bluuebunny/crossref_metadata_2025 huggingface dataset:
Deep Learning and Bayesian Inversion for Planning and Interpretation of Downhole Fluid Sampling
Authors: Orta Alemán Dante , Kristensen Morten , Chugunov Nikita
Published: September 2019

Downhole fluid sampling is ubiquitous during exploration and appraisal because formation fluid properties have a strong impact on field development decisions. Efficient planning of sampling operations and interpretation of obtained data require a model-based approach. We present a framework for forward and inverse modeling of filtrate contamination cleanup during fluid sampling. The framework consists of a deep learning (DL) proxy forward model coupled with a Markov Chain Monte Carlo (MCMC) approach for the inverse model.

The DL forward model is trained using precomputed numerical simulations of immiscible filtrate cleanup over a wide range of in situ conditions. The forward model consists of a multilayer neural network with both recurrent and linear layers, where inputs are defined by a combination of reservoir and fluid properties. A model training and selection process is presented, including network depth and layer size impact assessment. The inverse framework consists of an MCMC algorithm that stochastically explores the solution space using the likelihood of the observed data computed as the mismatch between the observations and the model predictions.

The developed DL forward model achieved up to 50% increased accuracy compared with prior proxy models based on Gaussian process regression. Additionally, the new approach reduced the memory footprint by a factor of ten. The same model architecture and training process proved applicable to multiple sampling probe geometries without compromising performance. These attributes, combined with the speed of the model, enabled its use in real-time inversion applications. Furthermore, the DL forward model is amendable to incremental improvements if new training data becomes available.

Flowline measurements acquired during cleanup and sampling hold valuable information about formation and fluid properties that may be uncovered through an inversion process. Using measurements of water cut and pressure, the MCMC inverse model achieved 93% less calls to the forward model compared to conventional gradient-based optimization along with comparable quality of history matches. Moreover, by obtaining estimates of the full posterior parameter distributions, the presented model enables more robust uncertainty quantification.
Solvent Screening Study for a Post CHOPS Cyclic Solvent Injection Pilot
Authors: Anderson Mark , Badamchizadeh Amin , Kantzas Apostolos , Bryan Jon
Published: September 2019

In preparation for a field pilot of cyclic solvent injection (CSI) on two depleted cold heavy oil production with sand (CHOPS) wells, a series of oilsands coreflood experiments were conducted to evaluate the effectiveness of various commercially available solvents and make a solvent recommendation for the pilot. Oil recovery and solvent recovery were the key performance indicators used to compare CSI effectiveness of each solvent blend. The operating pressure for each test was kept relatively constant for each solvent blend tested. Tested solvents included blends of methane/propane, carbon dioxide/propane, methane/ethane, 100% ethane, and nitrogen. Sensitivities for depletion rate and blowdown pressure are also presented. Overall the 100% ethane test performed the best with the highest oil recovery and solvent recovery in the fewest cycles. Due to the lack of commercial ethane supply and the industry experience with methane/propane in Husky Edam’s CSI pilot, a methane/propane blend was recommended for the field pilot in Manatokan East near Bonnyville Alberta Canada.
Numerical Study of Injection-Induced Seismicity Using A FEM-BEM Coupling Approach
Authors: Aoki Masato , Kimura Kentaro , Iijima Yoichiro , Furui Kenji
Published: September 2019

Induced seismicity caused by underground fluid injection occurs because of pore pressure changes that lead to stress changes in the reservoir and the surrounding formations. Despite that noticeable seismic events from fluid injection is very rare, proper assessment of possible seismic events is important. The objective of this study is to develop numerical models that simulate stress changes, fault slips, and ground floor movements induced by underground fluids injection.

The numerical analysis process presented in this work consists of three steps. First, stress changes around the reservoir due to fluid injection are analyzed using a FEM-BEM (Finite Element Method - Boundary Element Method) coupled model. Secondly, the stability of faults located near the reservoir is evaluated using the displacement discontinuity method. Thirdly, elastic waves caused by the fault slip is simulated using a FEM model where seismic response on the surface are calculated. A field case study is also presented to demonstrate the applicability of the numerical model developed in this work.

