bluuebunny/crossref_metadata_2025_split huggingface dataset:
Eagle Ford Huff-and-Puff Gas Injection Pilot: Comparison of Reservoir Simulation, Material Balance and Real Performance of the Pilot Well
Authors: Orozco Daniel , Fragoso Alfonso , Selvan Karthik , Aguilera Roberto 
Published: October 2018

Abstract
A comparison is made of real data from an Eagle Ford huff-and-puff (H&P) gas injection pilot with reservoir simulation and tank material balance calculations. The comparison is good and supports the conclusion that oil recovery from the Eagle Ford (and likely other shales) can be increased significantly with the use of H&P.
The study is based on the container methodology: for H&P to work, the injected gas and the insitu oil in the shale must be contained vertically and laterally following hydraulic fracturing. Containment is critical for the success of H&P. Vertical and lateral containment exist in the Eagle Ford as demonstrated previously (Fragoso et al., 2015) with the upside-down distribution of fluids: natural gas is at the bottom of the structure, condensate in the middle and oil at the top. Two different matching and forecasting approaches are used in this study: reservoir simulation and tank material balance calculations.
Results show a good history match of primary recovery and secondary recovery by H&P in the pilot well. The history match is good in the case of both reservoir simulation and tank material balance calculations. Once a match is obtained, the simulation and material balance are used to forecast secondary recovery over a period of 10 years with sustained H&P injection of dry gas. Results indicate that dry gas H&P can increase oil recovery from the Eagle Ford shale significantly. Under favorable conditions, oil recovery can be doubled and even tripled over time compared with the primary recovery. The addition of heavier ends to the H&P gas injection can increase even more oil recoveries, putting them on par with conventional reservoirs. The benefit of H&P occurs both in the case of immiscible and miscible gas injection. The H&P benefits can likely be also obtained in other shale reservoirs with upside-down containers for dry gas, condensate and oil.
The novelty of the work is the combined use of reservoir simulation and tank material balance calculations to match performance of an H&P gas injection pilot in the Eagle Ford shale of Texas. The conclusion is reached that oil recoveries can be increased significantly by H&P.
Asphaltene Gradients and Connectivity Analysis in Reservoirs, Asphaltene Onset Pressure, Bitumen and Tar Mats All Treated Within a Simple, Unified Chemistry Treatment
Authors: Mullins Oliver C. , Dumont Hadrien , Forsythe Julia C. , Chen Li , Achourov Vladislov , Meyer John , Johansen Yngve Bolstad , Rinna Joachim , Winkelman Ben , Wilkinson Tim W. , di Primio Rolando , Elshahawi Hani , Canas Jesus , Betancourt Soraya S. , Pomerantz Andrew E. , Zuo Julian Y. 
Published: October 2018

Abstract
Asphaltenes can be dispersed in crude oils in 3 different forms; molecules, nanoaggregates (of molecules) or clusters (of nanoaggregates); these forms are codified in the Yen-Mullins model and relate to the extent of solvency of the asphaltenes in the crude oil. Many reservoir studies are used here to show the systematic behavior of the specific asphaltene species in crude oil and the corresponding magnitude of the asphaltene (and viscosity) gradients. In addition, the specific asphaltene species is related to the chemical origin controlling asphaltene onset pressure (AOP) and tar formation and depends on 1) the quality of the live crude oil solvent for asphaltenes and 2) the concentration of asphaltenes. Elevated quantities of solution gas of a reservoir crude oil significantly reduce the solvency of asphaltenes in crude oil. For low concentrations and/or good solvency, asphaltenes are dispersed in crude oils as molecules with small gradients (unless there are large GOR gradients). For moderate concentrations and/or moderate solubility, asphaltenes are dispersed as nanoaggregates with intermediate (gravity) gradients of asphaltenes. With large concentrations and/or poor solvency, asphaltenes are dispersed as clusters with very large gradients in reservoirs. These crude oils can also exhibit higher asphaltene onset pressures and/or phase separated bitumen or tar in the reservoir depending on the origin of asphaltene cluster formation. Secondary gas charge into oil reservoirs can yield tar and/or a high AOP. The effect of biodegradation on these factors is also discussed. The systematics presented here are helpful in understanding a variety of reservoir concerns associated with asphaltenes.
Ultra-Light Weight Proppants for Better Placement
Authors: Bestaoui-Spurr Naima , Li Chunlou 
Published: October 2018

