bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lab Testing Cement-Steel Bonding at Shallow Temperature and Pressure Conditions
Authors: Wilson D. C. , Eustes A. W. , Fleckenstein W. W. 
Published: April 2018

Abstract
The Cohesive Zone Experiment (CZE), captured the effect of time, temperature, and pressure on the behavior of adhesive bonding between oilwell cements and casing. The CZE captured the behavior of bond failure as a function of displacement, showing the degree of compliance in the bond. Interpretation of the compliance behavior suggests an appropriate material property model of bond failure, suitable for mechanical FE analysis. The two failure models considered are the critical fracture energy (maximum area-specific energy) and the critical shear strength (maximum area-specific force).
Two Class G cement compositions were tested: a 15.8 ppg neat cement (Class G neat) and a 14.2 ppg gelled cement (Class G with 7% bentonite). The testing was done at temperature and pressure regimes designed to conform to environments typical to onshore surface casing shoe conditions, both shallow and deep. The neat cement is tested at conditions typically assumed at shallower surface casing setting depth (~600’ TVD): 92°F and 262 psi. The gelled cement was tested at conditions typically assumed at deeper setting depths (~1800’ TVD): 101°F and 786 psi. Each composition was tested at two hydration times: an early time of 4 to 6 hours and a late time of 22 to 24 hours.
The CZE results suggest cement at early hydration time (~5 hours) has a compliant bond. The adhesive bond of such an immature cement does not fail acutely when stressed to failure; the bond fails "intermittently" and retains some strength through displacement past the initial fracture. However, cements at late hydration time (~23 hours) do not show this compliance. The bond at late times fails acutely; displacement sufficient to initiate fracture is sufficient to fail the bond.
The compliant bond behavior observed at early hydration times should be modeled with a specific energy value: the critical fracture energy. The non-compliant bond observed at late hydration times should be modeled with a specific force value: the critical shear strength. Values for each property are reported from mean values observed in the CZE.
Investigation of Well Management on Hydrocarbon Recovery in Reservoirs With Pressure Dependent Permeability
Authors: Song Y. , Ehlig-Economides C. A. 
Published: April 2018

Abstract
Production rate and pressure transient data recorded in multiple transverse fracture horizontal wells (MTFHWs) suggested that well productivity is lost when wells are produced with excessive pressure drawdown. Pressure dependent permeability (PDP) may be a reason for this behavior. Moreover, in stress sensitive reservoirs, some models suggested that the pressure dependent permeability can result in productivity reversal. These models implied there is an optimum flowing pressure point which can lead to the maximum flow rate, and flowing at any other pressure will reduce the flow rate. The objective of this study is to discover how to quantify the inputs required to manage the well production.
This study is divided into two main parts. From the results of the first part, we learned that our simulation model can reproduce published results and can be used for the second part of the study. Using the model, we established that successive buildups must be acquired under different flowing pressures to provide meaningful results and can be used for permeability modulus estimation. We also learned that the behavior of the buildup transients distinctly depends on whether the pressure dependent permeability is mainly in the fractures or in the stimulated rock volume (SRV). Finally, we concluded that a rigorous model applying pressure dependent permeability phenomenon in space and time does not confirm the well management practices proposed in the literature. While these practices are likely well advised, PDP models do not justify them.
An Assessment of Model-Based Multiobjective Optimization for Efficient Management of Subsurface Flow
Authors: Fu Jianlin , Wen Xian-Huan 
Published: April 2018

