bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Data-Driven Analytics to Assess the Impact of Design Parameters on Production from Shale
Authors: Esmaili S. , Mohaghegh S. D. 
Published: June 2014

Abstract
The importance of production from Shale and its impact on the total US energy equation has focused much attention on this prolific source of hydrocarbon. Consequently, research related to unconventional reservoirs has increased significantly in order to better understand the inherent complexities of their behavior.
Analytical, numerical and statistical analyses have been applied to large multi-variable data set from Shale assets with different degrees of success. The notion that shale is a "statistical play" may be attributed to the fact that many of our preconceived notions on storage and flow mechanisms in shale are not supported by facts. Therefore, we set out to examine the possibility of learning from the data in order to be able to answer some of the questions that rise during the production process. Data Driven Analytics, having roots in pattern recognition and machine learning, have proven to be capable of extracting useful information from large data sets and are extensively used in many industries. Their application to multi-variable data sets from Shale assets, in order to extract understandable structure in the data, is the subject of the work being presented here.
This paper presents a Data Driven Analytics study of design parameters such as well trajectories, completion, and hydraulic fracturing variables for a large number of horizontal wells in Marcellus Shale. The data set from the Shale assets is so complex that use of conventional statistical analysis does not results in understandable trends and patterns. On the other hand, when advanced pattern recognition tools are used, certain (previously hidden) patterns emerges from the data with unmistakable trends.
In this article impact of parameters such as up-dip versus down dip deviation of wells, stimulated lateral length and cluster spacing, etc. on production from wells in a Shale asset is analyzed using an advance pattern recognition algorithm. The analyses are performed using production from multiple time intervals throughout the life of wells.
Gas Injection Rate Needed for SAG Foam Processes to Overcome Gravity Override
Authors: Boeije C. S. , Rossen W. R. 
Published: June 2014

Abstract
Gravity override is a severe problem in gas-injection enhanced-oil-recovery processes, especially in relatively homogeneous formations. Foam can reduce gravity override. Shan and Rossen (2004) show that the best foam process for overcoming gravity override is one of injecting a large slug of surfactant followed by a large slug of gas, injected at constant, maximum-allowable injection pressure. This process works because foam collapses near the injection well, giving good injectivity simultaneously with mobility control at the leading edge of the gas bank. The supply of gas that would be needed to maintain constant injection pressure is a concern for EOR processes where gas is produced industrially or from a separations plant with limited capacity: the available gas stream may not be sufficient for the optimal process.
We show that for such a process, the pressure drop across the foam bank back to the injection well, at fixed injection rate, is nearly constant as the foam bank propagates radially outward. From this result, one can derive a simple formula to predict the rate of gas injection required for each of two limiting cases:
an extremely strong foam at the foam front, many times more viscous than the fluids it displaces. In this case, the rate of gas injection required to maintain constant injection pressure is nearly constant, but injection rate is low. a foam just strong enough to maintain mobility control at its leading edge. In this case injection rate required to maintain constant injection pressure increases steeply with time.
Using the formulae provides a quick initial estimate of how gas injection rate must vary over the duration of the EOR process to maintain an optimal process. In addition, we illustrate how one would determine the properties of a foam that would fit the available gas stream. This criterion then could guide the development of a surfactant formulation with these properties.
Gas-Injection Rate Needed for SAG Foam Processes To Overcome Gravity Override
Authors: Boeije C.S.. S. , Rossen W.R.. R. 
Published: June 2014

Summary
Gravity override is a severe problem in gas-injection enhanced-oil-recovery (EOR) processes, especially in relatively homogeneous formations. Foam can reduce gravity override. Shan and Rossen (2004) show that the best foam process for overcoming gravity override is one of injecting a large slug of surfactant followed by a large slug of gas, injected at constant, maximum-allowable injection pressure. This process works because foam collapses near the injection well, giving good injectivity simultaneously with mobility control at the leading edge of the gas bank. The supply of gas that would be needed to maintain constant injection pressure is a concern for EOR processes in which gas is produced industrially or from a separations plant with limited capacity: The available gas stream may not be sufficient for the optimal process.
We show that for such a process, the pressure drop across the foam bank back to the injection well, at fixed injection rate, is nearly constant as the foam bank propagates radially outward. From this result, one can derive a simple formula to predict the rate of gas injection required for each of two limiting cases:
An extremely strong foam at the foam front, many times more viscous than the fluids it displaces. In this case, the rate of gas injection required to maintain constant injection pressure is nearly constant, but injection rate is low. A foam just strong enough to maintain mobility control at its leading edge. In this case, injection rate required to maintain constant injection pressure increases steeply with time.
Use of the formulae provides a quick initial estimate of how gas-injection rate must vary over the duration of the EOR process to maintain an optimal process. The fit to simulations of surfactant-alternating-gas (SAG) foam-injection rate in a five-spot pattern is remarkably good, especially for strong foam, given the simplicity of the model. In addition, we illustrate how one would determine the properties of a foam that would fit the available gas stream. This criterion then could guide the development of a surfactant formulation with these properties.
Novel Electro-Hydraulic Intelligent Firing Head for Tubing Conveyed Perforating
Authors: Stolboushkin Eugene , Zuklic Steve , Peterson Rick , Stretton John 
Published: June 2014

