bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Use of Low-Cost Graphite Nanomaterials to Enhance Zonal Isolation in Oil and Gas Wells
Authors: Peyvandi A. , Taleghani A. Dahi , Soroushian P. , Cammarata Ryan 
Published: October 2017

Abstract
One of the key challenges encountered in cementing the casing in oil and gas wells is the failure of the cement sheaths due to low tensile strength and toughness resistance of the cement sheath. To enhance the mechanical and durability characteristics of cement sheaths, low-cost graphite nanoplatelet (GnP) employed as a nano-scale reinforcement. GnP offers many of the highly desired mechanical, physical, geometric and stability characteristics of carbon nanotubes (CNTs) at substantially reduced cost. Experimental studies were implemented to evaluate the complementary effects of low-cost graphite nanomaterials in oil and gas well cement sheaths. Experimental results highlighted the balanced gains in diverse engineering properties of cement slurry by introduction of GnP. As a nano-scale reinforcement system, GnPs were found to significantly control the crack propagation and improvement in mechanical attributes of Zonal Isolation. The planar geometry of GnPs makes them to be effective in improvement of durability characteristics of cementitious paste.
Spatial and Temporal Relationships between Produced Gas and Water in Marcellus through Data Mining Analysis
Authors: Zhou Q. , Wang J. Y. , Xiao Y. , Kleit A. 
Published: October 2017

Abstract
The relationship between produced gas and flowback/produced water is important for evaluating shale gas well performance; however, it is not fully understood yet due to complex flow mechanisms and interactions / feedback among various geoscience and engineering controls. Further investigation would provide valuable insight to adjust development plans to achieve optimal well/regional economic production.
In this study, an auto-updated nonlinear model method was applied to evaluate the relationship between water and gas in different spatial and temporal domains and to understand the micro-scale flow mechanisms from macro-scale data. Fracture-fluid flowback data in the dataset are water produced within one month, following a fracture treatment (exclusive of well shut-in time), and the produced water were 1 to 3 years. 114 wells from the Marcellus Formation in northwestern West Virginia were selected to investigate the relationship between fracture-fluid flowback and one month gas production in different spatial domains (wet and dry gas regions). 67 Marcellus wells in Lycoming County, Pennsylvania were selected to study the relationship between produced water and gas production across different time periods ranging from one to three years. The results indicate that the relationship between gas and fracture-fluid flowback in the wet gas region is positive while negative in the dry gas region. WGR (water gas ratio) is high (&gt;9 bbl/mmcf) during the 1st-year which indicated water be carried out through displacement and leveled off at 3 bbl/mmcf after the 1st-year, indicating evaporation is the primary mechanism for water production. This study analyzed the relationship between gas and water production under different geological conditions and time periods and offers new insights on gas and fracture-fluid/produced water flow mechanisms in shale gas reservoirs.
Post-Combustion CO2 EOR Development in a Mature Oil Field: Model Calibration Using a Hierarchical Approach
Authors: Olalotiti-Lawal Feyi , Onishi Tsubasa , Kim Hyunmin , Datta-Gupta Akhil , Fujita Yusuke , Hagiwara Kenji 
Published: October 2017

