopetrol as a strategy to increase both heavy oil recovery and energy efficiency.

This work is focused on the design, execution, and results of two physical simulation experiments developed to study the behavior of the Teca Cocorná core and fluids with a combination of steam-based hybrid injection technology. Both tests were performed under similar conditions of temperature and pressure to assess the effect of a hybrid injection process on the residual oil saturation, produced hydrogen sulfide (H2S) and changes in produced fluids. The experimental methodology is described in detail for both experiments as well as relevant test results which constitute important parameters for reservoir simulation forecasts.

The first hybrid test was a combination of steam flood and solvent injection (naphtha) which consisted of the injection of 0.38 pore volumes (PV) of cold water equivalent (CWE) superheated steam at 271°C, followed by the injection of 0.05 PV of naphtha solvent (CWE), and finally by the injection of 1.0 PV of superheated steam (CWE). The second hybrid test combined steam flood with injection of flue gas consisting of 15 percent carbon dioxide (CO2) and 85 percent nitrogen (N2). The injection scheme for this test was similar to the first test and consisted of the injection of 0.40 PV of superheated steam at a temperature of 271°C (CWE), followed by 0.30 PV of flue gas (CWE) and finally by 0.71 PV of superheated steam (CWE).

This study shows that the Teca Cocorná oil-core system, as tested, responded positively in the laboratory to hybrid steam methods in terms of production and energy efficiency. A detailed comparison including temperature front, steam-oil-ratio, produced fluids and residual saturations is presented. In addition, the energy consumption is estimated. These results provide valuable information required for numerical and economic evaluations of steam-based processes prior to field tests.
Effects of Variable Perforation Configurations on Proppant Trasport and Distribution in Slickwater Fluids
Authors: Alajmei Shabeeb , Miskimins Jennifer
Published: October 2020

This paper investigates the effect of variable perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. The results are compared to other previously published data (Ahmad and Miskimins, 2019) using different proppant sizes and densities. A 30-foot horizontal laboratory apparatus with three perforation clusters is used to simulate a multistage horizontal well. Low viscosity fresh water is used as the carrier fluid to transport the proppant. This research incorporates the influence of testing various injection rates and proppant concentrations on proppant transport of 100-mesh brown sand. Different perforation configurations are used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations. A 200-gallon tank is used to mix the proppant before injecting the slurry mixture using a slurry pump. The apparatus also incorporates a variable frequency drive, a flow meter and pressure transducers. Sieve analysis is then conducted to identify the proppant distribution exiting from each cluster at different perforation configurations.

It commonly assumed that the injected proppant is distributed evenly across the perforation clusters and that the distribution of fluid and proppant is identical. However, this research shows that this is not always the case. The results show uneven fluid and proppant distributions between clusters when altering the perforation configurations, injection rates, and proppant concentrations. Sieve analysis also shows different size distribution of the settled and exited sand through different clusters and individual perforations. Such information is beneficial to understanding transport in horizontal, multi-stage completions and how such impacts the overall treatment efficiency.
Application of United Nations Framework Classification for Hydrocarbon Reserves and Resources Volumes for a Mature Oil Reservoir in Kuwait
Authors: Al-Ghnemi Mohammad , Al-Sane Amal , Dhote Prashant , Bora Anup , Al-Bahar Mohammad , Purewal Satiner , Walker Jacob , Dharanidharan Balagopal , Hornbrook John
Published: October 2020

United Nations Framework Classification (UNFC) for Energy and Mineral Resources is a unique instrument for harmonizing industry business processes, efficient capital allocation with policy framework and government oversights. The core competency of UNFC is focusing on objectives of Sustainable Development Goals (SDGs) while managing the natural resources required for the present and future needs of society.

The company manages the upstream oil and gas sector, with significant expertise in managing exploration and production of hydrocarbon resources in diverse geological, engineering, and commercial environment. Present day activities span a large spectrum from pure reconnaissance for resources to producing from very mature fields with increased geologic, engineering, and commercial complexities. KOC uses Resource and Reserves Management System (KOC-RMS) for accounting and reporting of reserves and resources, which is based on principles of Petroleum Resources Management System (PRMS). PRMS [AZ1]is a framework for classifying and categorizing estimates of petroleum reserves and resources and it is used by most of the upstream oil and gas companies worldwide.