The numerical analysis results indicate that stress concentration occurs around a boundary between the basement and sandstone beneath the reservoir. This affects the stability of existing faults in this region. As a result, when the fault is slipped, seismicity may be triggered. It is assumed that the slip is caused by stress changes in the faulted region as well as a pore pressure change in the fault, which is caused by volumetric strain changes of the fluid in the fault. A field case study based on wastewater injection in the Southwestern region of the United States where injection induced seismicity events have been recently reported, is also performed in this work. In this case study, the variation of rock strength is considered one of important factors in induced seismicity events.

The novelty of our model is the ability to quantitatively assess the risk of induced seismicity due to wastewater injection, which can be also applied to other applications such as CCS and underground gas storages. Moreover, conducting risk assessment by these numerical models can improve safety of underground fluid injection operations.
Study of Degradable Fibers With and Without Guar Gum As A Proppant Transport Agent Using A Large Scale Slot Equipment
Authors: Kim Jung Yong , Zhou Lijun , Morita Nobuo
Published: September 2019

Hydraulic fracturing with slickwater is a common practice in developing unconventional resources in North America. The proppant placement in the fractures largely determines the productivity of the well as it affects the conductivity of fractures. Despite the wide use of the slickwater fracturing and the importance of the proppant placement, the proppant transport is still not fully understood and the efficiency of the proppant placement is mostly bound to the changes to proppant properties, friction reducers, and guar technology. Although the degradable fiber is currently used in some cases, it has not been well investigated. In this experimental study, we conducted proppant transport experiment using different fluid composition of fiber and guar gum in three types of proppant transport slot equipment. The results indicate that the use of degradable fibers with or without the guar gum as viscosifier can produce fracture slurry applicable in both conventional and unconventional fracturing helping proppant placement in the reservoir.
Single Trip Tubing Conveyed Perforations Across Multi-Lobed Differentially Depleted Reservoir Complexes in a Highly Deviated Well - Challenges, Lessons Learned and Best Practices
Authors: Agbo Ejimofor , Anyanwu Chinedu , Olowoyeye Oluwasola , Ini Titus , Enah Victor
Published: September 2019

This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well as inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in the Niger Delta.
Creating 3D Geomodel: How to Increase the Quality through Training and Education?
Authors: Faizov Rustam Zulfakarovich , Maksimova Elizaveta Nikitichna , Kolesnikov Denis Sergeevich
Published: September 2019

The 3D geological model is an important tool, which is used for decision-making process at each step of reservoir lifecycle. In turn the quality of the model as well as field operating efficiency is directly dependent on the geologist's expertise level and requires continuous improvement of professional skills. In the digital technology era the software functions continuously enhance leading to increased number of trainings in order to implement new algorithms in the working process. The aim of the paper is to share the best practices of geological and petrophysical modelling on-job trainings applied in Scientific Technology Centre.

There are several web-resources used in the company in order to store operational regulations, corporate educational trainings, original workflows, created plug-ins etc. By dint of special module in the working software the above mentioned data sources were implemented into the integrated knowledge platform. Now new software functions can be explored on-the-job and without any charges for external trainings. The module affords the development of interactive training cases for new functions study. The results of case accomplishment can be saved and available for competency assesment. Another key aspect of the module is the automatization of model quality control provided by application of guided workflows. Additionally, the solutions for some cases can be found during the crossfunctional co-operation among geologists, petrophysicists and petroleum engineers in online question platform, which is the part of the professional groups.

The unique integrated approach for increasing the quality of geological models through training and education, which is developed and successfully implemented in Scientific Technology Centre, will be beneficial not only for other companies, which plan to create and apply the equivalent employee training system, but also for oil and gas industry in general.
Transforming Traditional Chinese-Taught Petroleum Engineering Courses into English-Taught Petroleum Engineering Courses to Meet ABET Standards
Authors: Qin Wenting , Yuan Ying , Wang Fei , Zhu Zhouyuan
Published: September 2019

It has been a long tradition, in China, the undergraduate and graduate petroleum engineering courses are taught in Chinese. As the globalization playing an important role in our lives, it has become more and more obvious, in many people's point of view, the education quality provided through those Chinese petroleum universities should also be matched with the international standards, such as ABET criteria.

At 2014, the China University of Petroleum Beijing launched a program called the ABET accreditation preparation program. The primary goal of this program is to prepare the ABET accreditation through the transforming of the traditional Chinese-taught Petroleum Engineering courses into English-taught Petroleum Engineering courses to meet ABET standards. At phase 1 of this program, 2014-2015, only two courses (Reservoir Engineering course and Petrophysics course) were chosen to experiment the new concept. Upon the completion of phase 1, the two courses ranked top 5% among all the courses offered by the Petroleum Engineering Department in terms of its popularity among students. Based on the success of phase 1, at phase 2 (2016-now), additional 4 courses were added into this program. Those 4 courses are: Well Completion Design, Flow in Porous Media, Production Engineering, and Reservoir Simulation.

