bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs
Authors: Moridis George , Reagan Matthew 
Published: February 2021

SummaryThe main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an enhanced oil recovery (EOR) process to increase production from multifractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems.This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically fractured shale reservoir under production. The stencil is discretized using a very fine (millimeter-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities.The results of the study indicate that a continuous CH4-based displacement that begins at the onset of production does not appear to be an effective EOR method for hydraulically fractured shale oil reservoirs over a 5-year period in reservoirs in which natural or induced fractures in the undisturbed reservoir and/or in the stimulated reservoir volume (SRV) can be adequately described by a single-medium porosity and permeability. Under these conditions in a system with typical Bakken or Eagle Ford matrix and fracture attributes, continuous CH4 injection by means of a horizontal well parallel to the production well causes a reduction in water production and an (expected) increase in gas production but does not lead to any significant increase in oil production. This is attributed to (a) the limited penetration of the injected gas into the ultralow-k formation, (b) the dissolution of the injected gas into the oil, and (c) its early arrival at the hydraulic fracture (HF; thus, short circuiting the EOR process by bypassing the bulk of the matrix), in addition to (d) the increase in the pressure of the HF and the consequent reduction in the driving force of production and the resulting flow. Under the conditions of this study, these observations hold true for domains with and without an SRV over a wide range of matrix permeabilities and for different lengths and positions (relative to the HF) of the gas injection wells.
Physics-Driven Machine-Learning-Based Borehole Sonic Interpretation in the Presence of Casing and Drillpipe
Authors: Liang Lin , Lei Ting , Donald Adam , Blyth Matthew 
Published: February 2021

SummaryInterpretation of sonic data acquired by a logging-while-drilling (LWD) tool or wireline tool in cased holes is complicated by the presence of drillpipe or casing because those steel pipes can act as a strong waveguide. Traditional solutions, which rely on using a frequency bandpass filter or waveform arrival-time separation to filter out the unwanted pipe mode, often fail when formation and pipe signals coexist in the same frequency band or arrival-time range. We hence developed a physics-driven machine-learning-based method to overcome the challenge. In this method, two synthetic databases are generated from a general root-finding mode-search routine on the basis of two assumed models: One is defined as a cemented cased hole for a wireline scenario, and the other is defined as a steel pipe immersed in a fluid-filled borehole for the logging-while-drilling scenario. The synthetic databases are used to train neural network models, which are first used to perform global sensitivity analysis on all relevant model parameters so that the influence of each parameter on the dipole dispersion data can be well understood. A least-squares inversion scheme using the trained model was developed and tested on synthetic cases. The scheme showed good results, and a reasonable uncertainty estimate was made for each parameter. We then extended the application of the trained model to develop a method for automated labeling and extraction of the dipole flexural dispersion mode from other disturbances. The method combines the clustering technique with the neural-network-model-based inversion and an adaptive filter. Testing on field data demonstrates that the new method is superior to traditional methods because it introduces a mechanism from which unwanted pipe mode can be physically filtered out.This novel physics-driven machine-learning-based method improved the interpretation of sonic dipole dispersion data to cope with the challenge brought by the existence of steel pipes. Unlike data-driven machine learning methods, it can provide global service with just one-time offline training. Compared with traditional methods, the new method is more accurate and reliable because the processing is confined by physical laws. This method is less dependent on input parameters; hence, a fully automated solution could be achieved.
Challenges from Well Shut-in Amid the Oil Downturn: Long Term Impacts on Near Wellbore Skin Buildup and Sand Control
Authors: Soroush Mohammad , Mahmoudi Mahdi , Roostaei Morteza , Izadi Hossein , Hosseini Seyed Abolhassan , Leung Juliana , Fattahpour Vahidoddin 
Published: February 2021

