bluuebunny/crossref_metadata_2025_split huggingface dataset:
Doctrines and Realities in Reservoir Engineering
Authors: Vittoratos Euthymios , Kovscek Anthony 
Published: April 2017

Abstract
Doctrines often develop with minimal empirical support. This observation is clear in reservoir engineering for heavy and viscous oils. Our objective is to develop a deeper appreciation of the empirical realities to permit improvement of depletion plans and thereby enable projects that are deemed uneconomic by the application of the misleading doctrines. Accordingly, this paper reviews the evidence for and against three doctrines in current use to develop depletion plans: (i) optimal recovery is obtained using a voidage replacement ratio (VRR) of 1, (ii) the Buckley-Leverett formulation applies uniformly to heavier oils, and (iii) viscous fingering dominates unstable multiphase flows.
Of primary importance is the doctrine that optimal waterflood response is obtained for a VRR of 1 both on an instantaneous and cumulative basis. A VRR of 1 is mandated in some regulatory jurisdictions and accepted unconditionally by many large oil companies. In the last decade, however, empirical, laboratory, and simulation investigations have demonstrated that, particularly for heavier oils, periods of VRR &lt; 1 significantly increase the oil recovery and reduce water production. Optimal voidage management increases oil recovery by an amount similar to a variety of EOR techniques at minimal cost.
A second doctrine is that the multiphase flows within the reservoir occur via the slipping of phases past each other, as formalized by the Buckley-Leverett formulation. Again, empirical and laboratory evidence demonstrates that in many cases two-phase flow occurs by emulsification of one phase, e.g., injected water disperses as small micron size droplets within a continuous oil phase. Such emulsion flows yield results that contradict current doctrines; e.g., decline curves are not monotonic but have steps associated with the type of emulsion. Likewise, the efficacy of polymer flooding is independent of polymer concentration after it exceeds the minimum value needed to support emulsification of water into the oil. These novel predictions have considerable commercial value.
Finally, viscous fingering is often attributed to the instability of flow when the displacing phase (water) has a viscosity smaller than that of the displaced phase (oil). Though elegant mathematical formulations explain such unstable flows under idealized laboratory conditions, the reality is that slow pressure diffusion within heavy oils is the originating factor in channelized reservoir flows because commercial injection rates cause altered porosity distributions that initiate the preferential path flow.
The appreciation of the empirical realities permits improvement of commercial depletion planning and enables a greater number of projects. These concepts are applicable in almost all heavy-oil reservoirs; they may also be applicable for lighter oils that possess oil chemistry that is typical of heavier oils, e.g., high acid content.
Investigation of Rheological and Filtration Properties of Water-Based Drilling Fluids Using Various Anionic Nanoparticles
Authors: Salih A. H. , Bilgesu H. 
Published: April 2017

Abstract
As sensitive and electro-chemically active additives, anionic nanoparticles can be used to develop various water-based mud designs to fulfill different drilling conditions with less costs. For an optimum performance, however, they must be carefully selected and formulated. The objective of this study was to compare and evaluate various properties of water-based nanomuds. This was achieved by investigating the impact of very low concentrations of commercially affordable three types of negatively charged nanoparticles on the rheological, hydraulic and filtration properties of a high pH "flocculated" water-based mud. Simultaneously, the superior and insufficient types and concentrations were explored.
In this research, four concentrations of each of anionic nanosilica, nanotitanium, and nanoaluminum were used to treat the high pH (11.5-12) water-based mud. Sequences of API experimental tests were conducted by using standard Low Pressure Low Temperature (LPLT) filtration and rheological devices for all samples. For the hydraulic evaluation, a commercially available software was used to simulate the impact of the nanoparticles on the equivalent circulation density (ECD) and the drillpipe circulation pressure in a typical directional well.
The results show significant improvements in the rheological and hydraulics properties of the flocculated water-based muds treated by 0.1% wt. or less of nanosilica and 0.3% wt. or less of nanotitanium and nanoaluminum. For the higher concentrations, no more improvements were obtained. Further, the results show the ability of nanosilica and nanotitanium to reduce the filtration volume and no filtration reduction based on nanoaluminum. However, all the nanoparticles enhance the mudcake structure, but differently, and prevent the spurt water loss completely.
The current nanoparticle types can be used to develop a qualified mud design, thereby reducing drilling problems, such as stuck pipe, formation damage, wellbore instability, downhole equipment failure, mud circulation loss, and shale swelling if they are properly formulated. Thus, the more complicated wells can be drilled by using water-based nano muds and by eliminating the high costs and bad environmental impacts of using oil-based muds.
IOR Methods in Unconventional Reservoirs of North America: Comprehensive Review
Authors: Alfarge Dheiaa , Wei Mingzhen , Bai Baojun 
Published: April 2017