Abstract
As well construction technology enables ever-longer horizontal reach, the challenge increases for proppant placement in hydraulic fracturing operations. Effectively placing conventional proppants (sand and ceramic) in extended-reach wells requires either high pump rates or high-viscosity fluids and are subject in both cases to early proppant settling and banking. Even when heavily gelled fluids are used, proppant suspensions are subject to particle settling in the presence of vibration, and/or due to fracturing fluids breaking before the fracture closes. Furthermore, the fractures are typically vertical; and in this case the proppant has a tendency to settle in the lower portion of the fractures while the upper portions close in the absence of proppant. This can lead to impairment in the geometry of the fracture and well productivity. Using proppant with much lower densities than that of conventional proppant will provide better transport. Another benefit from these ultra-lightweight proppants (ULWP) is the elimination of polymer damage with the use of low-polymer or slick water fluid systems, enabled by their extremely slow settling rates.
Since the mid-2000s, ULWP has been used in over 3000 wells to overcome placement and settling challenges. Taking advantage of low-viscosity fluids, ULWP have been used as nearly neutral buoyant proppant; thus, minimizing settling within the created fracture and leading to a better placement. In this study, the hydraulic treatment and production data of those wells treated with ULWP and offset wells were carefully reviewed. Main production metrics are calculated to evaluate the production performance.
Case Study: Apache's Approach to Societal Responsibility thru the Environmental Media Monitoring Program for the Alpine High Play
Authors: Behl Navneet , Bohm Brian , Bruton Marcus , Fleming Steven , Vance Steven 
Published: October 2018

Abstract
A baseline environmental media monitoring program is presented. Analytical data sets collected by third party contractors at the request of Apache Corporation are presented. The analytical data presented documents the environmental condition of groundwater, surface water, soil, and ambient air, within an area with sensitive environments supporting multiple endangered and threaten species, recently being developed as oil and natural gas exploration and early development. The area of the study is a previously undeveloped portion of the prolific oil and gas development area of the Permian Basin. The baseline environmental media monitoring program occurred over an area of approximately 78 square miles in southern Reeves County, Texas. The analytical data provides interested stakeholders a starting data set for comparison to future environmental conditions, allowing parties to assess if there are changes in the environmental media and if those changes vary from natural seasonal variations.
Deployment of Liner Systems in Extreme High Mud Weight Environments in Gas Wells
Authors: Oqaili A. H. , Alluhaydan A. S. , Ezi P. C. , Tirado A. E. 
Published: October 2018

Abstract
During the development phase of a gas field, the abnormal pressure in a dolomitic limestone formation demanded an extremely high mud weight to control the well. The casing design of this case-study field has entailed the installation of a 7″ × 9-5/8″ liner hanger in combination with a liner top packer followed by a tieback to surface. Due to this hole section being directly above the pay zone, it is crucial that the liner installation and the wellbore integrity are not compromised for the subsequent well completion.
The downhole pressure conditions require a drilling mud weight up to 157 pcf (~ 21 ppg), where solids content could reach as high as 49% using conventional weighing materials. For a liner deployment, this means that the high concentration of solids can cause plugging in the setting ports of conventional hydraulic liner hanger and running tool system. Additionally, the thin balance between ECDs and the formation fracture pressures in this field generated events of severe fluid loss during the liner deployment or while cementing. A liner not fully supported by cement — due to severe fluid loss during cementation — can experience ballooning, and be unable to withstand piston forces acting against the liner top packer during well completion operations. These forces can, in some cases, exceed the ratings of the liner top packer's hold-down slips, therefore allowing the packing element of the liner top packer to not set properly.
For these reasons, an optimized deployment strategy was planned and implemented to address these challenges. It included improvements to the hydraulic liner hanger and running tool system, calculations to simulate an optimal running speed of the liner, enhanced procedures for liner deployment and cementation, including revised setting procedures for the liner hanger slips, and modifications to drill pipe wiper plug design.
The objective of this paper is to detail the benefits of implementation, detailed pre-job planning, improvements for optimal drilling mud properties and modifications to the liner hanger system, and procedures that resulted in successful deployments of liners in this field. In addition, a case study will be shared as a way to institute lessons learned and best practices.
A Novel X-Ray Based High Pressure Mass Flow Rate Sensor for MPD Operations
Authors: Singhal Vivek , Ashok Pradeep , Oort Eric van , Park Paul 
Published: October 2018

