bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alkali Metal Silicides: A New Material for Heavy Oil Production Processes
Authors: Krumrine Paul H. , Lefenfeld Michael , Romney Gregory A. 
Published: June 2014

Abstract
Alkali metal silicides are a new class of materials that can provide thermal, chemical and immiscible gas drive benefits in one treatment. Not previously known in oilfield applications, these materials are solid, energy-dense chemicals that generate heat, hydrogen and an alkali silicate upon reaction with reservoir water. The reaction is only limited by availability of any type of water; in a closed environment, pressures &gt;10,000 psi can be generated. Alkali metal silicides are dispersible in various hydrocarbon fluids to facilitate placement in a reservoir and can be coated to allow time delayed reaction. The powders can also be milled to submicron size for optimum injectivity in high permeability reservoirs. This combination of material and reaction-product properties makes silicides particularly applicable for the recovery of heavier crude oils. Since the chemical reaction occurs in-situ, silicides are not subject to the thermal efficiency limitations of conventional thermal EOR processes at depth. Further, the resulting hydrogen and silicate reaction products represent a "green" chemistry approach that may reduce the environmental impact of oil recovery operations. This paper presents bench scale core flood results demonstrating that alkali metal silicides can recover greater than 50% of residual oil. Results also show that alkali metal silicides can provide accelerated oil production, as much as 20% faster than comparable chemical technologies.
Technical Implementation and Benefits of Use of Produced Water in Slickwater and Hybrid Treatments in the Bakken Central Basin
Authors: Griffin Larry , Poppel Ben , Siegel Joel , Weijers Leen 
Published: June 2014

Abstract
The Bakken boom in North Dakota has been well documented. From a development perspective, the majority of the acreage has been drilled with an initial well to hold the acreage and the emphasis has shifted to infill drilling. As the development progresses, the industry seeks to apply more sustainable practices which includes the recycling of produced water. A number of efforts are underway to consider the use of produced water for well stimulation, and the economics are expected to improve with infrastructure such as central gathering systems. From an economic and environmental point of view, reuse of produced water in the Williston Basin is a sustainable practice to conserve water and save on well completion cost.
A number of technical challenges accompany the application of produced water in well stimulation including stimulation design, execution, and effectiveness. Considerable attention is required regarding fluid chemistry including stimulation additives, guar-based gels, crosslinkers, and friction reducers (FRs) used in slickwater. For example, properties of friction reducers change considerably in the light of the high salinity of Bakken produced water. Effective friction reducers are critical for slickwater jobs that are pumped at high rates of 70 bpm and the early slickwater stages using in hybrid fracs (combination of gel and slickwater). Achieving that high rate is key to effectively divert fluid flow and maintain sufficient rate to transport proppant in a long lateral.
This paper provides insight into the effectiveness of using produced water into slickwater designs in the Bakken petroleum system. The work discusses screening of various experimental and commercial FRs to determine their individual effectiveness with fresh water and produced water. The efficiency of a few tested FRs is then measured in actual field treatments, and we conduct a comparison of the frictions measured in field and lab to provide a methodology for proper comparison of the two, enabling a reasonable forecast of frictions measured in the lab to pipe frictions expected under field conditions.
An Integrated Approach for Developing and Applying Multiple PVT Model Zones in Thermal Compositional Reservoir Simulation
Authors: Yang Zhengming , Urdaneta Alfredo 
Published: June 2014

Abstract
The South Belridge Opal-A diatomite reservoir is under waterflood and steamflood development. Laboratory measured compositional and viscosity data, API gravity distribution from commingled produced oil, as well as field production performance all suggest the existence of more than one oil type: light oil (29°API) and intermediate gravity oil (22°API), regionally separated by faulting. Accurate PVT and viscosity models are essential for use in thermal compositional reservoir simulation to quantify two major steam flood mechanisms: oil distillation and viscosity reduction. It is a challenge to develop PVT models with limited laboratory measurements of the initial, limited-interval, oil samples. Validation of legacy compositional measurements against mol-fraction distribution vs. SCN (Single Carbon Number) is critical for obtaining a meaningful PVT property model. A new approach of developing viscosity temperature relationship for each pseudo component based on PVT property modeling, and the use of the ASTM viscosity model with limited high temperature viscosity measurements is proposed. Integrated investigation of faulting from static geological modeling and API oil gravity measurements from commingled produced oil and sidewall core oil samples were used to define the boundary of two PVT regions. Waterflood and steam flood project responses were analyzed to assess the impact of fluid types (light or intermediate oil) on waterflood and steam flood performance. Field-scale reservoir simulation of both waterflood and steam flood processes demonstrate the success of applying the new approach for field-scale multiple PVT model zone studies.
Characterizing the Oil Reservoirs in the Uinta Basin
Authors: Merkel Richard , Lessenger Margaret 
Published: June 2014

