bluuebunny/crossref_metadata_2025_split huggingface dataset:
Errors in Prediction of Recoveries from Unconventional Resources with Analytical Methods that Ignore the Physics of the Flow
Authors: Jaiswal Aaditi , Alabdulbaqi Nibras , Alsafar Ali , Ershaghi I. 
Published: April 2017

Abstract
While in reality production from unconventional reservoirs with nanoscale pores and complex systems has caused a dramatic increase in oil and gas production, little is known about an effective characterization let alone prediction of long-term performance of individual wells. These systems challenge our classical understanding of petroleum reservoirs developed over decades. In the meantime, and the absence of a full understanding of the source rock systems, some practitioners have resorted to using reservoir engineering tools and techniques for production forecasting from source rocks. These toots borrowed from engineering principles of conventional petroleum reservoirs do not include the peculiar nature of the source rock systems. This, of course, is a long stretch going from applying conceptual models for uniform pore space occupied by hydrocarbons and water, to systems where fractures, microfractures, present significant complications to understanding the physics of the flow in source rocks. In summary, the realm of producing from source rock is one of those examples where before a better understanding of the rock physics is developed, already in different play areas, we have witnessed the phenomenal growth of drilling and completion of thousands of wells over the last decade.
Forecasting EUR (estimated ultimate Recovery) for individual wells producing from source rocks are essential in decision making at all levels. This is quite challenging particularly when only a few months of production data are available to predict the future. An urgent need in the industry has been using rapid methods for estimation of EUR's in the early life of any new well. These estimates have critical economic viability for business success and economic survival. To stay competitive and to provide attractive rates of return, companies prefer to drill in areas with the highest EUR's per well.
Among the techniques in widespread use are the decline curves. These simple regression models are used to estimate up-front guidance regarding total recoverable volumes over a long period. In practice, any forecasting can help to establish the resource base for individual wells and the entire asset. But the question is the validity of such forecasts. Decline curve analysis is based on empirical observations of production decline. In using decline curves, we assume that reservoir conditions and operating conditions causing the historical decline continue unchanged during the forecast period. In this study, we include well production with 5 or more years of history and examine various decline models using the early history data to test the estimated performance vs. the actual performance. We have noted serious limitations on the use of such models.
Integrated Reservoir Characterization of the Middle Bakken in the Blue Buttes Field, Williston Basin, North Dakota
Authors: Alexeyev Alan , Ostadhassan Mehdi , Bubach Bailey , Boualam Aldjia , Djezzar Sofiane 
Published: April 2017

Abstract
This paper discusses the methodology necessary for lithology identification and petrophysical analysis of an unconventional reservoir in Williston Basin. The scope of the work is done on a producing oilfield in the North Dakota portion of the basin. Well logs from 45 wells in Blue Buttes Field were analyzed, mainly focusing on the Middle Bakken section of the Bakken Formation. Reservoir properties, such as permeability, effective porosity, shale volume, and saturation were determined using a set of commercial software. Several methods for analyzing each property were tried, the results were compared and the best method was picked that matched the core analysis such as the XRD scanning.
The results of this study can help with a decision regarding the further development of the reservoir specifically in the Blue Buttes Field or to improve the understanding of various properties from the Middle Bakken. The procedures presented in this paper will help to establish a workflow for similar studies in other unconventional reservoirs in the future. This case study also helps better understand the lithology and rock properties of the Middle Bakken.
Quantitative Risk Analysis for Induced Seismicity in Hydraulic Fracturing versus Waste Water Disposal
Authors: Hosseini S. Mehran , Aminzadeh Fred 
Published: April 2017

Abstract
Induced seismicity risk is one of the major safety discussions surrounding hydraulic fracturing and waste water disposal. Several reported cases of induced seismicity in both waste water disposal and hydraulic fracturing propelled us to study the differences between the risks in each circumstance, by using a probabilistic-physics-based model. Herein, we present the work of our model for the probabilistic assessment of induced earthquakes that incorporates geomechanical analysis of the state of stress, pore pressure changes, and reservoir boundary conditions. The model considers a randomly distributed network of faults that undergo frictional failure due to overpressure-induced effective stress changes. This model includes the effects of flow properties and flow boundary conditions on overpressure, as well as the influence of initial stress regime on failure. The consequences of different injection parameters, reservoir size and other properties are discussed through case studies. We concluded that, despite the higher rate of injection in cases of waste water disposal, due to much shorter injection intervals, the risk of induced seismicity was much lower. The greatest difference was observed for a bounded reservoir in which the induced seismicity rate increased exponentially. Our proposed model provides a pathway to assess the expected seismic response to fluid injection, and supports the observations of less induced seismicity risk with hydraulic fracturing, compared to waste water disposal.
The Use of Voronoi Mapping for Production Growth in a Heavy Oil Field
Authors: Sharma Jyotsna , Popa Andrei , Tubbs Dallas , Cassidy Steve 
Published: April 2017

