bluuebunny/crossref_metadata_2025_split huggingface dataset:
Salt Water Disposal Performance in the Williston Basin
Authors: Schmidt Darren , Miguens Andrea Carolina , Wong Clarence , Hlava Kimberly , Pinkston Daniel 
Published: April 2019

Abstract
A significant expansion has occurred in North Dakota to accommodate disposal of produced water since the onset of oil production from the Bakken petroleum system. Anywhere from 1-2 barrels of water are associated with each barrel of oil produced in the Williston Basin. The growth over the past 10 years warrants a closer examination of the reservoir in which we store produced water and the related injection well performance. A sample of well test data, and an investigation of average injection pressure, cumulative injection, and injectivity index suggest that poor injection performance is associated with limitations to reservoir quality. Historically good injection wells appear to maintain positive injection volumes and are not significantly limited by wells added nearby. Increases in reservoir pressure are evident over limited geographic areas. Wells in these areas tend to suffer lower injection rates, and higher average injection pressures. The evidence from well testing, current geologic investigations, and geographic well characteristics suggest that localized geologic properties and reservoir quality are the primary limiting factors for poor injectivity performance.
Analytical Scaling Enhances Production Analysis of Multi-Fractured Horizontal Wells
Authors: Lemoine Romain , Lee John 
Published: April 2019

Abstract
This paper presents a rigorous method to scale rate-time profiles of multi-fractured horizontal wells (MFHW) to a set of reference reservoir and completion properties. Scaling is required for development of accurate production forecasts and typical well production profiles (type wells) with minimum uncertainty.
We use a modified version of commonly-used type curves, notably the Wattenbarger type curve, to fit production data. The fit requires that production profiles exhibit a negative half slope during transient linear flow followed by negative unit slope during boundary-dominated flow on a rate vs. material balance time plot. The horizontal and vertical displacement required to fit observed data to the type curve define the scaling factors for individual wells.
We present a set of equations to scale a given well's production profile to that of a reference well with specified effective permeability, fracture length, lateral length, net-pay thickness, drawdown, and fracture stage spacing. Just as we can scale a group of wells to common reference conditions, we can also rescale to predict the performance of a well with specified properties, such as average properties determined from wells analyzed or wells with completion designs different from those analyzed. While it is common and clearly important to normalize (scale) rate profiles for lateral length, we demonstrate that it is also crucial to scale production profiles in rate and time to account for differences in permeability, fracture spacing and thus, the duration of flow regimes. We provide examples of successful scaling based on publically reported production data from Marcellus, Barnett, Niobrara, Midland Basin (Wolfcamp) and Eagle Ford resource plays.
Most of the methods used to assess the performance of MFHW's in resource plays rely on having a statistically significant number of analogs. However, datasets of sufficient size are often either unavailable or limited by the large variety of completion designs and well performance characteristics. Our approach to scale production can dramatically increase the number of analogs available to characterize a geologically similar area and thus reduce the uncertainty in production forecasts.
Application of Novel Surfactants with Co-Solvent Character for Heavy Oil Recovery
Authors: Baek Kwang Hoon , Argüelles-Vivas Francisco J. , Abeykoon Gayan A. , Okuno Ryosuke , Weerasooriya Upali P. 
Published: April 2019

Abstract
A new class of ultra-short hydrophobe surfactants with co-solvent character was investigated as a sole additive to conventional polymer flooding for heavy oil recovery. No alkali was used for emulsification. The surfactants tested are composed of a short hydrophobe (phenol in this research) extended by a small number of propylene oxide (PO) and sufficient ethylene oxide (EO) units to achieve aqueous stability: phenol-xPO-yEO. Results are presented for the selection of ultra-short hydrophobe surfactants, aqueous stability, emulsion phase behavior, and oil-displacement through a glass-bead pack at 368 K.
Results show that 2 wt% phenol-4PO-20EO was able to reduce the interfacial tension between oil and NaCl brine to 0.39 dynes/cm, in comparison to 11 dynes/cm with no surfactant, at 368 K. Water flooding, 70-cp polymer flooding, and surfactant-improved polymer flooding were conducted for displacement of 276-cp oil through a glass-bead pack that represents the clean-sand faces of a heavy oil reservoir in Alberta, Canada. The oil recovery at 2 pore-volumes of injection was 84% with the surfactant-improved polymer flooding, which was 54% and 22 % greater than the water flooding and the polymer flooding, respectively. Results suggest a new opportunity of enhanced heavy oil recovery by adding a slug of one non-ionic surfactant with co-solvent character to conventional polymer flooding.
Improving Value of History Matching by Bridging the Discipline Gap with Integrated Static and Dynamic Subsurface Evaluations
Authors: Fjerstad Paul A. , De La Colina Julio C. , Turner Alexandre , Tyshkanbayeva Aigul , Pusca Victor , Lolomari Otonye T. , Ayanbule BabaFemi , Kim Jong Uk , Ghoraishy Mojtaba , Chukwuka Clement 
Published: April 2019