Abstract
Oil reservoirs in the Uintah Basin are extremely complex and have to be considered in the ‘Unconventional’ category. This is partially because of the lacustrine depositional environment which resulted in numerous self-sourcing reservoirs that vary greatly in wettability and mineralogy (very clastic to very carbonate). Analysis of these reservoirs is compounded because of the low porosity/permeability, high paraffin content, and natural fracture distribution. Standard log analysis to determine OIP has proved problematic. As a result, a more unconventional logging suite to examine fluid distribution and properties is being employed.
This paper presents some of our findings in the understanding of the liquid hydrocarbon distribution. Only then are we able to determine efficient primary production techniques as well as flow characteristics for secondary water-flood projects. Because of the discontinuous nature of the reservoirs, we have found that some intervals are most economically produced with vertical wells while others are best produced with horizontals.
The viscosity of the oil is highly temperature dependent because of the high paraffin content. The viscosity is also dependent upon asphaltine content which is present in the ‘black’ wax oil component. Fortunately, with new NMR techniques and continuous logging, the in-situ viscosity of the oil can be estimated. The NMR log is also used to differentiate between solid hydrocarbon (kerogen) and the liquid component. Dielectric measurements provide us with a water volume estimate that is essentially independent of the water salinity. This is particularly valuable in the water-flood area of the reservoir to determine remaining oil and residual oil saturation.
Petrophysical results from the open-hole logging that are calibrated to core are used in combination with core flooding experiments to feed into reservoir models. Fluid flow characteristics in this complex environment are measured at in-situ conditions through proper petrophysical analysis of core and logs.
Cost-Efficient Well-Head Purification of Produced Water using a Humidification-Dehumidification Process
Authors: Balch R. S. , Muraleedharan S. 
Published: June 2014

Abstract
The objective of this research was to design, build, and test a desalination unit for produced water purification at the wellhead, yielding water clean enough for beneficial uses, while reducing the waste stream requiring disposal. A low-temperature distillation / humidification dehumidification (HDH) process was designed and constructed to meet requirements of energy efficiency and high tolerance to inlet water chemistry. Through the process, water is evaporated at an elevated temperature (175°F/80°C) in a flowing air stream, followed by cooling and capillary condensation resulting in the collection of purified water. The average treatment cost of produced water purification with this method was estimated, after successful field demonstration, to be $0.31/bbl when co-produced or solar heating was used. In contrast the cost of transported disposal of can reach and exceed $2.50/bbl.
After bench scale testing a prototype of the low-temperature distillation unit with desalination capacity of 30 barrels/day was designed and constructed. Produced water purification was then demonstrated at a gathering site provided by industry partner Harvard Petroleum Co. LLC and the technical and economic feasibility of the process was evaluated. After the field demonstration of the HDH process, experimental results indicated that ∼20% of the processed water was purified in each pass through the system and that adding the concentrate back into the inlet stream of the HDH unit did not subsequently impact efficiency of the process. Salts, minerals, and dissolvable organics in the produced water were removed efficiently by the process: the total dissolved solids (TDS) were reduced to less than 200 mg/L for inlet TDS as high as 250,000 mg/L, and the total organic carbon was reduced from 470.2 to 17.83 mg/L. The purified produced water is of suitable quality for beneficial uses, such as agriculture, irrigation and industrial processes. The system not only processes water economically, but also does not require the significant use of fossil energy that conventional desalination plants require to preheat water. The portable nature of the unit and the fact that it can be located at a wellhead or at a field gathering site reduces transportation costs, a major cost factor.
A Generalized Rheological Model for Drilling Fluids Using Cubic Splines
Authors: Bui Binh T. , Tutuncu Azra N. 
Published: June 2014