Abstract
We present a simulation study of a mature reservoir for CO2Enhanced Oil Recovery (EOR)development. This project is currently recognized as the world's largest project utilizing post-combustion CO2 from power generation flue gases. With a fluvial formation geology and sharp hydraulic conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multi-decadal production data at different temporal resolutions into the available geologic model. This will be useful for understandingflow units, heterogeneity features and their impact on subsurface flow mechanisms to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.
Our strategy consists of a hierarchical approach for geologic model calibration incorporating available pressure and multiphase production data. The model calibration is carried out using regional multipliers whereby the regions are defined using a novel Adjacency Based Transform (ABT) accounting for the underlying geologic heterogeneity. To start with, the Genetic Algorithm (GA) is used to match 70-year pressure and cumulative production by adjusting pore volume and aquifer strength. Water injection data for reservoir pressurization prior to CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of over 7 million cells is reparametrized using a set of linear basis functions defined by a spectral decomposition of the grid connectivity matrix (grid Laplacian). The parameterizationrepresents the permeability distributionusing a few basis function coefficients which are then updated during history matching. This leads to an efficient and robust workflow for field scale history matching.
The history matched model provided important information about reservoir volumes, flow zones and aquifer support that led to additional insight to the prior geological and simulation studies. The history matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area which will be utilized for studying the impact of fine-scale heterogeneity on CO2 sweepand oil recovery. The uniqueness of this work is the application of a novel geologic model parameterization and history matching workflow formodeling of a mature oil field with decades of production history and which is currently being developed with CO2 EOR.
Effect of Fluid Type and Multi-Phase Flow on Sand Production in Oil and Gas Wells
Authors: Wang Haotian , Gala Deepen P. , Sharma Mukul M. 
Published: October 2017

Abstract
It has been shown in controlled laboratory experiments and some field studies that the onset of sand production in gas wells differs from that in oil wells. Results from a general 3-D sand production model are presented to explain the differences in the onset of sanding and sand production volume for different fluids and under different flow and in-situ stress conditions. The sand production model accounts for multi-phase fluid flow and is fully coupled with an elasto-plastic geomechanical model. Sanding criteria considers both mechanical failure and sand erosion by fluid flow. Non-Darcy flow is implemented to account for the high flow rates. The drag forces on the sand grains are computed based on the in-situ Reynolds number. Both the intact rock strength and the residual rock strength depend on water saturation. Water evaporation (drying) due to gas flow is modeled using phase equilibrium calculations.
The onset of sand production is compared for different fluid types (oil and gas). Model results are shown to be consistent with experimental observations reported in the literature. For example, the onset of sanding is observed at higher compressive stresses for gas wells as compared to oil wells. Theprimary mechanism for this is for the first time shown to be sand strengthening induced by evaporation of water. This effect is not observed in oil wells. The sand production rate when non-Darcy effectsareconsidered is lower than for Darcy flow. The reason for this is the lower fluid velocity (for the same drawdown) and consequently smaller drag forces on the failed sand grains. The effect of water breakthrough and water cut on sand production is studied from both mechanical and erosional perspectives. The model is shown to be capable of accurately predicting the onset of sanding and sand production induced by multi-phase and compressible fluid flows, helping us to predict sanding issues in both oil and gas wells.
Employing Effective Water Treatment in West Texas to Mitigate Surface Equipment Failures
Authors: Kakadjian Sarkis , Solomon Marvin , Nwachukwu Raymond 
Published: October 2017

Abstract
Effective bacterial control is a key component of a successful fracturing stimulation. Currently water sources can have extremely high levels of aerobic and anaerobic bacteria that can lead to chemical degradation, microbial induced corrosion (MIC) and souring of wells due hydrogen sulfide generation. Oxidative biocides are widely used per rapid kinetics of disinfection with the capability to provide good control of bacteria loadings with short residual lifetimes.
This paper reviews steps taken to mitigate failure in fluid cylinders and flow iron surfaces that come in contact with the fluids, causing them to degrade much quicker than the normal expected life when used oxidative biocides. Premature failures of fluid ends and iron missiles are capital intensive for most hydraulic fracturing companies in the current oil and gas market. In the duration of 2 months in summer 2016, there was an unsustainable increase in maintenance costs by an estimated USD 4 million for two fracturing fleets. MIC and overtreatment of water with chlorine dioxide have been implicated in this premature failure of iron surfaces.
The water treatment process was implemented in the field in summer 2016. The mitigation process involves pretreating produced water with chlorine dioxide with no residual, which is then complemented with conventional biocides and combos for longer term bacterial control at the start of each job. Water samples of the circulating fluids are taken every 2 hours to get the relative light unit (RLU), which determines the proper timeframe for retreating the water on location. RLU values were also correlated to typical sulfur-reducing bacteria (SRB) and acid-producing bacteria (APB) levels in West Texas.
The water treatment process, with continuous monitoring, implemented over a 3-month period dramatically increased the life of stainless steel fluid ends and missiles from the 300 pumping hours and 5 months respectively. Further analysis of the effectiveness of the treatment is conducted later when the equipment is retired.
Development of a Smart Fracturing Fluid for Tight and Unconventional Reservoirs
Authors: Mohammed Marwan N. , Mahmoud Mohamed , Elkatatny Salaheldin 
Published: October 2017