Abstract
Existing pressure-sensitive firing heads are either hydraulic or electronic. Hydraulic firing heads have the advantage of simplicity and cost. In addition, hydraulic firing heads do not have batteries and can, therefore, remain downhole for several months before functioning. This enables the operator to utilize their assets and equipment more economically. Electronic firing heads, however, enable operations in small pressure margin wells and allow for more advanced completion equipment and services.
The newly-developed electro-hydraulic firing head combines the long downhole life of a hydraulic firing head with the capabilities of an electronic firing head. An electronic module is programmed at surface to respond only to a pre-programmed pressure signature. Upon detecting this signature, the electronic module activates the hydraulic firing mechanism, initiating the perforating guns below.
This hybrid design incorporates safety features that were previously unique to each type of firing head. The hydraulic firing mechanism, which uses a percussion detonator, eliminates the need for electronic detonators that are sensitive to electro-magnetic interference (EMI) caused by rigsite communications devices. Additionally, this mechanism must have several thousand PSI to function, making surface detonation impossible. The electronics module prevents the firing head from functioning from an unintended overpressure of the wellbore, greatly reducing the possibility of firing off-depth.
This paper will discuss the design, development, and testing of this firing head from a mechanical and electrical engineering point of view, as well as the operational reliability, safety, and human interface features included in the design. In addition, it will discuss the test plan to qualify the tool for reliable and safe operations at up to 30,000 psi at 400ºF, as well as the test results.
Methodological Approach for Optimization of Completion Practices in Mature Carbonate Fields
Authors: Babaniyazov A. , Jackson C. H. 
Published: June 2014

Abstract
Technology advances, coupled with favorable commodity prices, have made it possible for operators to revive mature oil fields once considered depleted. This paper intends to illustrate how using existing wellbores to prove development potential and refine completions practices jump started one such revival in the Permian Basin. The team used a methological approach to prioritize projects, optimize stimulations, minimize the impact of wellbore integrity issues, and drive down costs.
Though this paper focuses on work implemented in a mature field environment, any field with a major review of the existing completion strategy can use the methodology outlined.
Technical discussions focus on stimulation optimization techniques and wellbore integrity assurance. The workflows for project prioritization and cost reduction are also addressed.
The methological approach led to reduction of fracture stimulation expenses by fifty %, reduction in rig time, and reduction of contingency cost associated with well integrity. As a result, otherwise uneconomic resources were added and future development opportunities were identified. Various sand-fracturing stimulation placement and diversion techniques were field tested and compared using post-stimulation production results and after-frac radioactive tracers. Despite the savings offered by diversion with ball sealers, isolation using mechanical tools was significantly more effective and justified the additional costs.
Resin-coated sand concentration for flowback control was analyzed and reduced from 50% to 10% based on findings. The team was able to reduce pad volumes and increase sand concentrations resulting in improved fracture conductivities and reduced costs. Field supervisors were trained to analyze net pressure response and adjust pumping schedule on the fly. The well integrity communication and information workflow was implemented, reducing costs and operations downtime. Major workover risks were identified, recorded, and quantified, improving project contingency planning and resource allocation.
Experimental Study of the Swelling Properties of Unconventional Shale Oil and the Effects of Invasion on Compressive Strength
Authors: Emadi Hossein , Soliman Mohamed , Samuel Robello , Ziaja Malgorzata , Moghaddam Rozbeh B. , Hutchison Shannon 
Published: June 2014