Abstract
In drilling fluid rheological characterization and hydraulics modeling, selecting a proper rheological model and obtaining rheological parameters using viscometers are critically important. Bingham Plastic, Power Law, and Yield Power Law are the most commonly used standard models for drilling fluid rheology since they are mathematically simple to implement. However, due to the complex nature of drilling fluids, these models do not often fit well to the rheological data. This leads to a significant error in drilling fluid hydraulics modeling. While searching for models based on the physical interaction between the various components of the drilling fluid, it is very practical to find simple mathematical functions that best fit to any experimental data obtained from field viscometers. This will improve the accuracy of hydraulics modeling, in particular for time dependent drilling fluids.
In this research, cubic splines have been used to fit the experimental data obtained from field viscometers. A generalized hydraulics model is presented to calculate pressure drop in pipe and concentric annulus with detailed sample calculations. A numerical simulator has also been developed to assist the calculations. The results obtained from the model have been validated with experimental data to verify the effectiveness of the proposed model.
The model introduced in this paper is the generalized form of all the other commonly utilized models and can be implemented for any fluid. The main advantage of the model is that it can capture all the complex rheological response of the fluid. Hence, all readings obtained from the viscometers can provide valuable input for the hydraulic model. Also, the numerical solution is stable and straightforward to implement. The model provides drilling engineers a simple and powerful method to accurately predict the pressure distribution along the wellbore. This is highly important in drilling fluid hydraulics program optimization and well control operation, especially in deep-water and arctic environments.
Completion Optimization Utilizing Multivariate Analysis in the Bakken and Three Forks Formations
Authors: King Victoria Martinez , Wray Laura 
Published: June 2014

Abstract
Completion optimization has been a key factor for ensuring an economic well in the Williston Basin. In North Dakota, most completion information is public after three to six months unless the wells are confidential. This enables operators to closely monitor offset completion and production performances. The goal was to optimize well economics through analyzing completion parameters. The area of interest for this analysis was confined to the Fort Berthold Indian Reservation and surrounding acreage in North Dakota.
Public and internal completion, reservoir and geologic data was gathered, interpreted, and used as inputs for the multivariate statistical analyses. These analyses were designed to understand the impact that both reservoir quality and completion design parameters have on production. The multivariate tool, coupled with quality checked and carefully interpreted data, has aided in understanding how sensitive well performance is to these parameters, as well as how these variables behave. This tool provided an analytic method to determine what parameters and their ranges are most critical to good production.
This paper will elaborate on the following high sensitivity completion and reservoir parameters and their behaviors: lateral length, proppant volumes, stage lengths (plug to plug or sleeve to sleeve), proppant type, treatment rate and water cut. The completion parameters were easily controlled by frac design, but additional analysis and review was needed to better understand the causes of high water cut. An understanding of completed reservoir (Middle Bakken or Three Forks) water saturations, job size, and geologic anomalies was critical in understanding and predicting this negative reservoir parameter.
This information was combined to predict the performance of various completion designs without having to invest the capital in large field tests. Economic analysis was then done using the cost of the respective completion design and expected performance. The optimized completion design was derived, in part, from the multivariate analyses and is currently being field tested.
Acoustic Techniques to Monitor and Troubleshoot Gas-Lift Wells
Authors: Taylor C. , Rowlan L. , McCoy J. 
Published: June 2014

Abstract
The distance to the fluid level provides beneficial information throughout the life of a gas-lift well. From the initial unloading of the well, to maintaining production, and even into troubleshooting the well, the location of the fluid level plays a crucial role in understanding the well's performance.
Some of the most valuable fluid level shots occur during the unloading process, when the fluid level is compared to the gas injection depth. Fluid levels can be used to help determine whether a problem is occurring within the wellbore or due to equipment malfunction. A quick surface measurement determines valves below the fluid level are not injecting gas. Finding holes in the tubing string and location of any restrictions in the tubing or casing help identify problems impacting production. During a workover, monitoring the fluid levels of a well filled with kill fluid ensures sufficient hydrostatic pressure is maintained against the formation. In gas-lift wells without a packer, producing bottomhole pressures can be accurately measured using an acoustic fluid level instrument. Bottomhole pressure information is useful in designing and operating gas-lift installations and measuring overall producing efficiency1.
Examples of fluid level shots on gas-lifted wells will be used to demonstrate these concepts. Acoustic fluid levels acquired on gas-lift wells provide a low cost, direct method to observe the well and benefit the operator through knowledge of the well's producing conditions.
Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses
Authors: Barree R. D. , Miskimins J. L. , Gilbert J. V. 
Published: June 2014