Summary
The making of development plan to produce an oil or gas field usually involves several distinct stakeholders (e.g., the operator, partners and the government) with many engineering, economic, environmental, and/or political considerations. The interests of these stakeholders may be potentially in conflict with each other, entailing that a robust development plan should take into account all these concerns. Multiobjective optimization (MOO) can be used to find a set of optimal solutions (i.e., the so-called Pareto front) to balance all these interests. This work reviews and presents several typical applications of MOO to illustrate its value for efficient and robust reservoir management (RM) and asset development. These applications include: (i) simultaneous optimization of oil recovery and unwanted fluids, (ii) states-constrained optimization, (iii) short-term and long-term optimization, and (iv) optimization under uncertainty (OUU) for risk mitigation. Particularly, the MOO solution is compared with a conventional single-objective optimization (SOO) method in handling these problems. Results show that MOO is a solution of choice for comprehensive RM when a project involves optimizing multiple metrics or multiple drivers.
Comparative Simulation Study and Economic Analysis of Thermal Recovery Processes in Athabasca Reservoirs
Authors: Iyogun C. O. , Chen Z. 
Published: April 2018

Abstract
Simulation studies of three thermal recovery processes used in Athabasca reservoirs have been carried out for a 10-year production period. The recovery processes studied are Steam-Assisted Gravity Drainage (SAGD), Fast-SAGD, and Expanding Solvent-SAGD (ES-SAGD). Normal pentane (n-C5) was the solvent of choice used in ES-SAGD simulations with its molar concentration varied from 2% to 5.9%. The main objective of this study is to conduct an economic analysis of the three recovery processes with the goal of determining the most economically viable process. The economic indicator that will be assessed to ascertain the most viable recovery process is their Net Present Value (NPV.)
2D simulation studies based on homogeneous Athabasca reservoirs have been performed. Results obtained show that of the three recovery processes, Fast-SAGD had the lowest cumulative oil produced, followed by SAGD and ES-SAGD, the highest. The cumulative oil produced also increased with increasing molar concentration of n-C5. Furthermore, it was shown that as expected, the CSOR of ES-SAGD was the lowest of them while that of Fast-SAGD was the highest. The CSOR of the ES-SAGD processes reduced as the concentration of the n-C5 increased.
The economic analysis showed that of the three recovery processes, ES-SAGD is the most economically viable process. Furthermore, the effect of solvent on the viability of ES-SAGD over the other recovery processes is dependent on the price regime of pentane. In this analysis, two extreme price regimes were chosen and the result showed that for a low price regime, varying the molar ratios of n-C5 had a significant effect on the NPV up to a point before its effect diminishes. In fact, increasing the molar concentration of n-C5 from 2% to 3.76% significantly increased the NPV while further increasing it from 3.76% to 4% and thereafter to 5.9% had no noticeable effect. However, it seems that increasing it from 3.76% to 5.9% had a diminishing effect especially after the 3-year period. Nevertheless, the significant NPV improvement ES-SAGD has over SAGD and Fast-SAGD diminishes once the price regime of pentane is more than 3 times that of oil. In fact, this high price regime showed that 5.9% molar concentration of n-C5 is no longer more viable than the SAGD counterpart. There is still some benefit up till about 4% molar concentration of n-C5 but this benefit is greatly diminished.
In conclusion, ES-SAGD has been shown to be the best recovery process for Athabasca reservoirs based on economics but further research is needed to evaluate the molar concentration that will provide the most economic benefit for a real Athabasca reservoir.
Controlling Microwave Penetration and Absorption in Heavy Oil Reservoirs
Authors: Liao H. , Morte M. , Bloom E. , Huff G. , Hascakir B. 
Published: April 2018