Abstract
In the industry as a whole, we are still at the beginning of the learning curve for shale oil drilling operations; however, many shale-oil wells have been drilled in recent years. Drilling through shale-oil formations is very problematic and imposes significant costs to the operators owing to wellbore-stability problems. These problems include, but are not limited to, tight holes, stuck pipe, fishing, sidetracking, and well abandonment. To more efficiently and effectively drill through these formations, we should better understand their properties.
Few experiments have been performed on shale-oil samples to better understand their properties. Most experiments conducted thus far were performed on common shale core samples, which are significantly different from shale oil samples. In this study, we first determined the mineralogy of shale-oil core samples from the Eagle Ford field and then investigated the swelling properties and Cation Exchange Capacity (CEC) of the core samples in the laboratory. Experiments have been conducted with the samples partially submerged in distilled water and potassium-chloride (KCl) brine. Several experiments have been performed using strain gages to measure lateral, axial, and diagonal swelling in both submerged and non-submerged areas.
The results demonstrate that the swelling properties and CEC of the shale oil core samples are different from the common shale core samples. This study proposes the quantification of the shale/fluid properties, the interaction, and the effects of different fluids on rock properties in unconventional reservoirs. This paper presents and documents the differences in the swelling properties between conventional and unconventional shale. The results of the study will help us to more precisely understand unconventional shale oil rock properties and can be used to design a more effective drilling fluid for field applications, as well as more accurately predict the mechanisms of formation failure.
Predictions of the Growth of Multiple Interacting Hydraulic Fractures in Three Dimensions
Authors: Castonguay Stephen T. , Mear Mark E. , Dean Rick H. , Schmidt Joseph H. 
Published: June 2014

Abstract
This paper presents fracture simulations of multiple, interacting, non-planar fractures in three dimensions. The paper provides a short description of the mathematical formulation of the model but the primary focus is on fracture propagation examples and illustrations of how multiple hydraulic fractures interact in three dimensions. The examples which are presented are intended to provide insight into how the number of growing fractures affects fracture shapes, how changes in fluid viscosity can cause fractures to grow together or grow apart, and how limited-entry at the perforations affects the propagation of interacting fractures. The fracture simulator discussed in this paper models the simultaneous growth of non-planar hydraulic fractures in a three-dimensional linear elastic media, and it can also incorporate stress shadows from hydraulic fractures created during earlier fracture stages. The program uses a symmetric Galerkin boundary element method to model fracture shapes and fracture growth, while flow in the fractures is modeled as power-law fluid flow in arbitrary curved channels. The program uses an effective mode-I stress intensity factor to determine which portions of each fracture will propagate and employs mixed-mode stress intensity factors, KI and KII, to determine propagation directions.
Drilling Systems Automation: Current State, Initiatives and Potential Impact
Authors: Macpherson John D. , de Wardt John P. , Florence Fred , Chapman Clinton D. , Zamora Mario , Laing Moray L. , Iversen Fionn P. 
Published: June 2014

Abstract
Drilling automation is the control of the drilling process by automatic means, ultimately reducing human intervention to a minimum. The concept of automating the drilling process has generated considerable interest, yet there is a lack of agreement on exactly what it is, what it entails, and how to implement it. As with industrial automation in the 1990s, the adoption of open standards enabling automation will have a significant impact on the underlying business model. In the oilfield drilling industry, the business model describes the relationship between operator, drilling contractor, service company, and equipment supplier.
The goal of drilling systems automation is to increase productivity and quality, improve personnel safety, and effectively manage risk. Principal drivers of drilling automation include well complexity, data overload, efficiency, repetitive well manufacturing, access to limited expert resources, knowledge transfer due to the exodus of skilled employees, and health, safety and environmental concerns. With so many drivers, and their potential economic benefits, it is understandable that there are many automation related initiatives within the industry.
Drilling through geopressured, possibly erratic lithologies, to a remote and possibly poorly defined target in a safe manner is not a simple task to automate. It is challenging. Drilling automation focuses on the drilling system and drilling operations, which entail combining various sub-systems, including the downhole BHA and its measurement and active components, the drillstring, fluid, and drilling rig and its sub-assemblies. Operations include conventional overbalanced, managed pressure, and underbalanced drilling operations, and their various procedures, such as tripping and making connections.
This paper examines and defines drilling systems automation, its drivers, enablers and barriers, and its current state and goals. In particular, the paper looks at the vision of drilling systems automation, and the role played by open collaborative initiatives among all segments of the drilling industry. Although commitment to automation by the drilling industry appears by many to lag other major industries, there are segments of the drilling industry that have reached a high level of automation on a commercial basis. There is also significant collaboration among interested parties in creating a standardized, open environment for data flow to foster the development of systems automation.
Effect of Concentration on HPAM Retention in Porous Media
Authors: Zhang Guoyin , Seright R. S. 
Published: June 2014