Abstract
In this work, we present an application of Voronoi partition technology to identify opportunities for increasing production in heavy oil reservoirs. The Voronoi partitions are a visual way of showing the boundary of influence of each well producing under a gravity drainage mechanism existing in heavy oil reservoirs. In contrast to classical well pattern representation or bubble maps, this approach provides a good estimate of the drainage areas around the wells and aids in identification of by-passed oil and opportunity for well intervention. The successful integration of Voronoi technology and fuzzy logic data led to effective workflows to target the by-passed reserves and identification of well interventions for production growth thus maximizing oil drainage in the Coalinga field.
The subject field presented within this article is a monocline dipping reservoir (14 degrees), with six producing sands located in San Joaquin Valley, California. Given the heterogeneity of the sands, low viscosity of the oil at reservoir conditions, scattered historical steamflood development, and the dipping characteristics; it is a challenge to get good drainage and recovery throughout the field. Therefore, one way to help mitigate this problem is by increasing the number of producers, however drilling new wells is cost intensive. The cheaper alternative is to utilize the existing poor performing wells and sidetrack them to alternate formations to increase productivity. The large number of available wells (over 1000 active & 700 shut-in), presented a lucrative opportunity to pursue the Voronoi technology to automate the process for workover selection and prioritization.
In this study, we demonstrate the methodology used for selection and prioritization of sidetrack candidates. The candidates were ranked based on the properties generated from the Voronoi and fuzzy logic tools, and the best candidates were selected and executed in the field. The lookback study results show a successful agreement of the workflow results and the actual production outcome, thus demonstrating the effectiveness of the proposed workflows.
Observations in the Loss of Well Productivity with High Solid/Liquid Ratios During Frac Jobs
Authors: Gao Song , Ershaghi Iraj 
Published: April 2017

Abstract
There have been various observations about the merits of increasing the proppant volume during hydraulic fracturing of source rocks. A general recommendation has been that larger proppant volumes can help in maintaining fracture flow capacity. In this study, we present data on actual cases related to more than 104 wells producing from the Bakken formation. Two parameters of interest were used as measures of well productivity. First was the average initial flow rate of the well, represented by the cumulative production during the first three months, and then was the production decline represented by the cumulative volume of oil produced in 180 days. Both of these parameters were tested as a function of corresponding sand/liquid ratios for similar completion practices and in the same reservoir. In all cases, we observed an an optimum value for the proppant liquid ratio related to the best case scenarios. Beyond that optimal ratio, the well performance show a deterioration. We attribute this to an overall reduction in fracture conductivity caused by packing of fractures, potential proppant plugging and slurry dehydration under excessive proppants placement.
Compositional Simulation Evaluation of Miscible Gas Injection Performance in Tight Oil Formation
Authors: Mansour Ahmed GH , Khalil Rayan , Gamadi Talal 
Published: April 2017

Abstract
Studying the performance of different techniques to improve oil recovery of tight oil reservoirs have become the main focus of many researchers because of the significant contribution of these reservoirs to the USA daily oil production. Recent studies have shown possibility of using EOR methods to improve oil recovery of tight and ultra-tight oil reservoirs as an attempt to encouagre the development of these reservoirs. This paper studies the feasibility and limitations of applying miscible gas flooding to enhancing oil recovery of tight and ultra-tight formation. A compositional simulation study was conducted and three main factors were used to study the performance of gas flooding; formation permeability, distance between wells, and gas injection period. Five permeability values, 1 md, 0.1 md, 0.01 md, 0.001 md, and 0.0001md, were used to build five simulation models then these models were used to study the performance and define the limitations of gas flooding process for each model. The results of the first part of the compositional simulation study show that the oil recovery has been improved when the miscible gas displacement process was applied to a formation that has permeability larger than 0.01 md becuase gas flooding did not significantly improve oil recovery for the models that have formation permeability less than 0.01 md. Second, we used the distance between the injection and production wells and gas injection period to investigate the performance and the limitations of applying gas flooding on each models. As a result of that, it has been found that formation permeability has a significant effect on the selection of well spacing. Forthermore, the study helped to recommend the well spacing that should be considered for different formation permeability values. Finally, this study promotes the understanding of implementing the miscible gas flooding in tight and ultra-tight oil formation and helps in the selection of the best candidate to apply gas flooding base on its permeability. Furthermore, it helps in optimize the well spacing of tight formation if gas flooding process is considered in future.
Above-Zone Pressure Response to Distinguish Between Fault and Caprock Leakage
Authors: Mosaheb Mojtaba , Zeidouni Mehdi 
Published: April 2017