Abstract
Microwave heating has great potential to recover heavy oil reservoirs, because it significantly reduces the heating time and consequently the cost of heavy oil extraction. Moreover, heavy crude oils contain high amounts of polar molecules (asphaltenes) and polar functional groups, making them great microwaving candidates. This study investigates the microwave effectiveness for a specific heavy oil reservoir focused on its polar components.
Furthermore, the impact of asphaltene precipitants and dispersants on microwave efficiency was investigated. A crude oil sample from Canada was subjected to microwave experiments for 30 seconds. Dielectric properties of the crude oil before and after exposure to microwave were mostly measured by using a vector network analyzer to quantify the overall polarity changes in the bulk crude. The impact of asphaltene precipitants (nC5 and nC7) and a dispersant (toluene) on microwave efficiency was also investigated. The crude oil sample was blended with nC5, nC7, or toluene at three varying doses (10%, 20%, or 50%) to investigate the impact of solvent dose on microwave efficiency. Microwave absorption and penetration depth were calculated to quantify the effectiveness of microwave heating.
It has been observed through dielectric property measurements that microwave energy was absorbed by mainly the asphaltenes. Dielectric constant and loss tangent values of the blends prepared with asphaltene precipitants (nC5 and nC7) and toluene were measured before and after exposure to microwave to quantify the microwave absorption in different blends. Although precipitant mixtures had higher dielectric constants, the dispersant mixtures had much higher microwave absorption due to higher loss tangents. This finding was further supported by penetration depth measurements, in which dispersant mixtures had lower values, which led to higher microwave absorption of the crude oil mixtures.
Microwave heating as a thermal enhanced oil recovery method is promising, however, complicated due to the uncontrollable nature of microwave penetration and absorption. This study reveals that while injection of an asphaltene precipitant to the desired reservoir locations can enhance the microwave penetration, injection of asphaltene dispersants will increase the microwave absorption. Cyclic injection of asphaltenes dispersants and precipitants may achieve the creation of effective heating spots within the reservoir by using only one microwave source.
Analysis of Critical Operational and Reservoir Parameters in Carbonate Acidizing Design
Authors: Safari R. , Fragachan F. , Smith C. S. 
Published: April 2018

Abstract
This work employs an integrated analysis method to quantify the impact of operational parameters and subsurface conditions on the acid stimulation efficiency of a carbonate reservoir. Examined parameters include reservoir type, completion design (initial skin), reservoir thickness, reservoir liquid properties (viscosity and compressibility), reservoir temperature, reservoir heterogeneity, acid type, acid volume, injection rate, and diversion technique.
In general, a combination of operational parameters and local geological conditions control the efficiency of carbonate acidizing. The operational parameters include acid type, injection volume, injection rate, and diversion technique. Optimizing these parameters maximizes stimulation efficiency and consequently hydrocarbon recovery. However, optimization needs to be evaluated within the context of local geology and subsurface conditions. For instance, the presence of natural fracture swarms or a high permeability zone along a limited length of the wellbore can present acid placement challenges that only advanced analysis can carefully address.
In our study, an integrated wellbore and reservoir model is used to simulate carbonate reservoir acidizing. The model first simulates the movement of stimulation fluid in a wellbore and couples it with transient reservoir flow. This analysis provides the distribution of reactive fluid along the well and calculates dynamics of skin evolution of a wellbore during stimulation. The model simulates the local change of injectivity and the interactions of different reservoir zones along the completed length of the well during stimulation time.
The analyzed results show that the interactions between wellbore flow and reservoir flow along the completed length of the wellbore is a dominant governing factor for stimulation efficiencies. It shows that at a limited volume of acid or low injection rate, most of the acid stimulates the upper sections of the reservoir while inadequate amounts of acid reach the bottom of the reservoir. The results show that the reservoir porosity system (i.e. porosity and permeability), pay-zone height, initial skin (i.e. completion design), reservoir temperature, and heterogeneity have governing effects on the optimum acid volume and injection rate. The reservoir condition might impose a wasteful acid volume and injection rate for a bullheaded treatment that can be optimized further with diversion technology. The latter situation being important in optimizing the volume of acid needed to efficiently stimulate the reservoir to obtain higher production.
Experimental Study on Oil and Solids Removal in Nutshell Filters for Produced Water Treatment
Authors: Rawlins C. H. 
Published: April 2018