This paper provides the lesson learned through the 5 years’ experience of setting up the new norm by fundamentally changing the ways of teaching in an environment where native language is not English. The specific details of "Know-how" through the execution of phase1 and phase 2 are presented, analyzed and discussed. The paper addressed the obstacles encountered within the program, the new teaching methods conducted in those classrooms and student's response to those brand-new English taught Petroleum Engineering courses.

The experience obtained through the ABET preparation program at China University of Petroleum Beijing may provide some guidance for those who to pursuit the same goal of seeking international recognition and establishing an international learning environment for their Petroleum Engineering courses.
Incorporated Artificial Intelligence and Digital Imaging System for Unconventional Reservoirs Characterization
Authors: Sun Huafeng , Belhaj Hadi
Published: September 2019

The unconventional reservoirs (UCRs) play a key role in global oil and gas supply. However, their reservoir characterization is difficult because of complex pore structure and low permeability-viscosity ratio. Usually, traditional techniques hardly can be used for determination of pore structure and estimation of reservoir properties. In this case, digital rock analysis (DRA) shows the potential for capturing detailed pore structure information and simulating rock properties, such as porosity, permeability, electrical properties and elastic properties. Recently, artificial intelligence (AI) techniques have presented an ever-increasing trend in a wide variety of research and commercial fields. Many AI applications can free man from the labor of complicated works in some way. Machine leaning (ML), which is a subdivision of AI, has attracted researchers' attention and been widely used in geoscience and reservoir characterization, such as feature extracting, rock type prediction and reservoir property estimation. The incorporation of AI and DRA is becoming an inevitable development trend for future reservoir study. In this paper, firstly, DRA workflow for reservoir characterization is introduced; secondly, the commonly used ML algorithms in DRA study is reviewed; finally, a case study of characterization of a tight carbonate reservoir with ML algorithm and DRA is presented. The analysis shows that ML can be applied in any part of DRA progress such as image segmentation, feature detection, rock image classification, numerical simulation and result analysis. Compared with traditional DRA algorithm, ML-based methods can reduce manual operation that has greatly impact on the results. The combination of ML and DRA provides a new insight in UCRs characterization and outlook the future opportunities of AI to solve the oilfield problems.
Automated Influx and Loss Detection System Based on Advanced Mud Flow Modeling
Authors: Lafond Aurore , Leblay Florian , Roguin Ghislain , Ringer Maurice
Published: September 2019

Maintaining well control is one of the most important considerations of any drilling operation, and early detection of formation fluid influx or mud losses is vital to safe drilling.

Today's gain and loss detection tends to trigger too many false alarms; major improvements in reliability (few to no false alarms) and reactivity (no missed events) are needed without being user dependent. The new developed system optimizes both accuracy and efficiency. This system maintains a false alarm rate lower than current system, while detecting influxes or losses as low as 40 gal. It applies also to a wide variety of configuration: deepwater, managed pressure drilling, land rig operations, etc. This performance is achieved through a new flow-modeling processes combined with automated settings, real-time quality control and guided, intuitive software interfaces. From a purely user-dependent system, the new kick detection software is now based on automated processes, ensuring repeatable and optimal detection performances while minimizing risks of human error. The detection of abnormal flow conditions in the well relies on the comparison of predicted and measured flow at the exit of the well. The improvements of the flow modeling, such as new, calibrated pump-efficiency models based on the isothermal modeling of the pumps, increase the robustness and the reactivity of the detection system. The presented case studies allow quantifying improvements of the kick detection performance between the existing system and the new version, benchmarking both the influx-detection reactivity and the system reliability. Kick detection charts used in the study represent a new way of illustrating detection performances.
The Blooming of Women's Leadership in Oil and Gas in the GCC, Middle East, and Key Enablers for their Growth
Authors: Capello Maria Angela , Borisly Nada
Published: September 2019

One of the goals cherished by modern organizations is gender balance, as a proven way to enhance productivity, boost the motivation of employees and enrich the leadership pipelines of internal succession plans. The energy sector follows closely this trend, inclusive of major organizations of operations and services, especially in Oil and Gas. And in no other region of the world this is now more visible than in the Middle East, one of the most active and traditionally leading and strategic regions in the segment. This paper summarizes what factors were fundamental for the very visible blooming of the female leadership, particularly in the oil and gas sectorin the Gulf Cooperation Council GCC countries. Certainly, middle-eastern women do not account yet for a large or representative number inthe highest roles of private or National Oil Companiesof their countries, but things are rapidly changing, and the blooming is real.