Abstract
Deep saline aquifers are widely considered for injection/disposal of fluids (e.g. CO2 and wastewater) in the subsurface. However, target injection aquifers may be overlain by a regionally leaky caprock, which allows for fluid migration from the injection zone. In addition, target aquifers may also be intersected by leaky faults, which can accommodate leakage by connecting the target aquifer to other permeable zones. Leakage from the injection zone to an above permeable zone will be associated with pressure rise in that zone. The above zone pressure response has recently been extensively investigated in studying leakage in the context of CO2 geological sequestration. Both leaky fault and leaky caprock are considered as potential leakage pathways. Before analyzing above-zone pressure response for leakage characterization, it is important to determine whether the feature causing leakage is a fault or the semi-pervious caprock. The focus of this study is to provide a diagnostic tool to identify the leaky fault from a leaky caprock based on the pressure response.
A fault is a planar interface that can act as a conduit both normal and through the fault plane. Caprock is a very low permeability medium which is assumed to act as sealing layer to the reserved fluids. However, there may be heterogeneities associated with regional permeability variations in the caprock, which can accommodate leakage. An injection well makes a local high pressure region near the well that may result in significant leakage through the caprock or a fault intersecting the reservoir.
In this work, we investigate leakage from an injection layer into an overlying layer through a leaky fault and a leaky caprock based on the pressure changes. We present analytical models for pressure response to interlayer communication via a caprock and a leaky fault. The fault leakage causes a linear flow in the overlying layer. However, leakage through the cap rock is different in nature for which most leakage occurs at the vicinity of the injection well The flow regime occurred in the above-zone due to leakage are the base of our method to identify the leaky fault from the leaky caprock. Results show that fault leakage makes linear flow and caprock leakage show late-time radial flow in the above-zone. In order to detect these flow regimes by the common pressure transient analysis methods, the observed pressure in the above-zone must be normalized based on the time variable leakage rate.
Life After CHOPS: Alaskan Heavy Oil Perspective
Authors: Mathur Bakul , Dandekar Abhijit Y. , Khataniar Santanu , Patil Shirish L. 
Published: April 2017

Abstract
Heavy oil reservoirs in Alaska provide for major production challenges. The diverse set includes proximity to permafrost layers, very high viscosity oil and low mechanical strength pay zones. The Ugnu deposits of Alaska North Slope (ANS) hold more than 6 billion barrel of oil in place. The dead oil viscosity at reservoir temperature ranges from 1,000 to 1,000,000 cp1. In an effort to achieve sustained well life, this paper focuses on the unique set of challenges occurring in the Ugnu reservoir and presents the best possible way of maximizing production.
The paper accentuates on the observations derived from the field data which shows that deliberate sand production with the hydrocarbon stream while employing a Progressive Cavity Pump (PCP) as artificial lift method has favorable effect on the primary oil recovery. The developments have led to the advent of technique called Cold Heavy Oil Production with Sand (CHOPS) as initial production method for shallow heavy oil reservoirs. Sand production leads to the formation of high porosity channels or wormholes that can range up to hundreds of meters. The co-mingling of heavy oil and sand develops the behavior of foamy oil by creating a bubbly flow inside the reservoir. The combination of these wormholes with foamy oil behavior are the primary factors that result in enhanced production during CHOPS. One of the major hindrances to its successful application is the selection of post CHOPS production method, that has been addressed in this paper with the help of modeling and simulation The present research is based on modeling one of the wells drilled into the M80 sands of the Ugnu formation and then analyzing the post CHOPS recovery for the well. The research uses modeling of CHOPS well with the help of a wormhole fractal pattern and a foamy oil model. Simulation of polymer injection is then being employed from a nearby well. The recovery obtained from the simulations have been analyzed to provide a basis for selecting the appropriate enhanced oil recovery method after CHOPS.
Alternative recovery techniques following the primary cold production include water flooding, polymer injection, miscible gas injection and thermal recovery methods. Water flooding becomes unviable because of the mobility contrast between the highly viscous oil and water. The high permeability zones provide a bypass for water, producing elevated water cuts as a consequence. Another aspect unique to Alaskan heavy oil reservoirs is the proximity to the permafrost layer with the hydrocarbon bearing zone making thermal recovery methods unappealing. Polymer injection and miscible gas injection become favorable non-thermal secondary and tertiary recovery methods in this case. This paper analyses the performance of polymer flooding on a reservoir that has been produced with CHOPS. The results indicate almost 12% increment in recovery with polymer flooding as compared to the natural depletion.
Analytical Cyclic Steam Modeling Revisited and Applied to the Shallow Low Permeability California Diatomite
Authors: Elias Ramon , Medizade Mason 
Published: April 2017