Abstract
Nutshell filters composed of black walnut or pecan granular media are an established produced water treatment technology for tertiary oil removal. Guidelines for the size and operation of nutshell filters have evolved mainly by trial and error, with limited published operating data. This laboratory research program tested a nutshell filter to determine the operating flux limits (flow rate per unit area) that provide suitable oil removal performance. The separation efficiency target was defined as 5 ppmv oil in the outlet stream. The variables tested included medium type (black walnut shell or pecan shell), medium size, filtration flux, water salinity, and oil concentration. The flux limit for common 12/20 media is 12.0 gpm/ft2 for fresh water operation and 13.0 gpm/ft2 for saline water. Decreasing the medium size to 20/30 mesh increased the allowable flux limit but at the expense of a substantial increase in the pressure drop. Oil droplet penetration into the filter bed proceeds via a near plug-flow profile, with the top 18 inches of the bed providing 99% of the oil removal. Full breakthrough is a function of inlet oil concentration, with 20-30 hours of operation expected for a 48-inch-deep bed. Testing for removal of fine sand particles showed a average 5 µm separation size for 12/20 media at 13.5 gpm/ft2 flux.
A Cost-Effective Application of New Surfactant/Oxidant System to Enhance the Removal Efficiency of Oil-Based Mud Filter Cake
Authors: Zhou J. , Nasr-El-Din H. A. , Socci D. , Holcomb J. 
Published: April 2018

Abstract
Removing oil-based mud (OBM) filter cake is a difficult task. Low removal efficiency of filter cake may result in pay zone damage, including drilling fluid filtrate incompatibilities with reservoir fluids, fines migration, and undesirable change of permeability. This paper proposes a cost-effective and single-stage application of a new surfactant/oxidant system to enhance the removal efficiency of OBM filter cake.
A qualitative wettability experiment was performed to test wetting property of OBM emulsion before and after being cleaned by non-ionic surfactants. Phase behavior of the new surfactant/oxidant system was also shown when the variables were the concentration and type of coated persulfates. Filter press simulated various high-pressure/high-temperature (HP/HT) well conditions in laboratory to form and remove the OBM filter cakes. Average permeability ratio (Kfinal / Kinitial) of Berea sandstone disks was calculated by static filtration test to show the degree of formation damage.
Surfactant used in the new removal system ensures OBM emulsion to be water-wet and promotes it to flow more easily in contact with the rock surface. Coated persulfate can be circulated out of wellbore after the removal work, based on its low density and tightly coated property. HP/HT filter cake removal tests indicate the optimized new system can disperse and remove the filter cake by up to 98 wt% removal efficiency. The optimized surfactant/oxidant system affects the formation permeability slightly because Kfinal / Kinitial ratio is consistent in the 0.99~1.09 range.
With optimized formulation and soaking time, the cleaning solutions will benefit the oilfield industry significantly by removing OBM filter cake under challenging well conditions. Cost-Effective and single-stage application of the new removal system makes the oilfield industry more efficient and economical to remove OBM filter cake. The new surfactant/oxidant system minimizes the effects of drilling fluid on formation properties, based on its compatibility with OBM emulsions, quick removal steps, high removal efficiency, and acceptable Kfinal / Kinitial results.
A New Method to Assess Stimulation of Sandstone Cores Damaged by Fines Migration
Authors: Hanafy A. M. , Nasr-El-Din H. A. 
Published: April 2018