Abstract
Massive hydraulic fracturing is the only method to have economic production from unconventional resources (i.e. tight sandstone and shale gas reservoirs, etc.). Tight permeability reservoirs represent around 60% of global unconventional resources, they have large quantities of hydrocarbon, and with their impaired permeabilities, hydraulic fracturing is the most promising technique dealing with those types of reservoirs. A typical fracturing fluid usually consists of a cross-linked gel system, buffer, clay and gel stabilizers, biocide, and a breaker among many other constituents, all to prevent damage resulting from such operations, or better yet, enhancing the formation beyond the aim of a fracturing operation.
This paper introduces a new zero leak-off, smart fracturing fluid system for tight formations and conventional resources as well. The fluid system consists of GLDA chelating agent that has the abilities of a cross-linker, breaker, biocide, clay stabilizer, replacing those constituents in one simple fluid, GLDA is also a low IFT fluid which will reduce the IFT eliminating the water blockage problems due to the capillarity effect in tight reservoirs. It is also stable in high temperature reservoirs (up to 300°F), environmentally friendly and readily biodegradable. The effect of temperature, pH, shear rate, polymer concentration and GLDA concentration on the rheological properties of the new fluid system has been studied, as well as the thickening-breaking time and efficiency, thermal stability of the developed fluid system.
The new fracturing fluid formulation can withstand up to 200°F of formation temperature and stable for about 6 hours under high shearing rates (511s−1), with polymer concentration ranging from 20 to 70 pptg with the optimum being 45 pptg at pH 12, the viscosity building and breaking time can be controlled by the concentrations of the constituents.
Coreflooding experiments were conducted using Scioto and Berea sandstone cores to evaluate the effect of the developed fluid on the core permeability and to investigate the zero leak-off property. The flooding experiments were in conformance with the rheological properties of the developed fluid regarding the thickening and breaking time as well as yielding high return permeability (85-89%).
Mapping the Natural Fracture Network in Marcellus Shale using Artificial
Authors: Mohaghegh S. D. 
Published: October 2017

Abstract
Contribution of Natural Fracture Network (NFN) to the productivity of shale wells is a well-established fact. So much so that it is widely believed throughout the industry that all other things being equal, the presence and the extent of Natural Fracture Network in shale determines the productivity of a shale well. While deterministic mapping of the NFN in shale through direct measurements is not an option, stochastic techniques are used to generate NFN to be used in numerical simulation. Among tools used to provide some indication of NFN in shale are wellbore image logs and seismic surveys. However, limitations of these tools for this purpose is well documented. In this paper, we present an alternative technique that makes use of a large number of field measurements and incorporates artificial intelligence in order to generate NFN map in shale.
In this technique Artificial intelligence, infers the presence and the extent of the NFN from well productivity. Parameters that impact the productivity of shale wells are: well construction … trajectory, reservoir characteristics, completion, stimulation/hydraulic fracturing, and operational conditions (wellhead pressure, choke size). Natural Fracture Network falls under the category of reservoir characteristics. In this approach Artificial Intelligence uses 12 measured parameters representing the volume of fluid available for production and operational conditions as well as completion and hydraulic fracturing practices to infer the presence and the extent of NFN.
These field measurements are analyzed on a well by well basis to generate a dimensionless score for the presence and the intensity of the NFN that are then mapped throughout the reservoir using geo-statistics. Through two case studies, we demonstrate that the discrepancies in correlation between reservoir, completion and frac job parameters and the well productivity can be explained through the presence and the extent of the Natural Fracture Network.
The results of this process is (a) a distribution map of the presence and the extent of the Natural Fracture Network throughout the reservoir and (b) a large number of examples with detail comparisons between wells that justify the generated map.
A Comprehensive Evaluation of Alkaline Surfactant Polymer Flooding and Hybrid Process for Enhanced Oil Recovery
Authors: Dang Cuong , Nghiem Long , Nguyen Ngoc , Chen Zhangxin , Yang Chaodong , Bae Wisup 
Published: October 2017