Abstract
Unconventional resources have played a significant role in changing oil industry plans recently. Shale formations in North America have huge oil in place, 900 Billion barrels of recoverable oil in Bakken only. However, the predicted primary recovery is still low as less than 10%. Therefore, seeking for improved oil techniques to increase oil recovery in these complex plays is inevitable. In this paper, three stages of review have been combined to find out the applicability of the most feasible IOR methods in these unconventional reservoirs. Firstly, the most common fluid and rock properties of these reservoirs have been investigated and extensively discussed. Secondly, a comprehensive review has been conducted on most of published experimental studies, simulation works, and pilot tests which were performed to examine the applicability of different IOR methods in these unconventional plays. Finally, the performance of different IOR methods in pilots tests have been compared with experimental and simulation observations. These comparisons between field scale approaches (Pilot tests) and lab experiments have been used to diagnose the gap beween what had been reported from lab works and what happened in the field tests.
This study found the integration method of different tools such as experimental, simulation, and pilot tests is the proper technique to accurately diagnose the most feasible IOR methods in these poor-quality reservoirs. This research found that CO2, surfactant, and natural gas are the most applicable IOR methods in these unconventional reservoirs. CO2 injection seems the most feasible technique among the reported IOR methods. However, this study found that there is a clear gap between lab-works conclusions and pilot tests performance. This gap mainly happened due to the misleading predicting for that diffusion mechanism would be the most dominant mechanism for CO2 in field conditions due to the pre-reported lab observations. However, pilot tests performance generaly denied any significant role for diffusion mechanisim on CO2 performance. Furthermore, although pilot tests indicated that injectivity problem is not a big obstacle in these unconventional reservoirs, most of the evidences explained that the improvement in the observed injectivity was due to Injection Induced Fractures (IIF) which are the main reason for conformance problems which happened in the reported pilot tests. The slow imbibition rate of surfacatant methods in these types of reservoirs might impair their potentinal success. Pilot tests apparently approved success of natural gas due its high compressibility and avialbility in these fields. Finally, this work specifies the most common problems which could face the most potentional unconventional IOR methods in field applications. Also, this study recommended new directions to be considered for fututure investigations on applicability of some IOR methods in these plays since they are more complex and very different from conventional formations.
On Estimation of Horizontal Well Effective Lateral Length and Reservoir Properties from Well Test Data
Authors: Qi Qianru , Bethel Katarina , Ershaghi Iraj 
Published: April 2017

Abstract
One of the ways suggested in the literature to estimate effective reservoir properties when drilling horizontal wells is by pressure transient testing. Various analytical solutions published provide the interpretation path for analyzing such tests. Our study shows that using the analytical tools to estimate horizontal wells could be subject to significant errors if there are uncertainties about the effective length of the lateral. In this study, we examined situations where horizontal wells were designed given certain reservoir properties and the inverse estimation of parameters, using currently available analytical tools, showed significant errors. This is attributed to the nonlinear nature of analytical equations which result in multiple combinations of answers. In actual cases, analytical equations may be insufficient to represent complex real horizontal well trajectories. We show multiple examples using the direct modeling of horizontal wells and demonstrate the non-uniqueness of solutions obtained from analytical models when there are uncertainties about the effective lateral length.
Application of Pressure Transient Analysis and 4D Seismic for Integrated Waterflood Surveillance- A Deepwater Case Study
Authors: Suleen Fnu , Oppert Shauna , Chambers Geordie , Libby Lauren , Carley Shane , Alonso Daniel , Dygert Todd , Olayomi Joe 
Published: April 2017

Abstract
A practical application of pressure transient analysis (PTA) and 4D seismic for monitoring movement of flood fronts and determination of hydrocarbon saturations in a waterflooded reservoir is presented. A novel workflow for quantitatively integrating 4D seismic data with PTA is described. At the injectors, pressure falloff tests were analyzed to reveal the progression of the flood fronts by using analytical radial composite models. Seismic interpretations of flood fronts were incorporated and refined in the numerical PTA model to examine flood front anisotropies. Sensitivity analysis with numerical PTA of the 4D interpreted flood fronts reduced uncertainties in their size, shape and location. Analytical and numerical PTA techniques were used to determine the range of pressure-saturation conditions in the reservoir at the time of the monitor seismic survey that could explain the lack of 4D signal around the producers. Unique multiphase effects were observed in producers - like the appearance of artificial "humps" in the derivative - which were explained by means of numerical models with gas saturation gradients. Results from the integrated 4D-PTA approach reduced uncertainties in the predicted pressure and saturations around the injectors and producers. The results from these techniques can be used to improve reservoir characterization and reduce uncertainties in remaining reserves. The integrative workflow can lead to upgrades in the reservoir-management strategies, increasing the realized economic value of both PTA and 4D technologies. Application of the integrated PTA-4D techniques allow for early field intervention and optimized placement of development wells.
Reinterpretation of Fracture Closure Dynamics During Diagnostic Fracture Injection Tests
Authors: Zanganeh B. , Clarkson C. R. , Hawkes R. V. 
Published: April 2017