Abstract
This paper describes an alternative practical interdisciplinary collaboration and application of a work process applied to field case studies from recent producing fields for identification of field development opportunities. Multi-disciplinary integration of static and dynamic work processes is part of the history matching process. The process improvements involve use of a common visualization environment that enable efficient iterative updates to reservoir characterizations and modification of production engineering information.
Next generation subsurface modeling tools and reservoir simulation technology has been deployed and adopted. Modeling tools continue to evolve and mature. Geologists, geophysicists and reservoir engineers now have access to user-friendly tools with common look-and-feel graphical user interfaces. The workflow outlined in this paper is one possible workflow enabled using a flexible and integrated framework. The primary goal of modeling is to streamline the construction and practical business use of reservoir models. The introduction of interdisciplinary work processes achieves this goal. Drillers, petroleum and reservoir engineers and geoscientists are all working from the same subsurface depth model, co-visualizing and co-analyzing diverse types of information in a collaborative environment.
The history matching process and workflow requires updates and adjustments to the dynamic model. A typical history match starts with hand-over of the static model to the reservoir engineer. This process oftentimes results in a dynamic model with a lack of ongoing direct updates of the static geological model and hence loss of full evaluation of all geological uncertainties. The loss of integration between the static and dynamic modeling results in too much time spent modeling of detailed geological events that have little impact on the dynamic behavior of the reservoir. Missing important geological and petrophysical parameters may have significant impact on the history match quality. Direct changes and updates to the static reservoir description ensures consistency between the static and the dynamic models.
Results from dynamic modeling combined with an update of the reservoir characterization can easily be shared with all team members. This process improves the quality of matched models, it reduces the speed of completing history matches and results in improved understanding of the static and dynamic uncertainties and their interdependencies. Discussion of complex relationships with the entire team observing an array of data and interpretations, results in clearer communication and enhanced decision making.
Uncertainty Analysis in Production Forecasting-Part II: A Case Study on the Barnett and Haynesville Shale Plays
Authors: Mabadeje Ademide O. , Ghanbarnezhad Moghanloo Rouzbeh 
Published: April 2019

Abstract
This paper evaluates the impact of decision making and uncertainty associated with production forecast for 11000+ wells completed in the Barnett & Haynesville shale plays. Existing studies show that unconventional reservoirs have complex reservoir characteristics making traditional methods for ultimate recovery estimation insufficient. Based on these limitations, uncertainty is increased during the estimation of reservoir properties, reserve quantification and, evaluation of economic viability. Thus, it is necessary to determine and recommend favorable conditions in which these reservoirs are developed.
In this study, cumulative production is predicted using four different decline curve analysis (DCA) - power law exponential, stretched exponential, extended exponential and Duong models. A comparison between the predicted cumulative production from the models using a subset of historical data (0-3months) and actual production data observed over the same time period determines the accuracy of DCA's; repeating the evaluation for subsequent time intervals (0-6 months, 0-9 months,..) provides a basis to monitor the performance of each DCA with time. Moreover, the best predictive models as a combination of DCA's predictions is determined via multivariate regression. Afterwards, uncertainty due to prediction errors excluding any bias is estimated and expected disappointment (ED) is calculated using probability density function on the results obtained.
In this paper, uncertainty is estimated from the plot of ED versus time for all wells considered. ED drops for wells having a longer production history as more data are used for estimation. Also, the surprise/disappointment an operator experiences when using various DCA methods is estimated for each scenario. However, it appears that in both plays power law exponential serves as the lower boundary of the forecast whilst the upper boundary – stretched exponential (SE) and Duong (DNG) method always significantly overpredicts the cumulative production in the Barnett and Haynesville respectively.
The outcome of the paper will help improve the industry's take on existing uncertainty in production forecast using the concept of expected disappointment. This study suggests that effects of bias due to decision making can be much greater than what has often regarded, which can change the performance evaluation of the Barnett and Haynesville plays in terms of economic feasibility.
Feasibility Study of Heavy oil Recovery Using In-situ Steam Generated by Thermochemicals
Authors: Moussa Tamer , Patil Shirish , Mahmoud Mohamed 
Published: April 2019