Abstract
In wake of the biggest oil crash in history triggered by the COVID-19 pandemic; Western Canada in- situ production is under tremendous price pressure. Therefore, the operators may consider shut in the wells. Current investigation offers an insight into the effect of near-wellbore skin buildup because of such shut-in.
A series of simulation studies was performed to quantitatively address the impact of well shut-in on the long-term performance of well, in particular on key performance indicators of the well including cumulative steam to oil ratio and cumulative oil production. The long-term shut-in contributes to three main modes of plugging: (1) near-wellbore pore plugging by clays and fines, (2) scaling, and (3) chemical consolidation induced by corrosion. A series of carefully designed simulations was also utilized to understand the potential of skin buildup in the near-wellbore region and within different sand control devices.
The simulation results showed a higher sensitivity of well performance to shut-in for the wells in the initial stage of SAGD production. If the well is shut in during the first years, the total reduction in cumulative oil production is much higher compared to a well which is shut-in during late SAGD production life. As the induced skin due to shut-in increases, the ultimate cumulative oil production drops whose magnitude depends on well completion designs. The highest effect on the cumulative oil production is in the case of completion designs with flow control devices (liner deployed and tubing deployed completions). Therefore, wellbore hydraulics and completion design play key roles in the maintenance of uniform inflow profile, and the skin buildup due to shut-in poses a high risk of inflow problem and increases the risk of hot-spot development and steam breakthrough.
This investigation offers a new understanding concerning the effect of shut-in and wellbore skin buildup on SAGD operation. It helps production and completion engineers to better understand and select candidate wells for shut-in and subsequently to minimize the skin buildup in wells.
An Innovative Modelling Approach in Characterization of Autonomous Inflow Control Valve Performance to Maximizing Oil Recovery in Heavy Oil-SAGD Application
Authors: Mohd Ismail Ismarullizam , Mathiesen Vidar , Abraham Anson , Ranjbar Ehsan , Zarei Faraj , Walter Jeremy 
Published: February 2021

Abstract
Flow control devices (FCDs) have demonstrated significant potential in improving recovery from Steam Assisted Gravity Drainage (SAGD) production wells. Passive FCDs will allow the SAGD producer well to create additional pressure drop to balance the production influx, improving overall conformance and promoting accelerated hydrocarbon production. However, passive FCDs cannot effectively restrict steam effluents once steam breakthrough at the production well occurs.
The Autonomous Inflow Control Valve (AICV) actively delivers a dynamic flow restriction with the ability to choke and/or ‘shut-off’ in response to the associated viscosity and density of the fluids flowing through the AICV. This novel AICV design behaves truly autonomously based on the Hagen-Poiseuille equation and Bernoulli’s principle. The AICV utilizes the differences in flow behaviour between the laminar and turbulent flow restrictions to differentiate the pressure-drops between oil, water, gas, and steam phases.
A collaborative effort has been initiated between the AICV vendor and the Computer Modelling Group to develop reservoir simulation workflows with the AICV that will allow the user to enter characteristic performance curves for a variety of SAGD and thermal fields. The development of mechanistic wellbore modelling and developed methodology to incorporate the associated complexities of AICV behaviour has shown to be an improvement to the way FCDs are currently modelled, providing insight into the potential for AICV application in SAGD and other thermal recovery operations. Such techniques allow the reservoir simulation tools to perform realistic predictions of the AICV behaviour at downhole conditions and evaluate scenarios and relative impacts of completion designs.
The development of a new characterization method of AICV performance in SAGD applications, and its implementation in reservoir simulation tools, has helped to unveil the benefits of implementing AICVs in improving recovery from SAGD operations.
Making the Case for the Use of Effective Tension in Casing Design to Eliminate Approximations and Wall Thickness Limitations
Authors: Murphey Carey , Ruddy Kenneth , Ruddy Kate 
Published: February 2021

Abstract
Existing plastic limit load equations for casing design include approximations that can result in overly conservative (and costly) well designs and ignore forces that may prove critical for assured integrity in complex operations. The use of effective tension in place of physical tension can simultaneously simplify casing design and eliminate existing approximations and wall thickness limitations.
Effective tension has not yet been widely adopted because a rigorous derivation based on axiomatic mechanics and calculus does not exist in the current body of literature. This paper presents a thorough derivation for effective tension in terms of working stresses, with tensile, radial, and tangential stresses all receiving proper treatment. Unlike Barlow’s equation, which is routinely used for casing selection, the analytical result presented here allows fully plastic limit loads to be established for tubulars of any wall thickness, without introducing any approximations.
Determining plastic limit loads is a crucial component of designing for well integrity, especially with complex operational loads where classical load equations are too conservative. The methods of transformation detailed in this paper facilitate the use of effective tension, which is often the more efficient primary tension load variable for pipe design, as opposed to physical tension. The rigorous model can also be used to derive strains as functions of loads, which is required for some design problems such as seal effectiveness. Additionally, the formulas can be used to dynamically simulate load changes and dimensional changes of pipe when it deforms, such as expandable casing, deformable ball seats, or when approaching rupture pressure.
The elimination of approximations in the equations presented in this paper is significant in today’s well design climate, where integrity is demanded yet excessive cost is not tolerated. The derivation provides a foundation upon which existing casing design can be improved by eliminating wall thickness limitations and dependencies on approximations. This foundation will allow new design techniques to be developed that were not previously achievable due to the inefficiencies inherent in the use of physical tension.
A Mathematical Model to Predict Solvent/Steam Flashing in Pure Solvent or Solvent/Steam Coinjection in Horizontal Producers
Authors: Irani Mazda , Sabet Nasser , Bashtani Farzad , Gohari Kousha 
Published: February 2021