Abstract
Over the last twenty years, Diagnostic Fracture Injection Tests, or DFIT's, have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic fracture treatment parameters. Thousands are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results due to either problematic data acquisition or incorrect analysis of the acquired data.
This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided including data resolution, pump rates, test duration, and fluid selection. Rules of thumb are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis.
The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight gas and shale reservoirs due the long data acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor ISIP data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after closure analysis.
Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance: Application to the Marcellus and Haynesville
Authors: Ouenes A. , Aissa B. , Boukhelf D. , Fackler M. 
Published: June 2014

Abstract
To reduce our dependence on microseismic data which is only available in about 5% of the shale wells, a recently developed workflow based on "hard" Geophysical and Geological data is used for the estimation of SRV and its varying rock properties in a reservoir simulator. This workflow relies on the use of the concept of Shale Capacity which encompasses the four key shale drivers responsible for most of the factors affecting the shale well performance: TOC, Brittleness, Fracture Density and Porosity. The shale capacity is available over the entire 3D reservoir volume and is estimated from well and seismic data.
The SRV varying enhanced permeability is estimated through the use of a variable Half fracture length, a radial function and the shale capacity thus providing a realistic distribution and values to the reservoir simulator. Using appropriate gridding techniques such as the Tartan grid for the SRV cells, near-wellbore effects are accounted for along with no-Darcy effects and gas desorption in the shale reservoir. With these key factors represented in the dynamic model around the well, a Haynesville gas, water rate and pressure was successfully matched without the need for any major history matching effort. The resulting irregular and asymmetric SRV region and pressure distribution takes into account the geologic variability which has major implication on the EUR and well spacing. When comparing the EUR estimated from the derived geologically constrained model and those computed from traditional decline curve analysis, shale operators could be booking reserves that could be 50% lower than the actual ones. Finally, the spacing of the laterals could be optimized by taking into account the resulting irregular and asymmetric pressure distribution around the shale wells.
Environmental Responsibility of Current Proppant Solutions
Authors: Fuss Tihana , Shi Jingyu , Ma Jun , Herndon Daniel C. , Stephens Walter T. 
Published: June 2014

Abstract
The hydraulic fracturing industry recognizes two primary proppant types: sand and man-made (ceramic) proppants. Selecting the right proppant for a well focuses on the mechanical strength and conductivity of proppants under down hole (application) conditions. Since proppants are generally stable under high temperature, high pressure conditions, their environmental impact on well completion is often considered minimal. However, with recent increases in proppant consumption, mass of proppant used on a well site can now easily reach 6 million pounds. Transportation, storage and handling of such high volumes of any material pose an environmental challenge. This study compares the environmental impact of three different types of proppants: sand, lightweight kaolin clay proppants and intermediate density bauxite proppants, and proposes best practices to minimize risks.
This study first investigates dust generation associated with transportation, handling and storage of proppants. Results show that attrition of all tested proppant types generates dust. Chemistry, morphology and health hazard ratings of crystalline species present in generated dust are compared across variety of proppant types. Best practices for dust control are discussed.
Secondly, study focuses on natural radioactivity of current proppant products and compliance with state waste disposal NORM regulations. Study compares levels of detected natural radioactivity in proppants based on their type, geographic origin and detection method used. Costs associated with waste disposal of these materials are compared for several different states.
Complexities Associated with Thermal Stimulation of Low Gravity Oil Sands Using Horizontal Wells
Authors: Qi Q. , Zhang Q. , Ershaghi I. 
Published: June 2014

Abstract
Among the complex issues associated with recovering extremely viscous oil (API &lt; 5 degree) using CSS; we focus on two important factors. First is a feature of these reservoirs with water lenses imbedded or overlain on top of the oil column. Next is the issue of optimum well completion method to uniformly deliver steam, enhance productivity and reduce steam requirements. The option of using CSS with horizontal wells to avoid water lens effects is compared to that of recovering such oil deposits using CSS in vertical holes. We computed expected responses for scenarios that included spot heating or distributing steam along the entire lateral of the horizontal well. For comparison purposes, we computed expected recoveries using horizontal vs. vertical completions for such ultra-viscous oil systems and compared with benchmark data from number of field historires of CSS for somewhat lighter heavy oil reservoirs.