A comparison of key elements considered diagnostic about the empowerment of women, like female workforce percentages, gender gap indexes, and representation of women in leadership roles in oil and gas are herein analyzed for the GCC, comparing those with figures of other regions of the World. Other indicators were included in the analysis, which proved to be key for developing women's leadership, in particular, communication strategies, empowering plans, training, active and visible endorsement of top leaders and other strategies of governmental agencies and corporations. Definitively, the Middle East, and particularly the GCC countries, in which our study is centered, have boldly address cultural issues and traditional barriers, to produce step-changes that are quickly transforming the oil and organizations in all countries of the region. A forecast of opportunities for women's leadership in the upstream and downstream sectors of the oil industry in the future is proposed, in a story of learned best practices worth sharing.

The paper includes a summary of the standing and utilization of social media channels by main organizations in oil and gas. A frame of the current trends analyzed resulted in the identification of the organizations more successful in the utilization of these key channels, so relevant for the general audiences and the new generations. Some unexpected findingsshaped our conclusions about strategies instrumental for step-changes needed in political or cultural settings that may be challenging for boosting women's empowerment.
Common Globalization Strategies for SMBs Looking to Expand in Asia Pacific
Authors: Appleton Joel
Published: September 2019

Is your energy business ready to go global?

In today's market there are few companies that are able to strictly focus on domestic opportunities. Increased competition in saturated home markets offer stagnant returns and in order to achieve growth, a company must either innovate, explore opportunities in foreign markets or both. By internationalizing, a company can capture new market share and may achieve continuous business growth. To accomplish this however, a thorough examination of the barriers and key considerations is vital for companies who are considering taking their business to the international stage.

To begin, a company should find a market for their goods and services and then plan, test and evaluate their internationalization strategy. By reviewing different models, theories and tools meant to assist a company when entering into the global economy, these findings and concepts are then applied to a case study of an oil and gas mid-sized service company which internationalized into the South East Asian market.

The intent of the paper is to identify key external considerations that a small to mid-sized oilfield service company should be cognizant of prior to entering into a host market. For many businesses, the rewards far outweigh the risks when a company decides to internationalize. Ensuring they have a proper strategy will set the company up for success. Key global expansion considerations were validated during the initial phases of the internationalization process and after creating a roadmap for the case study oilfield service company as it expanded into South East Asia. Further, several recommendations were put forth. These included host regulatory environment risks, political stability and culture. The goal of this paper outlines how companies can follow their own path, rather than following a herd mentality to go global successfully.
Reactive vs Proactive Intelligent Well Injection Evaluation for EOR in a Stratified GOM Deepwater Wilcox Reservoir using Integrated Simulation-Surface Network Modeling
Authors: Da Sie Will , Oghena Andrew , Seth Gaurav , Ouyang Liang-Biao , Ghoraishy Mojtaba
Published: September 2019

Improved field management for monitoring, estimating zone productivity/injectivity, and controlling wells with intelligent completions can broaden application of advanced well designs. We have developed a coupled Simulation-Surface Network modeling workflow to evaluate the potential benefit of intelligent injection profile control with a focus on reactive vs proactive control for Gulf of Mexico (GOM) Deepwater Enhanced Oil Recovery (EOR) schemes. The developed injection control solution can be consistently applied to gas, water injection, and gas followed by water injection, to evaluate relative impacts of intelligent injectors on each option. We did this by defining rules for both proactive and reactive injection ICV controls for a GOM Deepwater Wilcox multilayered reservoir. Proactive controls, based on reservoir zone characteristics, pore volume injected, and recoverable pore volume, are dependent on a static reservoir model realization. Proactive control results demonstrate a diminishing return as we begin to observe fluid breakthroughs that results in part from the inevitable uncertainty of the original static assessment so there should be a benefit in reassessing optimal pore volume injection based on reservoir model updates. Reactive control strategies based on measured production response is a challenge in terms of linking injection control events to production responses that are time-lagged and incomplete for understanding gas and water breakthrough. The integrated model captures the effects of topside facilities, risers, flowlines, pressure/temperature at manifolds and topside, seafloor booster pump performance, wellheads, and wellbore to reservoir interactions and ICV controls to provide a realistic evaluation of achievable development alternatives outcomes.
Oxygenated Solvent as a Novel Additive for Improved Oil Recovery in Tight Oil Reservoirs
Authors: Wang Mingyuan , Baek Kwang Hoon , Abeykoon Gayan A. , Argüelles-Vivas Francisco J. , Okuno Ryosuke
Published: September 2019