Summary
Although the steam assisted gravity drainage (SAGD) process is still the preferred thermal-recovery process method for Athabascan deposits in Alberta, Canada, the interest in solvent-based techniques is growing due to reduce greenhouse-gas (GHG) emissions and water treatment concerns. In SAGD process, the thermodynamic trapping or subcool trapping is quite efficient due to strongly dependency of bitumen viscosity to temperature. As Irani (2018) discussed subcool trapping for solvent applications such NsolvTM recovery process is inefficient due to week dependency of solvent viscosity to temperature. Other factor that effects the efficiency of the thermodynamic trapping is that the pure solvent injection recovery processes are operated at low pressure and it is not large temperature window for operators to apply large subcools. Such challenges make the pure solvent injection recovery processes a perfect case for deployment of Flow-Control-Devices (FCDs). FCDs have demonstrated significant potential for improving recovery in SAGD production wells. FCD experience in SAGD has been primarily positive and most producers performed better with FCDs. Application of FCDs are even more important in pure-solvent injection recovery processes due to large amount of solvent in the liquid pool and also low latent heat of solvent in comparison of water. With FCDs, the draw-down pressure is typically higher, resulting in flashing near the well bore, which is largely correlated to latent heat of the main fluid in the liquid pool.
The flashing creates either steam or vapour breakthrough that causes the reduction in the relative permeability of the liquid phase. Such mobility reduction creates new equilibrium that stabilizes at lower rates. Such new equilibrium analysis is conducted by forcing a new temperature gradient to the model. Such condition creates an environment that leads into extensive solvent-breakthrough called solvent-coning in this study. The main output of such analysis is the produced solvent gas-fraction produced at the sand-face. The gas-fraction is an important input for the flow control devices (FCDs) especially at subcools close to the zero, as it controls its behavior. EoS model is also created and simplified to be possible to used in defining different equilibrium conditions. This type of analysis can help the operators evaluate the effectiveness of different type of FCDs, whether they are primarily momentum- or friction-style devices for application of the pure solvent injection recovery processes. This study is the first of its kind that couple the EoS and Darcy flow in the liquid pool. The model includes all the factors into a liquid-relative-permeability, and limitation of the liquid flow into producer is modeled by Darcy flow and reduction of such relative-permeability.
Well Integrity Issues in Steam Flood Injection Wells, Karim Small Field Cluster
Authors: Ariwibowo Alexis , Al Sulti Al Salt , Al Aufi Yousuf , Mirza Muhammad 
Published: February 2021

Abstract
Two (2) steam flood vertical injection wells are under operation for the last 15 months in a two- pattern pilot. Previous steam injection experience in this reservoir did not indicate serious issues due to the short injection periods for cyclic steam stimulation (CSS) but several well integrity issues have been faced during the steam flood period. Key issues include high wellhead growth, steam leak to the annulus A, annulus between 7” production casing and 4-1/2” injection tubing, and groundwater vapor behind 9.625” surface casing. Negative impacts from these issues on the continuity and effectiveness of the steam flood are recognized and need to be resolved comprehensively.
All wells in the steam flood pilot were drilled and completed based on designs and procedures according to thermal well compliance including well equipment, and cementing specification. Production casing was equipped with thermal expansion collars to support reduction in wellhead growth. Completion strategy uses seal bore packer with bore extensions to accommodate tubing movement and Vacuum-Insulated-Tubing to provide maximum thermal insulation. However, the presence of a total- loss zone near the surface (starting from 50 m depth) affects the cement isolation between surface casing and 12.25” open hole. Daily monitoring is performed on each well where key injection parameters and well responses are recorded.
Maximum wellhead growth reached 61 cm within the first week and steam leak from the injection string to annulus A started after 6 months of steam injection. Soon after that, groundwater vapor starts to arise from the gap between 9.625” casing and 12.25” open hole. These series of failures occurred in both injection wells within 3 months apart from each other. It is believed that the steam leak to annulus A resulted in thermal transmission to groundwater vapor. Hoist entries to both injectors indicated that Injector-1 has tubing seal assembly stuck inside seal bore and resulted in parted tubing collar while Injector-2 has tubing seal assembly damage. Both wells have thick oil covering the retrieved seal bore packer. Remedial actions were performed, including a complete change-out of the seal bore packer assembly and top-job cement fill up to surface using fast-set cement to isolate the gap between 9.625” casing and 12.25” open hole to reduce wellhead growth. As a result, the maximum wellhead growth became only 19 cm and 4 cm in Injector-1 and Injector-2, respectively. These remedial actions also led to restoring well and thermal integrity.
Retrieved seal bore packer was sent back to manufacturer for appropriate failure analysis and providing useful feedback reports on the above issues. Monitoring and observation data along with failure analysis should provide vital information and possible improvement in completion strategy for steam injection wells that are planned for continuous steam flood projects in similar reservoirs.
Performance Analysis of Infill Wells Adjacent to SAGD Well Pair: Non-Condensable Gas NCG Breakthrough
Authors: Irani Mazda , Tuttle Aubrey , Stevenson Jesse 
Published: February 2021