UNFC provides common language for classification and reporting of solid mineral and petroleum resources, with main emphasis on socio-economic viability, technical feasibility, and maturity of a project. There have been continued efforts for bridging the gap between PRMS and UNFC systems, including the mapping of PRMS guideline updated in 2007 being to the UNFC system updated in 2009. This effort produced clearly marked similarities between the two systems and there is an effort currently underway to map the PRMS guidelines updated in in 2018 to the recently updated UNFC. This integration will help in comparing renewable energy resources with non-renewable energy.

The objective of the present case study is to assess the applicability of UNFC for Energy and Mineral Resources management system for a mature oil reservoir. The results of this UNFC case study identified producing, justified for development, and contingent projects with limited social or environment impediments to development.

The novelty of this study is the first known application of the UNFC approach to a petroleum reservoir of the Middle East and shows applicability to similar oil fields around the world. This approach can assist in the identification of all technical and non-technical aspects, such as social and environmental issues associated with development, and may be used to reflect the hydrocarbon resource maturation and reserves progression framework of a reservoir.
A Field Pilot of Huff-n-Puff Gas Injection for Enhanced Oil Recovery in Permian Basin
Authors: Ganjdanesh Reza , Eltahan Esmail , Sepehrnoori Kamy , Drozd Hunter , Ambrose Raymond
Published: October 2020

Unconventional oil wells exhibit rapid decline in oil production rate and low ultimate oil recovery, even though the lateral drilling and completion technology have advanced drastically in the past decade. The petroleum industry has been seeking to develop economic enhanced oil recovery methods to improve the overall recovery factor. The gas huff-n-puff process has been performed and shown the potential of improving the recovery factor from tight oil reservoirs. The objective of the study was to investigate the performance of huff-n-puff EOR in Midland Basin. The studied section of the field contains 2 horizontal producers. The wells produced on primary production for 3 years. The sector was selected as a candidate for performing gas huff-n-puff to enhance the oil recovery factor. Recently, this huff-n-puff EOR project has been performing in the studied volatile oil field in the Permian Basin.

In this study, compositional reservoir simulation was used to predict the performance of enhanced oil recovery. A sector model was built for the area selected as the prospective candidate for gas injection. An Embedded Discrete Fracture Model (EDFM) was used for modeling the fractures and stimulated reservoir volume (SRV). A Peng-Robinson equation-of-state model was prepared based on the early produced samples from the wells. A thorough phase behavior analysis was conducted to understand the miscibility of the injected field gas and the in-situ fluid. A Bayesian Assisted History Matching (AHM) algorithm with a neural-network-proxy sampler was applied to quantify uncertainty and find the best model matches for the pair of wells in the Wolfcamp B and C formations of Midland Basin.

From 1400 total simulation runs, the AHM algorithm generated 100 solutions that satisfy predefined selection criteria. Even though the primary production were the same for the two wells, the forecasts were dissimilar. It is discussed that the dissimilarity in huff-n-puff performance between two wells is caused by interwell communications. The well interference through fracture hits play an important role in the studied reservoir. The field data show the pressure communication between the two wells. Also, the injected gas was observed in the offset wells about one month after the start of injection. Several long fractures were added to the reservoir model to capture the characteristics of fracture interference. The prospects of EOR were proven decent for the wells of interest. We reported 29% and 82% incremental recovery for the P50 predictions of wells BH and CH, respectively. The results of field operation have been in agreement with the simulation forecasts after two cycles of gas injection and production.
Changing the Way: Integrated Artificial Lift Strategy Overcomes Waterflooding and Mature Field Challenges Increasing 58% of Total Oil Production
Authors: Gallegos Johanna , Enriquez Luis Carlos , Reyes Carlos , Correal Alvaro , Villalobos Jorge , Fun Sang Byron , Torres Richard , Villa Carlos , Bonilla Christian
Published: October 2020

The artificial lift strategy described in this document addresses new challenges resulting from an accelerated implementation of secondary recovery in a mature oilfield. New technologies and best operational practices were implemented to handle challenges such as high pressure and water flowrates in source water wells, extended-life ESP to enable production across a wide production range to cover the response of the waterflooding, increasing solids production, heavy oil, and installations of ESP in deep and tortuous wells.