Abstract
This paper presents recent advances in the subject of modeling and optimization of ASP (Alkaline, Surfactant and Polymer) flooding with: (1) a critical review of the state-of-the-art development of ASP flooding; (2) an efficient and accurate novel approach for ASP modeling for robust simulation of chemical processes in conjunction with oil, gas, and water flash calculations using an equation of state (EOS) simulator; (3) systematic validation of the new modeling approach with laboratory studies; (4) evaluation of a hybrid Low Salinity ASP recovery process; and (5) robust optimization of ASP field-scale design under geological uncertainties.
We used a new approach that can model the behavior of the surfactant-oil-water-microemulsion system based on solubility data. In the Type III system, the emulsion is distributed judiciously between the oil and water phases without the need to introduce a third liquid phase. This model captures most of the important physical and chemical phenomena in the ASP process. The model was then validated with numerous coreflooding experiments conducted by different research institutes as well as with a specialized chemical flood simulator. The newly proposed model is tested using different injection schemes and chemical formulations including negative salinity gradient, non-negative salinity gradient, and a series of benchmark coreflooding experiments. Excellent agreements between the model and the experiments in terms of oil recovery and pressure drop were achieved for all corefloods. In addition, the model was also proven to be highly consistent with both UTCHEM-EQBATCH and UTCHEM-IPHREEQC. More importantly, previous results obtained without the explicit modeling of Type III indicated that the recovery factor deviates significantly from the experimental data, whereas the pseudo two-phase approach in this paper gives an excellent match in all cases. This model has also been successfully applied to match the recovery of Alkaline-CoSolvent-Polymer flooding, which is a promising recovery approach.
We investigated the potential of hybrid low salinity ASP flooding in which Low Salinity Waterflooding (LSW) was implemented in secondary production and followed by ASP flooding. This approach can provide a superior performance compared to the conventional chemical flooding because it provides better oil recovery in the secondary stage and promotes the synergy between low salinity environment and ASP slugs. Finally, the proposed robust optimization workflow helps to increasea project NPV and significantly reduces the uncertainty range associated with geology.
Offline Temporary Abandonment, Deepwater DVA
Authors: Hosli C. , Shannon S. , Boyle R. , Stein D. 
Published: October 2017