Tight oil reservoirs typically show rapid reduction in production rate within a few years. Various methods of improved oil recovery from tight reservoirs have been studied, such as cyclic injection of gas and chemical solutions. Chemical solution injection is expected to improve oil recovery through wettability alteration and water/oil interfacial tension (IFT) reduction because most tight oil reservoirs are reportedly intermediate- to oil-wet.

This paper presents a comparative study of two wettability modifiers with different characters for enhancing water imbibition from a fracture into the surrounding matrix. One is 3-pentanone, a symmetric short ketone, and the other is 2-ethylhexanol-4PO-15EO, a non-ionic surfactant with an ultra-short hydrophobe. They were used as low-concentration additives (approximately 1 wt%) to reservoir brine (RB) in this research.

Contact-angle experiments with oil-aged calcite surfaces showed that the two chemicals are comparable as wettability modifiers. For example, the surfactant solution was able to change the contact angle of oil droplets on oil-aged calcite surfaces from 134° to 47° within a day.

Coreflooding experiments using fractured limestone cores showed that the 3-pentanone solution resulted in more rapid oil recovery by water imbibition than the surfactant solution. The incremental oil recovery factor was 30.9% for 1.6 pore-volumes injected (PVI) of the 3-pentanone solution and 8.4% for 1.2 PVI of the chase RB. For the surfactant case, it was 23.6% for 1.6 PVI of the surfactant solution and 23.7% for 7.0 PVI of the chase RB.

The difference in oil recovery response between the two chemical solutions was attributed to their different characters as wettability modifiers; that is, the surfactant solution lowers the water/oil IFT from 11 mN/m to 0.21 mN/m, but the 3-pentanone solution does not. The 3-pentanone solution can keep the original water/oil IFT, and increase the capillary force for water imbibition by wettability alteration. The importance of lowering the water/oil IFT was observed during the extended chase RB injection after the surfactant slug. The oil recovery in the surfactant case was increasing even after 7.0 PVI of the chase RB.
Nanofluidic Analysis of Flowback Enhancers for the Permian Basin: Unconventional Method for Unconventional Rock
Authors: Quintero Harvey , Abedini Ali , Mattucci Mike , O’Neil Bill , Wust Raphael , Hawkes Robert , De Hass Thomas , Toor Am
Published: September 2019

For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (kro). This study provides insight into the pore-scale evaluation of the latest flowback enhancer technologies currently applied in the Permian Basin, Texas, USA. A multidisciplinary approach, including concepts of nanotechnology, was used to assess fluid-fluid and rock-fluid interactions occurring at the nanopore scale and their implications on enhancing oil recovery.

A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.

This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (kro) in the nanomodel when MFS was added to the stimulation fluids at loadings as low as 0.05% v/v. The results were compared against other premium flowback enhancers.

Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.

This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
An Integrated Approach in Characterization of Triple Porosity Nisku Reefs Alberta: A Quest from Core and Borehole Images to 3D Earth Model
Authors: Zaluski Wade , Andjelkovic Dragan , Xu Cindy , Rivero Jose A. , Faskhoodi Majid , Ali Lahmar Hakima , Mukisa Herman , Kadir Hanatu , Ibelegbu Charles , Pearson Warren , Ameuri Raouf , Sawchuk William
Published: September 2019