Summary
Late in the life of the Steam Assisted Gravity Drainage (SAGD) process, it has become common practice to drill a single, horizontal infill well (called a “Wedge Well™” by some) in the oil bank located between two mature SAGD well pairs to produce the bitumen that has been heated and mobilized but is unable to be effectively drained by gravity given the largely lateral location relative to that of the SAGD producers. Since this oil bank is surrounded by the large, depleted steam chamber created by the existing well pairs, it requires little heat to mobilize bitumen. One of the challenges, however, in producing infill wells is that non-uniform drainage and local hot spots can be readily created in the first year of their operation, that in many cases require completion retrofits, such as with Flow Control Devices (FCDs), to improve the drainage profile. Installation of FCDs in these wells is quite challenging since the dynamics of the infill wells is changing with time and there is limited time to achieve conformance.
To maintain pressure in SAGD chambers the common practice is to inject non-condensable gas (NCG). NCGs, such as methane, which is most common, do not condense in the steam chamber. Some of these NCG can short-cut into the infill through the existing hot-spot. The main reason is that the hot sections of infills are locations that are closer to the SAGD steam chamber, and due to steam condensate encroachment and higher mobility create a pathway for NCG breakthrough. FCDs are designed to promote a more uniform flux distribution along the producer, and exposure to NCG can change the impact of the FCDs. The true hot-spot temperature after NCG injection is decreasing and this can be mistaken as FCD efficiency and steam blocking. In reality, this temperature reduction is due to partial pressure effects associated with NCG encroachment. In this study, a new thermodynamic model is created to explain the NCG encroachment into infill wells, and a new temperature profile along the producer as a function of NCG breakthrough is calculated. The purpose of this work is to create a productivity index (PI) relationship that is fit for purpose for infill wells adjacent to SAGD well-pairs with NCG breakthrough that can primarily be used for analysis and optimization of SAGD FCD completions. This model can also be used to evaluate FCD performance in infill wells pre- and post- NCG breakthrough.
Pore-Scale Simulation of Calcite Matrix Acidizing with Hydrochloric Acid
Authors: HaghaniGalougahi MohammadJavad 
Published: February 2021

Summary
A continuum hydrodynamic model with immersed solid/fluid interface is developed for simulating calcite dissolution by hydrochloric acid (HCl) at the pore scale, and is most accurate for a mass-transfer-controlled dissolution regime under laminar flow conditions. The model uses averaged Navier-Stokes equations to model momentum transfer in porous media and adopts a theoretically developed mass-transfer formulation with assumptions. The model includes no fitting parameter and is validated using experimental results. The findings of previous research and existing models are briefly discussed and their shortcomings and advantages are elucidated. The present model is used in some pore-scale simulations on hypothetical but realistic cases, investigating the evolution of Darcy-scale permeability. Darcy-scale permeability exhibits totally different functionality of porosity in different dissolution regimes.
Reserves Determination Using Type Curve Matching and Extended Material Balance Methods in the Medicine Hat Shallow Gas Field
Authors: West S. L. , Cochrane P. J. R. 
Published: February 2021

Tight shallow gas reservoirs in the Western Canada Basin present a number of unique challenges in accurately determining reserves. Traditional methods such as decline analysis and material balance are inaccurate due to the formations' low permeabilities and poor pressure data. The low permeabilities cause long transient periods not easily separable from production decline using conventional decline analysis. The result is lower confidence in selecting the appropriate decline characteristics (exponential or harmonic) which significantly impacts recovery factors and remaining reserves. Limited, poor quality pressure data and commingled production from the three producing zones results in non representative pressure data and hence inaccurate material balance analysis.
This paper presents the merit of two new methods of reserve evaluation which address the problems described above for tight shallow gas in the Medicine Hat field. The first method applies type curve matching which combines the analytical pressure solutions of the diffusivity equation (transient) with the empirical decline equation. The second method is an extended material balance which incorporates the gas deliverability theory to allow the selection of appropriate p/z derivatives without relying on pressure data.
Excellent results were obtained by applying these two methodologies to ten properties which gather gas from 2300 wells. The two independent techniques resulted in similar production forecasts and reserves, confirming their validity. They proved to be valuable, practical tools in overcoming the various challenges of tight shallow gas and in improving the accuracy in gas reserves determination in the Medicine Hat field.