Abstract
The decommissioning of wells and restoration of natural subsurface barriers which prevent hydrocarbon flow to surface, is a critical activity in well life which removes environmental impact for the future after oil/gas production facilities have been removed. Despite reduced rig/equipment costs, abandonment continues to be a substantial expenditure and represents a significant liability for operators in a cash constrained environment. While we see many efforts to reduce scope of abandonment and workover operations, engineered design and execution must comply with regulations as defined in the Code of Federal Regulations (CFR) without compromising safety.
Abandonment and workover activities in the deepwater Direct Vertical Access (DVA) environment are typically conducted with a platform installed rig. However, there exists a significant amount of work involved in rig workover activities (cement plug installation, tubing cutting, circulation to workover fluid, etc) which do not require the physical workover unit itself and therefore can be accomplished "offline" both to save rig days, cost, personnel exposure, etc. In this context, "offline" will be defined as the time associated with activities that may be accomplished without dedicating critical path rig time to abandonment scope, reducing time and cost, assuming this identified rig would not otherwise be idle. Saved time may be used to provide value in a number of capacities from drilling and completing new wells to working over or abandoning another well.
This paper discusses the case histories of two wells accessible via a deepwater Tension Leg Platform (TLP) in the Gulf of Mexico (GoM), both of which were scoped for conventional producer zonal abandonment and recompletion/workover activities. One would be worked over to another target production zone ~7000’ up-hole while the other would be worked over and converted into a new field injector for a major water flood project in the region. Through meticulous pre-planning, engineering design, and contingency development, the engineering and operations teams working on these two wells were able to reduce the critical path time of the work unit by realizing offline opportunities.
These activities utilized conventional intervention techniques of slickline, electric line, and available pumping to both abandon these wells in an unconventional manner and ready the wells for immediate tubing pull once the rig was skidded atop. This was all done with full compliance with the CFR, in a "through-tubing" method, and satisfied abandonment conditions and operational safety requirements of the operator. While both wells noted significant savings either to acceleration of operation timeline or of first oil, the work conducted required decisive challenge management to succeed. The engineering decisions made, scope reductions identified, and trouble time events incurred will be discussed to the detail possible in this manuscript.
Enhancing Performance and Operational Safety of Argentinean Vaca Muerta Shale Wells by Drilling High Pressure Formations Using Managed Pressure Drilling
Authors: Pozo Mariano , Torres Fabian , Bedoya Jorge , Leroy Jean Christophe , Montilva Julio 
Published: October 2017

Abstract
An unconventional shale gas drilling project in the Rincon de la Ceniza onshore field is being developed to reach the Vaca Muerta formation, which is overlaid by the shallower and troublesome Quintuco formation. This formation is composed of two over-pressurized layers located in the middle and near the bottom of the formation. The Lower Quintuco formation may also be naturally fractured, containing oil and gas, trapped in an over-pressurized regime, creating an operational drilling hazard. Pore pressure prediction has a high degree of uncertainty, making the proper mud density selection a difficult task. Offset wells drilled conventionally have incurred significant Non Productive Time (NPT) due to well control events, where accurate kill mud weight definition has been challenging due to the presence of natural fractures.
The objective for the drilling campaign was to define an optimal and reliable drilling method that would address the challenges of pore pressure uncertainty in a safe and cost-effective way. The first step was to implement Managed Pressure Drilling (MPD) to control over-pressurized zones and determine the more suitable mud density to control the well. The previous vertical wells were drilled conventionally having Quintuco and Vaca Muerta formations isolated from each other with two different casing strings.
The drilling strategy was redefined and implemented in three horizontal wells, but in this time both formations were drilled together in one hole section. The intention was to enable drilling with the minimum mud weight possible, allowing higher Rate of Penetration (ROP) consequently. This was possible to achieve by maintaining constant bottom hole pressure conditions at variable Anchor Point depths along the open hole while drilling Quintuco formation. Before drilling the horizontal section in Vaca Muerta formation, a small and controlled constant underbalanced condition was created and fixed at the deepest Anchor Point depth which was as close as possible to the transition zone between both formations.
This successful strategy allowed improving drilling performance, by reducing drilling time from 123.4 to 51.7 days per well and reducing NPT from 30.5% to 7.5% by managing well control events, eliminating one casing string and improving drilling efficiency to increase the ROP. Consequently, the cost of the well was reduced 5.5 MM USD/well when compared with the last well of the campaign without any Health Safety and Environment (HSE) issues.
This paper presents the drilling strategy followed to overcome well control events and associated NPT when drilling an unconventional shale gas play with highly uncertain pore pressure profile. Planning, implementation and results from the project are presented.