Enhanced oil recovery (EOR) is an economic way of producing the remaining oil out of previously produced Devonian Pinnacle Reefs in the Nisku Formation within the Bigoray area of Alberta. To maximize the recovery factor of the remaining oil, it was necessary to first characterize the geological structure, matrix reservoir properties, vugular porosity and the natural fracture network of these two carbonate reefs. This characterization model was then used for reservoir simulation history matching and production forecasting further discussed by (Rivero, 2019). With the enhanced resolution of a reprocessed 3D seismic volume, more accurate seismic interpretation was completed to better delineate the internal and external structure of the reefs. The petrophysical analysis and core interpretation showed that the two reefs could be divided into two zones; the bottom zone has low porosity and the upper zone has high porosity that was targeted in previous well completion schemes. These zones were easily picked on well logs and when using Seismic Ant Tracking attributes, were accurately interpreted within the seismic volume. With the framework of the geomodel developed, rock type, porosity, permeability and water saturation were interpolated within the reservoir. Because natural fractures in these carbonate reservoirs are known to be an important part of fluid movement, it was important to characterize the discrete fracture network. In one well, a borehole image successfully quantified the properties of the natural fracture network. The observed fracture density (5 fractures/m) suggested discreate fracture zones throughout the well which was also confirmed with core fracture mapping. As part of the geomodel, a discrete fracture model (DFN) was generated; Seismic Ant Tracking was used to interpolate the fracture intensity within the reservoir. In these Devonian Pinnacle Reefs, and in other reservoirs, before investing in an EOR scheme, it is critical for the operator to understand the geologic structure and the petrophysical characteristics of the reservoir in as much detail as possible. This paper demonstrates how log and seismic data that is up to 40 years old can be converted to modern data types and be used to characterize a reservoir in a way not possible before.
Towards Better Estimations of Rock Mechanical Properties Integrating Machine Learning Techniques for Application to Hydraulic Fracturing
Authors: Gong Yiwen , Mehana Mohamed , Xiong Fengyang , Xu Feng , El-Monier Ilham
Published: September 2019

Rock elastic moduli are one of the major perspectives for the hydraulic fracturing design. Among all of them, Young's modulus and Poisson's ratio essentially control fracture aperture for the proppant placement. The objective of this work is to predict the elastic moduli by applying data mining techniques as a comparison to the experimental measurements. We have collected attributes representing the pore structure, mineralogy and geomechanical characteristics. We implemented classification techniques such as k-means, hierarchical and PAM (partition around medoids). PAM results in more evenly-distributed clusters compared to the rest. Artificial Neural Network (ANN) is used for regression. We formulated two scenarios; firstly, all the data is grouped into one group and the other involves performing the regression on the clustered data. Interestingly, both scenarios yield acceptable results. The classification results could guide the fracturing operations where clusters with high brittleness, low anisotropy and high microfracture intensity could be identified as fracture candidates. Still the main limitation to unleash the machine learning capabilities in this domain is the data scarcity
A Unified Gas-Liquid Drift-Flux Model for Coupled Wellbore-Reservoir Simulation
Authors: Tang Hewei , Bailey William , Stone Terry , Killough John
Published: September 2019

Implementation of a drift-flux (DF) multiphase flow model within a fully-coupled wellbore-reservoir simulator is non-trivial and must adhere to a number of strict requirements in order to ensure numerical robustness and convergence. The existing DF model that can meet these requirements is only fully posed for upward flow from 2 degrees (from the horizontal) to vertical. The work attempts to extend the current DF model to a unified and numerically robust model that is applicable to all well inclinations. In order to achieve this objective, some 5805 experimentally measured data points from 22 sources as well as 13440 data points from the OLGA-S library are utilized to parameterize a new DF model – one that makes use of the accepted upward flow DF model and a new formulation extending this to horizontal and downward flow. The proposed model is compared against 2 existing DF models (also applicable to all inclinations) and is shown to have better, or equivalent, performance. More significantly, the model is also shown to be numerically smooth, continuous and stable for co-current flow when implemented in a fully implicitly coupled wellbore-reservoir simulator.
Fracture Cross-Flow Equilibrium in Simulation of Three-Phase Compositional Flows
Authors: Zidane Ali , Firoozabadi Abbas
Published: September 2019

We present an efficient numerical model for compositional three-phase flow in complex fractured media in 2D and 3D. The capillary effect is included in the simulations. The algorithm accounts for one aqueous phase and two hydrocarbon phases. CO2 is assumed to be soluble in the aqueous phase. We extend the fracture cross-flow equilibrium to three phases for the first time. The cubic plus association (CPA) equation of state describes the aqueous phase. To avoid small time steps in fracture elements we adopt an implicit time scheme discretization in the fractures. Capillary pressure gradients are computed at the element level. The phase fluxes are evaluated with the hybridized form of the mass conservative mixed finite element (MFE). A finite volume (FV) discretization is used in the mass balance equations in the fractures and the discontinuous Galerkin (DG) method is used in the matrix with an explicit time scheme. Pressure is implicit in the whole domain. Our algorithm accounts for different types of grids in 2D and in 3D.
When is There Too Much Fracture Intensity?
Authors: Cote Ashley , Cameron Neil , Grunberg Daniel
Published: September 2019