This technical and strategic approach covers artificial lift designs for water injection in well-to-well configurations located in the same platform. This approach reduces the requirements for surface facilities. For oil producers, ESP robustness must be enhanced to handle wide range and aggressive reservoir conditions. Slim ESP applications to allow taking full advantage of waterflooding. A novel concept applied to recirculate hot water making possible produce deep heavy oil reservoirs and updated workflows and equipment for remote surveillance of the ESP systems and reservoir.

The integrated approach of the strategy allows its application in either brownfield or greenfield. Putting such strategy into action resulted in an incremental production of 30,000 bopd from waterflooding using more than 60 ESP installations of wide range and reducing workover interventions representing savings of 4.5 MMUSD. Additionally, direct well-to-well injection in 22 water producer wells allowed direct injection of 100,000 bwpd at roughly 2,000 psi at the well head and savings of 14 MMUSD in surface facilities.
Hole Cleaning Efficiency of Sweeping Pills in Horizontal Wells - Facts or Philosophy?
Authors: Czuprat Oliver , Faugstad Anne Marte , Byrski Piotr , Schulze Kai
Published: October 2020

More than 35 million m3 of oil have been produced from the Mittelplate oilfield. Poor hole cleaning has been identified as a root cause for drilling problems in the horizontal sections of its ERD wells. Enhancing cutting removal in vertical wells, high-viscous pills are typically considered. However, literature is providing contradicting guidance of using sweep pills in deviated/horizontal wells. Thus, the purpose of this study is to provide an overview about the theoretical background on hole cleaning and to experimentally identify the best sweep pill for ERD wells.

An apparatus has been designed as a closed flow-loop system consisting of coaxial pipes forming a horizontal well with a drill-string inside, two mud tanks, and a mud pump. Two pressure sensors are placed along the horizontal section, providing complementary information about the moving sweeping pill. Different pills (high-viscosity, medium-viscosity, high-density and a high-viscosity/high-density combination pill) have been circulated and the recovered model cutting material from one cycle of circulation has been re-weighted.

To the best of our knowledge, it is the first time that such a fully scaled-down device including pressure sensors at the toe and heel of the horizontal section has been designed and used for the evaluation of sweep pills. It delivers an efficient and cost-effective method to optimize hole cleaning processes and prevent costly drilling incidents.
Hydrodynamics of Continuous Flow Plunger Lift
Authors: Sayman Ozan , Pereyra Eduardo , Sarica Cem
Published: October 2020

The distinctive characteristic of continuous flow plungers (CFP) is the ability to complete a plunger cycle without a pressure buildup period. The hydrodynamics of the fall and upstroke stages of the CFP lift is vital to determine operational envelope, select plunger, and optimize gas lift. This paper presents the results of an experimental and theoretical study conducted to develop fall and upstroke models with dimensionless parameters.

The fall motion of four sleeves with different height, weight, and outer diameter, three balls made from different materials, and a bypass plunger were tested in the static facility with four different fluids. The wall effect on settling velocity was defined, and drag coefficient results for balls were validated with the literature. The liquid holdup effect on the drag coefficient was investigated by injecting gas into the static liquid column. The 40-ft long dynamic facility is utilized to investigate fall and upstroke stages of a two-piece plunger for different gas and liquid flow rates. Experiments were performed with the deviation angles up to 40 degrees.

The drag coefficients of plungers for respective Reynolds numbers, the liquid holdup correction, and the wall effect on the settling velocity were obtained. The fall model was developed with dimensionless parameters for conventional and continuous flow plungers, which can estimate primarily fall velocity and maximum flow rate to fall against. The fall model was coupled with multiphase flow simulations for sensitivity analysis, and the results showed that plungers fell slowest at the wellhead in field conditions. Furthermore, upstroke experiments demonstrated the effect of gas and liquid flow rates and outer diameter, height, and weight of the sleeve on the plunger upstroke velocity. The model predictions for the upstroke stage match with experimental results from the dynamic facility, and it is further developed to estimate upstroke velocity, liquid slug removal from the wells in field conditions. The fall and upstroke models were used together to determine the operational envelope for CFP lift and plunger assisted gas lift (PAGL) for different plunger types. The liquid unloading mechanism of the CFP lift was also discussed.

The study is unique in defining the hydrodynamics of continuous flow plunger lift and PAGL operations. The models are constructed with dimensionless parameters allowing applicability to the field conditions. The experimental results also contribute to plunger selection and design. The study provides a better understanding of when to use and how to use continuous flow plunger lift.