Abstract
Alaska North Slope (ANS) contains heavy oil (12-23 API) with an estimated range of original oil in place (OOIP) of 13 to 25 billion barrels. This resource has been considered as one of the largest heavy oil deposits in the United States. However, several technical challenges are limiting its commercial development. One of the most significant difficulty is the overlying 1,800-2,000 ft-thick permafrost layer, which causes unavoidable significant heat losses when steam is injected from the surface steam generators, and the potentially disastrous effects due to melting of the permafrost around the cemented casing. Therefore, surface steam injection might not be a viable option to develop this resource, although it is the most commonly used approach of heavy-oil recovery. Hence, the objective of this research is to conduct a feasibility study on the application of new approach, in which steam is generated downhole using thermochemical reaction (SGT) combined with steam assisted gravity drainage (SAGD), to recover heavy oil from Ugnu reservoir which is one of the major oil deposits in ANS.
A numerical simulation model for Ugnu heavy oil reservoir is built using CMG-STARS simulator. Then a MATLAB framework is integrated with the simulation model to study different recovery strategies on the project profitability. Net Present Value (NPV) is used in this study as the key performance indicator while monitoring oil recovery factor (RF) and cumulative oil production (COP). The design and operational parameters studied and optimized in this paper involve; 1) well configurations and locations, 2) steam injection rate and quality, steam trap and startup heating period to initialize SAGD process.
The results show that the in-situ SGT is a successful approach to recover heavy oil from Ugnu reservoir and it yields high project profitability, in terms of the NPV after 10 years of development. The main reason of this outperformance is ability of SGT to avoid the significant heat losses and associated costs, in the surface steam injection methods.
This paper introduces a novel approach to generate downhole steam using thermochemical reactions to overcome the challenges associated with heavy-oil resource development from Ugnu reservoir, while minimizing the environmental impact by reducing the greenhouse gas emission related to surface steam injection methods.
Coke Deposition During Air Injection Assisted Cyclic Steam Stimulation Process: Mechanism Study and Field Impact Analysis
Authors: Wang Yanyong , Zhang Liang , Ren Shaoran 
Published: April 2019

Abstract
Air injection assisted cyclic steam stimulation (CSS) is an innovative and effective process for enhancing ultra heavy oil recovery and increasing the efficiency of steam injection, which has been successfully applied in over 200 wells in Liaohe oilfield (Northeast China) in recent years. During this process, low temperature oxidation (LTO) and pyrolysis of crude oils may take place spontaneously under elevated reservoir temperatures (around 300°C) due to steam and air coinjection. There have been concerns over the formation and deposition of coke-like substance in the reservoir and their impacts on reservoir permeability and oil production.
In this study, the mechanisms of coke formation during this process were investigated based on experimental results, and the effects of LTO reactions on coking and oil pyrolysis were analyzed. A mechanistic model of coke formation in the presence of air was constructed, in which the coking process was modeled based on the partial equilibrium reaction. The model was then incorporated into a reservoir simulator, and a field scale reservoir simulation study of this process was conducted in order to reveal the impacts of coke deposition on formation properties and oil recovery performance.
The simulation results demonstrate that coke deposition can reduce the fluid porosity and permeability in the near well region, which will induce a detrimental effect on heavy oil production. Therefore, the possible reduction of formation permeability due to precipitation of coke-like substance should be considered. The field performance of this technique conducted in a typical ultra heavy oilfield was simulated and presented along with the analysis of the possible coking effect. Injection of air with reduced oxygen content is proposed for reducing the coking effect, and the simulation results show that injection of air with oxygen content of 10 vol% will be beneficial to retarding coke formation and deposition, and moreover the safety hazard of explosion will also be eliminated in field operation.
This study can provide new insights into the numerical modeling of the coking process and deepen the understanding of the air injection assisted CSS process for extracting oil from ultra heavy oil reservoirs.
Production Optimization through Intelligent Wells in Steam Trapping in SAGD Operations
Authors: Temizel Cenk , Canbaz Celal Hakan , Palabiyik Yildiray , Irani Mazda , Balaji Karthik , Ranjith Rahul 
Published: April 2019

Abstract
Steam-assisted Gravity Drainage (SAGD) is one of the major thermal recovery methods for heavy oil. Optimization of SAGD is a delicate process that needs to be planned and operated in a detailed manner. Steam trapping is one of the methods that may help optimize production in SAGD by keeping the steam chamber well drained, where liquid does not accumulate on top of the producer and steam is not produced. This is a challenging process even with the advances in well completions with smart or intelligent wells. In this study, the use of smart valves (ICVs) are investigated and their use in optimization of SAGD through steam trapping is outlined.
A comprehensive review on steam trapping, in terms of theory and practice, has been provided. A smart well configuration with intelligent valves are built in a representative reservoir simulation model where the full-physics commercial reservoir simulator is coupled with an optimization/sensitivity software to optimize the processes and investigate the significance of the key control/decision and uncertainty variables. Different approaches are used in steam trap control; static location, dynamic scanning in time and location, and dynamic scanning in time and specified locations. The results are outlined along with practical aspects of the whole process and operation.
The results are outlined in a comparative way to illustrate the benefits of smart valves and the key points in utilizing them, including economic aspects of their use for additional recovery and the related costs. Results indicate that intelligent wells may prove useful in optimizing steam trapping in SAGD operations depending on the size of the prize.
There are several studies on steam trapping. However, there aren't many studies that integrate steam trap control with smart wells. This study investigates the theoretical and practical aspects of steam trapping using intelligent wells, along with outlining the key attributes, decision and uncertainty variables in a comparative way in terms of the steam trap control strategies and economics.
An Investigation into the Effect of Brine Salinity on Fines Migration in SAGD Operations
Authors: Haftani Mohammad , Wang Chenxi , Montero Pallares Jesus David , Mahmoudi Mahdi , Fattahpour Vahidoddin , Nouri Alireza 
Published: April 2019