A distinct shift in wellbore fracture stimulation events has occurred within the Western Canadian Sedimentary Basin (WCSB) over the last 5 years. New designs, commonly referred to as "increased fracture intensity designs," are characterized by an increased number of fracture stages, decreased fracture spacing, and resulting increases in water and proppant required per stimulation. Existing technology applied in increased fracture intensity designs include: Open Hole Ball and Seat technology, Coil Activated sleeves, Plug and Perforating, as well as hybrid designs that combine several technologies.

Increased fracture intensity designs have contributed to improved production rates and increased reserves and, as a result, have quickly become the preferred approach to hydraulic fracture stimulation of the reservoir. Promising hydraulic fracture designs and decreased spacing designs run the risk of being applied broadly without discrimination.

Without proper retrospective or hindsight, there is a risk of over applying this new approach with false assurances of its success rates. It is therefore important to determine whether and at what point increasing fracture intensity generates diminishing returns.

This paper provides 3 retrospective case studies within the regions of the greater Montney and Cardium formations where increased fracture intensity designs have led to decreased well production as well as decreased reserve allocation. We further examine the various components of increased fracture intensity designs to pinpoint areas where design optimization may have prevented these outcomes.
Modeling and Optimization of Low Salinity Waterflood with Fines Transport
Authors: Gorucu Seyhan Emre , Dang Cuong , Nghiem Long , Shrivastava Vijay
Published: September 2019

After nearly thirty years of research and development, it is now commonly agreed that Low Salinity Waterflood (LSW) is an attractive enhanced oil recovery (EOR) method because of its incremental oil recovery performance, reasonable operating cost and low environmental impact compared to conventional waterflood and other EOR processes. From the past studies, LSW is known as a process that comprises many mechanisms, i.e. multiple ion exchanges, wettability alteration, complex geochemical reactions, and fines migration and deposition. However, most studies in the literature have only focused on a single recovery mechanism, with varying, sometimes contradictory conclusions. This paper presents: (1) a comprehensive model that takes into account all the different important physics in LSW, i.e. fines transport, geochemistry and wettability alteration; (2) validation with a core-flood experiment; and (3) field-scale optimization of LSW.

A model for fines transport has been developed and incorporated in an Equation-of-State compositional reservoir simulator with geochemistry and wettability alteration modeling. The proposed model is capable of accounting for complex transport phenomena of fines (clay) particles in porous media including fines deposition, entrainment, and plugging. The simulator also considers physical phenomena in the oil/rock/brine system such as aqueous chemical equilibrium, rate dependent mineral reactions, multiple ion exchanges, and relative permeability alteration due to wettability changes. Validations with a LSW core-flood experiment were carried out, which provide insights into the important mechanisms for the incremental oil recovery by LSW.

The proposed model shows good agreement in terms of oil recovery and pressure drop with a benchmark LSW core-flood experiment which was conducted with a non-polar oil and in which migration of clay particles and their plugging of pores were considered as the main recovery mechanism. It is shown that the proposed model can efficiently capture the important physics in LSW processes related to fines transport. The impact of formation damage during LSW can be efficiently evaluated using this model. Finally, an optimization workflow helps maximize the recovery factor of the LSW process.

To our knowledge, this paper describes one of the first LSW mechanistic models to capture the three principal mechanisms of LSW, i.e. fines transport, geochemistry, and wettability alteration. Excellent match with laboratory experiments and field-scale optimization reinforce validity of the model. The proposed workflow can be extended to other recovery methods such as Low-Salinity Polymer or Low-Salinity Alkali-Surfactant-Polymer.
Petroleum Engineering Enrollment: Past, Present and Future
Authors: Heinze Lloyd , Menouar Habib , Watson Marshall , Gamadi Talal
Published: September 2019