Abstract
The commercial production of oil from the low permeability and shallow Opal A diatomite in California has been one of the most important resource development accomplishments of recent times. Corresponding oil-in-place estimates range from 24 to 80 billion barrels with oil recovery efficiencies of 50% and more. Most of the production comes from cyclic steam stimulation (CSS).
This paper discusses changes made to an existing analytical thermal simulator to modelCSS production from diatomite. Algorithms were added to enable well stimulation and reservoir dilation. Field production data was compiled from public sources and history matched to calibrate the input parameters. The model was then run to show how stimulation and dilationinfluence oil and water production. The conclusions give new insightson production from the diatomite.
This is the first published application of CSS analytical modeling for this resource.
Augmented Text Mining for Daily Drilling Reports using Topic Modeling and Ontology
Authors: Arumugam Sethupathi , Rajan Shebi , Gupta Sanjay 
Published: April 2017

Abstract
Exploring Textual data has been often presented as a challenge across all the industries around the world. This challenge has been alleviated to an extent by the biomedical industry using text mining to improve cancer research. This paper proposes applying similar techniques to explore daily drilling reports, these reports are rarely exploited for well planning. It is paramount to identify relevant drilling reports for the current well planning operations and to utilize advanced text mining techniques to track drilling operations against geological formations and offset wells in terms of caving, mud loss, vibrations, sudden increase/decrease of ROP, additional torque, etc.
This paper focuses on knowledge discovery using statistical analysis, theme based Report classification and domain based ontology to identify offset wells which have encountered risks and events. Tetxual contents are extracted from the drilling reports and analyzed using bag of words, frequency distribution and pie charts to obtain high-level view of the drilling reports. The processed Textual is further analyzed using Latent Dirichlet Allocation (LDA) into theme based models; in LDA each report is viewed as a mixture of themes that are present within the textual corpus. Outcome of LDA model helped to establish Ontology association between the symptoms and their corresponding causes. This helps Geologists in identifying offset wells with operational challenges and equips them for faster root cause analysis that can lead to better well planning.
Knowledge Discovery begins by extracting facts and events from daily drilling reports. Classification of drilling reports, extraction of key events encountered on geological formations are problems that Geologists face using this approach would allow them to browse large collection of documents, view critical highlights and drill down for detailed information.This solution can be further extended to other reports such fluid report, mud log report and operational reports. All the well reports can be exploited using text mining results to provide greater insight into drilling operation from different perspective.
Recovery Improvement of Gravity Driven Steam Applications Using New Generation Chemical Additives
Authors: Bruns Fritjof , Babadagli Tayfun 
Published: April 2017

Abstract
Reservoirs containing very heavy oil or extremely heterogeneous/fractured geology are not convenient for steamflooding and even cyclic steam injection. Then, steam can be used to heat the reservoir and accelerate the recovery by gravity drainage. Two well-known applications of this method are steam assisted gravity drainage (SAGD) and thermally assisted gas oil gravity drainage. Although the latter is not commercially applied, the former is a proven technology with remarkable production in Canada and Venezuela. Due to the risks caused by the cost and solvent retention, no large scale applications of solvent injection with steam have been implemented. An alternative is to use chemicals as suggested a few decades ago to alter the interfacial forces and improve microscopic displacement. This paper presents experimental results on testing -new generation- chemicals for their capability in recovery improvement.
Sandpack experiments were conducted to evaluate the incremental in oil recovery by chemical additives compared to sole steam injection. Steam and chemicals were heated and introduced to the system from separate channels at the entrance of the vertically situated sandpack (30 cm long, 5 cm in diameter). To generate a purely gravity dominated system (pressure differential of 10–25 psi) a back pressure regulator was used. The chemicals used include thermally stable surface agents, such as surfactants (AAS J1111, O352, LTS-18), Tween 20, biodiesel), ionic liquid (BMMIM BF4), high pH solution (NaBO2), solvent (heptane), and nanoparticles (SiO2). The oil selected was 20,000 cp crude.
Incremental recoveries were monitored and related to the thermal stability of the chemicals. A comparative analysis was provided as to their contribution to the reduction of the cost (less steam and lower temperature) and chemicals were classified based on their recovery improvement performance and thermal stability. Through this experimental schematic, the highest increment in oil recovery was achieved by LTS-18 but also combined a high duration of the experiment with a high water consumption. This reduces the result in economical favorable conditions of the LTS-18. Biodiesel had the best performances in steam-to-oil ratio (SOR) and its effects needs to be further investigated. Tertiary injection of hot water with a surfactant was inefficient. Ionic liquid increased the oil recovery in the tertiary stage after the core was flooded with a low quality steam by 20%.