Abstract
In Steam Assisted Gravity Drainage (SAGD) operations, condensed water dissolves the formation minerals and mixes with formation water, and its salinity changes over time. For the salinity levels below a critical salt concentration, brine reacts with the formation clays and affects their mobilization towards the production well. Migrated fine particles may plug the pore spaces around the well and reduce wellbore productivity. This paper aims to investigate the impact of water salinity on fines migration and permeability reduction.
A large-scale pre-packed Sand Retention Tests (SRT) facility was employed to simulate SAGD well conditions. Brine with different NaCl salt concentrations was injected into synthetic sand-pack samples that are representative of the McMurray Formation. Flow rates were varied during the test, and fines migration along the sand-pack was traced. Differential pressures along the sand pack were recorded to calculate the permeability changes during the test. Samples of produced water were collected immediately below the coupon to measure the fines concentration. Testing parameters such as pH, clay mineralogy, temperature, and sand control specifications were kept constant in all tests.
Fines concentration in the produced water during the test and retained permeability were considered as the indicators of the fines migration inside the sand-pack. Results of step-rate testing display a jump in fines concentration in produced water right after each flow rate increase. Besides, fines concentration results show that fines migration was insignificant when using brine with high salt concentrations. Fines migration was stronger for a relatively narrow salinity range with low NaCl concentrations, resulting in the highest pore plugging. The findings in this research are consistent with past studies which relate clay dispersion to the zeta potential of clay materials: the higher the zeta potential, the stronger the fines dispersion and migration.
Based on this study, it is recommended that the operating companies monitor the chemical properties of the produced water. Field operators could preserve the reservoir productivity by manipulating the formation salinities to lower the dispersion and detachment of fines and their migration towards the production well.
Characterizing of Ferric Ion interaction with Viscoelastic Surfactant VES-Based Acidizing Fluid
Authors: Afra Salar , Samouei Hamidreza , Nasr-El-Din Hisham A. 
Published: April 2019

Abstract
Viscoelastic surfactant (VES) have been successfully applied as acid-diversion fluids. However, high temperature, interaction of VES and Fe(III), addition of alcohol-based additives, and chelating agents all interfere with the apparent viscosity of the VES-based acid and reduce its efficiency. In the present study, the interactions of Fe(III) with a new type of VES-based acid system, which can be applied effectively for diversion at high temperatures, were characterized in a wide range of pH.
The physical behavior of the VES solutions after addition of iron at various pH values were observed visually to determine any change in the viscoelasticity of the solutions. In the present study, because of the similarity between chemical structures, 3-sulfopropyldimethyl-3-methacryl -amidopropylammonium (SMA) was used as a model compound of VES to characterize the nature of the interaction between VES and Fe(III). IR spectroscopy was employed to understand the nature of the SMA interactions with Fe(III) in different pH values. Also, UV-vis spectroscopy was conducted to determine stoichiometry of the interactions as well. Single X-ray crystallography was also utilized to further understand the nature of interaction between SMA and Fe(III).
Bottle test results show the formation of a viscoelastic gel at different pH in the presence of Fe(III)and VES. IR results express that the interaction of SMA and Fe(III) occurs through the amide group in the SMA which is existed in the headgroup of tested VES too. These results confirms previous observations that the interaction of amide part of the VES with Fe(III) results in screening the repulsion forces between surfactant head groups and formation of wormlike micelles that is the primary reason for increase in the viscosity. Results of continuous variation method on SMA and Fe(III) also confirm the 1:1 stoichiometry in their interaction which are in agreement with the results of our previous study on stoichiometry of VES and Fe(III) interaction.
The present paper is the first mechanistic attempt to characterize and understand the nature of a VES-based system interaction with Fe(III) by using a model compound that has the same headgroup as tested VES. The findings of the present study can be utilized to further investigations of the effects of additives on the performance of VES- based systems.