Objectives/Scope: Graduate and undergraduate petroleum engineering degrees and enrollments are presented. Causes and effects of huge changes in enrollment and degrees granted over the past sixty years are discussed. The impacts on the future of the petroleum industry’s available new engineers and sources of these talents are presented. Methods, Procedures, Process: United States petroleum engineering enrollments and degrees granted since the 1950’s have been collected from AIME (SPE’s mother institution) sources, SPE’s annual enrollment reports, and more recently surveys of the petroleum engineering department heads. Additional input from SPE’s standing Education and Accreditation Committee and Professionalism Committee are included. Approximately a dozen Colloquiums on Petroleum Engineering Education (CPEE) have been held over the past twenty-five years at locations in the US and other areas of the world. These CPEE discuss enrollment trends, job placement, industry needs and have resulted in significant advancements to petroleum engineering education. Over the last year information has been collected to include five years from non-US programs. Enrollment is compared to inflations adjusted oil prices. Lastly, a look at international petroleum programs as compared to SPE membership changes on a global basis. Results, Observations, Conclusions: This paper presents the following results, observations and conclusions: Petroleum Engineering enrollment and the resulting degrees granted are affected by oil and gas prices. These changes lag price by 2.5 years. The Recent peak in Bachelor of Science (BS) degrees granted 2550 (in 2017) are projected to drop 980 (in 2020). The pipeline to produce new engineers is four to five years long. As industry petroleum engineer requirement increases, it will take several years to increase the supply from previous conventional sources (programs/universities).
Impact of Chemical Osmosis on Brine Imbibition and Hydrocarbon Recovery in Liquid-Rich Shale Reservoirs
Authors: Torcuk Mehmet Ali , Uzun Ozan , Padin Anton , Kazemi Hossein
Published: September 2019

We present an assessment of the impact of low-salinity brine osmosis on oil recovery in liquid-rich shale reservoirs. The paper includes: (1) membrane behavior of shales when contacted by low-salinity brine, (2) numerical model of osmosis mass transport for low-salinity brine, and (3) enhanced oil recovery (EOR) potential of low-salinity osmosis in liquid-rich shale reservoirs.

Capillary osmosis causes low-salinity brine to be imbibed into the shale matrix; thus, forcing expulsion of oil from the rock matrix. This oil recovery process is described by a multi-component mass transport mathematical model consisting of advective and molecular transport of water molecules and dissolved ions. In the transport model, the activity-corrected diffusion of the brine solution is used to calculate the volume of brine imbibed into a shale core sample and the resulting expelled oil. We used the mathematical model to match oil recovery from two carefully designed brine-imbibition experiments conducted at Colorado School of Mines.

We have concluded that, in oil-wet shale reservoirs, low-salinity brine invasion of the rock matrix is by osmosis rather than capillary force. Thus, osmosis is the only imbibing force that drives the low salinity brine into the reservoir rock matrix. Furthermore, we believe brine osmosis can potentially enhance oil recovery by expelling oil out of the rock matrix and into the micro- and macro-fractures existing in the stimulated reservoir volume.
Separation Performance of Compact Axial Hydrocyclone for Water Pre-separation from Wellstream
Authors: Bai Chunlu , Liu Meili , Chen Jiaqing , Wang Chunsheng , Shang Chao , Zhang Ming
Published: September 2019

Efficient and compact separation technology is in urgent need for many oilfield exploitations because of increasing water cut and strict discharge regulations. A compact axial hydrocyclone is presented to pre-separate water from the wellstream. Experimental investigation was carried out to qualify its performance. A test loop is designed to perform experimental investigations. The flow loop is fabricated to manipulate and control various operational variables, such as the oil/water mixture flow rate (0.5-2 m3/h), the oil droplet size, and the water-to-oil ratio (65/35 to 100/0). A combination of venturi tube and static mixer is used to mix oil/water mixture. Dehydration rate and oil concentration at water outlet are used to evaluate the oil/water separation performance. A series of experiments have been carried out to test the performance of the novel hydrocyclone. Inlet parameters, including inlet flow rate, water cut, droplet size and split ratio, have been evaluated. Inlet flow rate, water cut, and droplet size have significant effects on the separation performance. When the oil concentration in the water outlet is controlled to be less than 1,000 ppm, a maximum dehydration rate of 70% can be obtained. The compact axial hydrocyclone exhibits high separation performance and reliability for a wide range of operating conditions. A stable oil core without vortex oscillations is observed. This effect, combined with the low pressure drop, indicates a stable swirl with low turbulence, which enables a higher capacity of the compact axial hydrocyclone compared to traditional hydrocyclone.