Abstract
Sandstone stimulation faces multiple challenges due to the heterogeneity of the formation and the sensitivity of its clay minerals. Fines migration results in lowering the formation productivity and complicates the stimulation process. Multiple field studies showed that treatment of fines migration is critical and can result in permanent damage of the wellbore. This study aims to locate, quantify, and describe the damage resulting of fines migration damage and its stimulation in sandstone formations and examine the impact of the clay content and its nature on the stimulation process.
This work is structured to evaluate the stimulation of fines migration damage in Bandera, Berea, and Kentucky sandstones. Fines migration was induced by injecting deionized water to trigger the mobilization of the clay minerals in the core. Both HCl or formic acid, and mud acid stages were injected following the fines migration induction. The new formation damage evaluation methodology utilizes computed tomography (CT) and nuclear magnetic resonance (NMR) scanning before and after the fines migration induction and its stimulation. The data from CT and NMR were combined and processed to generate a 3D representation of the cores pore structure, which gives an insight on how the clay nature impacts the stimulation process and the pore system.
The developed technique exhibited an excellent ability to visualize the core porosity distribution and the changes in the pore structure following the fines migration damage and the acid treatment. The 3D representation succeeded to assess the magnitude and the location of the formation damage due to fines migration and its stimulation. The injection of deionized water in the studied formations resulted in a different petrophysical responses, which came matching the prediction built on the mineralogy and porosity mapping using computed tomography data. These changes in pore structure prevailed as a controlling variable of the acidizing process. The stimulation of the damaged cores at 150 and 250°F resulted in the deposition of the alumino silicates toward the core outlet. These deposits are attributed to the acid leaching of the aluminum and iron ions from the alumino silicate structures. The high temperatures resulted in the deposition of alumino silicates closer to the injection point. The enhancement in permeability noticed in all of the studied formations showed to be due to the induction of narrow channels in between heavily deformed pore structures.
This work added to the sandstone stimulation technology a new tool to assess the true impact of acid stimulation on fines migration damage. The high level of resolution of tracking the changes in the pore structure lay the road to optimize the treatments to enhance the productivity and lower the cost. This technique has a potential as a formation evaluation technique to evaluate other types of formation damage, such as fracturing fluids and water blockage.
Detection of Fault Reactivation in Compartmentalized Reservoirs Using Pressure Transient Analysis
Authors: Molina Oscar M , Zeidouni Mehdi 
Published: April 2018

Abstract
A pressure transient model to detect fault reactivation is presented in this paper. The central assumption of the fluid flow model is that fault permeability gets suddenly altered upon fault slip. The fault is modeled as a linear interface segmenting an infinite, homogeneous and isotropic reservoir into two semi-infinite regions. A constant-rate well induces pressure changes in the reservoir by either fluid withdrawal or injection that lead to fault reactivation. The mathematical model is solved via integral transforms and the analytical solution is examined at the well with the purpose to find the characteristic bottomhole pressure and pressure derivative response to a fault slip event. Typical diagnostic plots and type curves used in well testing analysis are presented. A reservoir characterization approach summarizes the application of the model presented in this paper.
Reservoir Performance Optimization under Uncertain Future Development Plans
Authors: Jahandideh A. , Jafarpour B. 
Published: April 2018

Abstract
Optimization workflows have received considerable attention in oilfield management and development. A major difficulty in field development optimization is the significant uncertainty and risks from various sources, especially at the early stages of the reservoir life. While field development optimization under geologic and economic uncertainties have been studied and investigated in the literature, future development plans and their associated uncertainties have not yet been considered. In life-cycle optimization, reservoirs are likely to undergo extensive development activities in the future. Disregarding the possibility of future developments can lead to field performance predictions and optimization results that do not represent real field conditions. Alternatively, future development activities may be considered either as decision variables to optimize or as uncertain input parameters that must be accounted for. In many cases, even when future development activities are optimized, for a variety of (often unpredictable) reasons, the implementation in real field may not follow the optimized plan.
In this paper, we demonstrate that it is important to consider future development plans with their associate uncertainty when optimizing the field performance. We present stochastic formulations to account for the uncertainty in future development activities, necessitating the need to consider multiple possible development scenarios. Using stochastic optimization formulations, we optimize decision variables (e.g. well locations and operational settings) at the current stage of development while accounting for the uncertainty in possible future development plans. In this work, we assume that infill drilling uncertainty evolves over reservoir development stages as a discrete time stochastic process, resulting in a decision tree representation of future drilling scenarios. The performance of the developed stochastic framework is evaluated and discussed relative to existing approaches that do not account for future field development plans in the optimization procedure. The results show significant improvements in the production performance when the uncertainty in future field development planning is considered in the optimization problem. We conclude that incorporating the uncertainty in future development offers flexibility and robustness to accommodate alternative development options and can avoid solutions that significantly underperform when future reservoirs development (drilling) activities do not go as planned.