Abstract
This paper investigates the effect of HPAM polymer concentration on retention in porous media using both static and dynamic measurements. Consistent results using these two methods show that different polymer retention behaviors exist in dilute, semidilute and concentrated regions. In both the dilute and concentrated regions, polymer retention is basically concentration-independent. In contrast, in the semidilute region, polymer retention is concentration-dependent. If a porous medium is first contacted sufficiently with dilute polymer solution to satisfy the retention, no significant additional retention occurs during exposure to higher HPAM concentrations. Based on the experimental results, a concentration-related retention mechanism is proposed that considers the orientation of the adsorbed polymer molecules and the interaction between molecular coils in solution. Using this model, we explain why polymer retention does not show much dependence on concentration in the dilute and concentrated regimes. Further, in the semidilute region, we explain how moderate coil interactions lead to mixed adsorbed polymer orientation and magnitude on rock surfaces, and retention becomes concentration-dependent. In field applications of polymer and chemical floods, reduced polymer retention may be achieved by first injecting a low-concentration polymer bank.
The Role of Autonomous Flow Control in SAGD Well Design
Authors: Banerjee Sudiptya , Jobling Robert , Abdelfattah Tarik , Nguyen Hang 
Published: June 2014

Abstract
Steam-assisted gravity drainage (SAGD) has become the de-facto standard for commercial development of heavy oil and bitumen (HO-B) reserves in a significant number of fields. Although SAGD has proved to be a highly effective technique, many uncertainties and unanswered questions still exist, leaving room to improve production and optimize the economics of a SAGD installation. One notable improvement originating from recent field experience is the novel usage of injection/inflow control devices (ICDs) in a conventional SAGD well pair. The use of a properly designed ICD completion is proving beneficial to both steam chamber development as well as improving the inflow profile of the producing well of the SAGD pair.
Work conducted in the Surmont field of Alberta, Canada provided an excellent starting point to optimize flow control improvements to the SAGD process. However, significantly more needs to be added to the discussion to establish best practices for ICD selection and usage and to quantify the benefits gained from using autonomous ICDs in HO-B reservoirs. It is the goal of this paper to provide a useful reference for ICD behavior and theory, selection criteria, the unique role of ICDs in managing steam chamber development, steam fingering control, and management of the subcool temperature (steam trap control). Representative field simulations of Albertan bitumen sand are used as the basis for describing overall trends in the use of flow control in the SAGD process.
The Risk of Using Risk Matrices
Authors: Thomas Philip , Bratvold Reidar B. , Eric Bickel J. 
Published: June 2014

Abstract
The risk matrix (RM) is a widely espoused approach to assess and analyze risks in the oil & gas (O&G) industry. RMs have been implemented throughout that industry and are extensively used in risk-management contexts. This is evidenced by numerous SPE papers documenting RMs as the primary risk management tool. Yet, despite this extensive use, the key question remains to be addressed: Does the use of RMs guide us to make optimal (or even better) risk-management decisions?
We have reviewed 30 SPE papers as well as several risk-management standards that illustrate and discuss the use of RMs in a variety of risk-management contexts, including HSE, financial, and inspection. These papers promote the use of RMs as a "best practice." Unfortunately, they do not discuss alternative methods or the pros and cons of using RMs.
The perceived benefit of the RM is its intuitive appeal and simplicity. RMs are supposedly easy to construct, easy to explain, and easy to score. They even might appear authoritative and intellectually rigorous. Yet, the development of RMs has taken place completely isolated from academic research in decision making and risk management. This paper discusses and illustrates how RMs produce arbitrary decisions and risk-management actions. These problems cannot be overcome because they are inherent in the structure of RMs. In their place, we recommend that O&G professionals rely on risk- and decision-analytic methods that rest on over 300 years of scientific thought and testing.
Investigation of Miscibility Behavior of CO2 rich Hydrocarbon Systems – With Application for Gas Injection EOR
Authors: Lindeloff Niels , Mogensen Kristian , Oil Mærsk , Pedersen Karen Schou , Tybjerg Peter , Noman Rashed 
Published: June 2014

Abstract
The phase behavior of two Middle East reservoir fluids mixed with CO2 has been studied. The experimental work includes quantification of VLLE/LLE behavior studied in a visual high pressure PVT cell.
To investigate the effect of dispersion on slim tube recoveries, experiments were performed using two different tube sizes. One of the reservoir fluids was found to be miscible with CO2 at the reservoir temperature while a liquid-liquid split persisting at high pressure was observed for the other fluid. As the two liquid phases had approximately the same mobility, a high slimtube recovery was seen for the latter fluid despite the liquid-liquid split. EOS models have been developed matching the swelling and slimtube data and confirming the observed VLLE and LLE phase behavior.
The work has led to an improved understanding of how swelling and MMP data for CO2-crude oil systems is to be interpreted. An important observation is that a miscible drive is not always attainable for a reservoir fluid undergoing CO2 gas injection.