Abstract
Managed Pressure Drilling (MPD) allows one to drill through formations with narrow pressure windows, thereby making those formations that cannot be drilled with conventional techniques accessible. It also provides the capability for early detection and safer handling of well control events. This technique requires accurate estimation of the annular pressure profile and the delta mass flow rate. These measurements can be improved through accurate density and mass flow rate measurement at the high pressure (7500 psi) input side of the well. Since no good metering technologies exist to make these measurements, the objective was to develop a high pressure density and mass flow rate sensor.
A comprehensive review of all existing flow rate and density measurement instruments suggested that an X-ray based sensor was the best option for the high pressure fluid line. Multiple experiments were conducted to determine the electrical power range (voltage and power) for the X-ray tube that would work best for mud between densities in the range of 8 to 20 ppg. Experiments were then conducted to test the accuracy and feasibility of techniques developed for density and volumetric flow rate measurement. Based on these experiments, an X-ray source and detector were identified and a sensor was designed for inline use on 4 inch pipes. Two approaches were developed to estimate density using the sensor. The first was an empirical approach where sensor gray level values were directly mapped onto mud density values though in laboratory experiments. These mappings can then be used in the field to estimate density. The second was a model-based approach that estimates density based on the Beer Lambert's law. Both these approaches were tested experimentally using drilling muds of different densities and compositions.
A mechanism that uses X-rays to determine volumetric flow rate was also designed and tested using both simulations and experiments. A real-time calibration subsystem had to be added to the sensor to preserve measurement accuracy and precision over time. Based on encouraging results from simulations and experiments, a laboratory prototype was built and is currently undergoing flow loop tests. This is the first time an X-ray mass flow rate measurement sensor has been designed to be used on high pressure lines. Preliminary findings indicate that no existing sensors used for similar applications can match the measurement accuracy and frequency that may be offered by this technology. Development of this sensor would improve the safe drilling of complex wells with narrow drilling windows.
Effect of Anisotropic Fault Permeability Alteration on Pressure Transient Behavior
Authors: Molina Oscar , Zeidouni Mehdi 
Published: October 2018

Abstract
Compartmentalized reservoirs are often segmented by a sealing fault acting as a barrier to pressure communication between neighboring reservoirs. However, changes in reservoir pressure, due to either fluid withdrawal or injection, can induce changes in local stresses that can lead to fault slip and associated alteration of fault permeability, which can transform the initially sealing fault into partially conductive.
This paper examines the transient pressure response to a sudden change in anisotropic fault permeability as an indicator of fault seal breakdown. Analytical solutions for pressure-transient response for a line-source, constant-rate well in a compartmentalized reservoir where fault permeability is rapidly enhanced, are presented. The fault is modeled as a linear interface between semi-infinite homogeneous and isotropic formation layers. Laplace-Fourier transform technique is used to solve the governing equations analytically. Pressure-transient solutions are presented as type curves for the scenarios of across-fault and simultaneous across-along-fault permeability enhancement. Characterization of enhanced fault transmissibility using asymptotic late-time solutions is discussed.
Seismic Lithofacies for Static Model Building and STOIIP Calculation in Bioturbated Shallow Marine Environments
Authors: Baharuddin Saira Bannu , Khair Hani Abul , Bekti Reza Amarullah , Ali Amita Mohd , Kantaatmadja Budi , Som Mohd Rapi , Sedaralit Faizal 
Published: October 2018

Abstract
Bioturbated zones are frequently bypassed by oil and gas operating companies during perforation due to the perception that they are non-productive. We analysed data from wells in four fields in the Sarawak Basin, Malaysia, for selected bioturbated zones. The study included thin section, probe-permeameter, petrophysical, and routine core analysis. A bioturbation index classification scheme was established to allow semi-quantitative ranking for each foot of core.
In the current study, we introduce a simulation script to predict lithofacies types at well locations based on input from bioturbation intensity algorithm (Ali et al., 2016), this script can be used for application on shallow marine field within Malaysia.
We also used post stack seismic inversion for acoustic impedance and it proved to be a key approach to enhance the ability of predicting rock properties between wells. We generated a seismic derived lithofacies which provided the best estimate of lithofacies distribution between wells even though a well derived lithofacies had higher resolution. We calculated STOIIP using input from seismic lithofacies and porosity, and the results showed more accurate estimate of hydrocarbon in place compared with statistical approaches. Thus, the current seismic lithofacies methodology can be used for static model building and STOIIP calculation in shallow marine environments.
Cellulose Nanocrystal Stabilized Emulsions for Conformance Control and Fluid Diversion in Porous Media
Authors: Pandey Aseem , Telmadarreie Ali , Trifkovic Milana , Bryant Steven 
Published: October 2018

Abstract
Nanoparticle stabilized emulsions have drawn increasing attention for applications in various industries including enhanced oil recovery (EOR). Unlike surfactants, nanoparticles provide long-term stability to the emulsions and significantly higher viscoelastic response. However, the flow behavior of nanoparticle stabilized emulsions in porous media has not been explored much. Cellulose Nanocrystals (CNCs) have gained attention in the past few years since they are an abundant renewable biomass-derived material. This study investigates the flow behavior and stability of oil in water emulsions stabilized by CNCs in unconsolidated porous media and the application of these emulsions in EOR and conformance control.
Confocal Microscopy coupled with Cryo-SEM enabled us to precisely characterize the emulsion microstructure and correlate it to the rheological behavior of the emulsions. The rheological measurements revealed that a strong droplet network forms within the emulsions over time. Importantly, we show that the same network forms when the emulsions occupy pore space in a granular material. Emulsions were injected through a sandpack with a porosity of 35% and average pore diameter of 54 μm. The injected emulsions were aged inside the porous media for 24 hours. Thorough experimental assessment of the collected effluent samples revealed that the emulsion was stable. The porous medium was then subjected to a gradually increasing pressure gradient of either water or oil. Gradients greatly exceeding typical near-well values (&gt;300 psi/ft) were required to establish flow, and the resulting flow rate exhibited a pressure gradient three orders of magnitude higher than in an untreated water saturated sandpack. Interestingly, a significantly larger gradient was needed for water to flow than for oil, raising the possibility of using this class of emulsions for selective phase blocking, and perhaps as relative permeability modifiers. Moreover, emulsions stabilized with other material allowed water to flow at very small gradients, confirming that the network formation is critical for this application.
This study revealed the potential application of a naturally occurring biodegradable nanomaterial for conformance control and for curbing excessive water production where zonal isolation is difficult to achieve.
What Happens after the Onset of Liquid Loading? — An Insight from Coupled Well-Reservoir Simulation
Authors: Tang Hewei , Chai Zhi , He Youwei , Xu Boyue , Hasan A. Rashid , Killough John 
Published: October 2018

Abstract
Liquid loading is an inevitable production issue for mature gas fields. A varied group of phenomena after the onset of liquid loading has been observed in field, including the natural cyclical production of liquid loaded wells. Most previous modeling studies focused on predicting the onset of liquid loading. The production behaviors after the onset of liquid loading is equally important and requires strict modeling techniques to simulate dynamic interactions between wellbores and reservoirs.
In this paper, we apply a newly developed fully implicitly coupled well-reservoir simulator to systematically investigate the well behavior after the onset of liquid loading. The model honors the mass and momentum balances in both reservoir and wellbore systems, and thus allows us to analyze both wellbore and reservoir dynamics after the onset of liquid loading. The simulation results indicate that there exist a gas-water coproduction period and a zero liquid production period after the onset of liquid loading. For reservoir permeability as low as 0.1md, the liquid-loaded horizontal well might experience natural cyclical production after the onset of liquid loading, which coincides with field observations. Both uniform stimulation and multi-stage hydraulic fractures help mitigate the production phenomenon. The near-wellbore reservoir pressure build up and wellbore fluid reinjection are also evaluated. This work demonstrates the successful application of the coupled wellbore reservoir model in predicting the rich production phenomena of stimulated horizontal wells after the onset of liquid loading.
Formation Evaluation, Economic and Environmental Assessment for the Slurry Injection for Biosolids Management in the City of Houston
Authors: Panchal Yashesh , Mohamad Ibrahim , Abou-Sayed Omar , Abou-Sayed Ahmed , Bruno Mike 
Published: October 2018

Abstract
A strong economy, industrial base, and low cost of living have led to a significant rise in population in the Greater Houston Metropolitan area of Texas, and with it, an increase in production of sewage and biosolids wastes. In the Houston area, sewage is treated with a combination of anaerobic digestion and lime stabilization to create biosolids which are then pelletized into fertilizer, composted, landfilled, or land applied.
The Slurry Injection technique is an alternative treatment and disposal method, that can replace much of the capital costs associated with maintaining and expanding the wastewater treatment infrastructure in Houston at significantly lower capital cost. This technique utilizes the principles of Drill Cutting Injection which has been implemented in petroleum industry since mid 1980s for oil and gas waste management. A biosolids slurry injection facility of sufficient capacity to dispose of all the biosolids currently produced by the city of Houston could be installed for less than 1/10 of the nearly $526 million in capital currently budgeted by the city to expand the current system under the current rolling 5-year plan. A substantial reduction in greenhouse gases is achieved as well, by using the slurry injection technology as the Carbon Dioxide and Methane (which are prominenet greenhouse gases) produced by biosolids degradation is completely sequestered under deep geological formation and along with it the emissions produced during dewatering and transportation of biosolids is also eliminated.
The City of Los Angeles’ Terminal Island Waste Water Treatment Plant facility has deployed the slurry injection technology since 2010. It currently disposes of approximately 20% of biosolids of the city of Los Angeles.
This paper describes the economic and environmental aspects related to biosolids management and the formation evaluation carried out to inject the bioslurry in greater Houston. The study includes both the economics of the surface construction requirements as well as the science behind the subsurface strata evaluation for containment assurance. For the subsurface aspects, a geomechanical and stress analysis is performed on two different formations (the Frio and the Vicksburg). A significant confining layer is present above and below our targeted injection zones, which restrict and assure the injected waste remains contained. Also, hydraulic fracture simulation and analysis provides an assurance and the waste containment within the engineered subsurface strata/formation for permanent storage.