Abstract
A fit-for-purpose, fully coupled stress-pore pressure simulation model (Abaqus®) is used to simulate diagnostic fracture injection tests (DFITs) and generate before closure pressure responses. The simulated responses are used to explain field observations, and to propose a new concept: progressive fracture closure.
The cohesive zone model (CZM) is used to model fracture propagation and closure associated with DFITs. The customized model in Abaqus® is capable of modeling all the physical processes involved in a typical DFIT including: porous media deformation? fluid flow inside the reservoir? hydraulic fracture initiation, propagation and closure? compliance change before and after closure; residual fracture conductivity? and fluid flow inside the fracture and fluid interaction between the fracture and reservoir (leakoff).
A key result obtained is that the previously-introduced fracture compliance method is demonstrated to be the most reliable approach to identify fracture closure. Depending on the pressure distribution around the fracture, the closure pressure is usually found to be higher than the minimum principal stress. Based on the continuity equation, the compliance method is expanded to include the progressive fracture closure (PFC) concept. PFC refers to the scenario where fracture closure occurs gradually along the length of fracture, from the tip of the fracture to near the wellbore. Different estimates of closure pressure will be obtained early and late in this process. Several field cases are presented which exhibit progressive fracture closure. A consistent closure signature can be identified for these cases using the primary pressure derivative. This study further suggests that wellbore storage can mask the closure signature. Therefore, reducing the wellbore storage effect by using downhole shut-in makes it easier to identify fracture closure, in addition to accelerating the test.
A common DFIT fracture closure referred to as "fracture height recession" is reinterpreted to be caused by the PFC phenomenon. This finding has tremendous implications for interpretation of before closure flow regimes and associated reservoir behavior. This study also confirms that the compliance method, which corresponds to fracture tip closure, provides more of a true measure of closure pressure than conventional approaches which correspond to fracture closure near the well.
Testing and Calibration of a Low-Cost Custom Geomechanical Properties Testing System
Authors: Sultan U. , Saini D. 
Published: April 2017

Abstract
In this research project, functionality, and repeatability of a low-cost custom geomechanical properties testing system that had been built for studying the mechanical behaviors of hydrocarbon bearing reservoir rocks and overlying seals, was tested and calibrated. For this, unconfined uniaxial compression tests were performed for generating transvers microstrain and axial microstrain curves for two standard metals namely aluminum and copper. The experimentally measured Poisson's ratio values were compared with the published values. The results were found comparable.
The experimental work conducted in this project has provided an opportunity to fine tune the experimental procedures needed for performing uniaxial and reservoir condition triaxial testings of the representative samples of reservoir and overlying cap rocks of potential geologic CO2 storage sites. Such expermients will greatly assist in determining the ability of potential geologic CO2 storage sites in California in storing injected CO2 in safe and effective manner.
Optimization of Steamflooding Heavy Oil Reservoirs
Authors: Suhag Anuj , Ranjith Rahul , Balaji Karthik , Peksaglam Zumra , Malik Vidhi , Zhang Ming , Biopharm Frontida , Putra Dike , Energy Rafflesia , Wijaya Zein , Dhannoon Diyar , Temizel Cenk , Aminzadeh Fred 
Published: April 2017

Abstract
Conformance improvement is the key to success in most enhanced oil recovery (EOR) processes including CO2 flooding and steamflooding. In spite of technical and economic limitations, foam has been used as dispersions of microgas bubbles in the reservoir to enhance mobility. Steam-foam has numerous applications in the industry, including heavy oil reservoirs, which are a significant part of the future energy supply. Steam-foam applications have been used to prevent steam channeling and steam override, thus improving overall sweep efficiency, in both continuous steam and cyclic steam injection processes. The objective of this study is to investigate the key components of this complex process, where relatively high temperatures are recorded, in order to have a robust understanding of chemistry and the thermal stability of surfactants.
The efficiency and therefore economics of the steam-foam process are strongly reliant on surfactant adsorption and retention. This requires a good understanding of the process for effective sizing of the foam injected. In this study, a commercial reservoir simulator is used where surfactant transport is modeled with surfactant availability and is determined by a combination of surfactant adsorption, surfactant thermal decomposition, and oil partitioning due to temperature. The degree of mobility decrease is interpolated as a result of factors that contain aqueous surfactant kind and concentration, the presence of an oil phase, and the capillary number. An empirical foam modeling method is employed with foam mobility decrease treated by means of modified gas relative permeability curves.
The simulation results outline the sensitivity of these parameters and controlling agents, providing a better understanding of the influence of surfactant adsorption and thus, a number of chemicals to be used in an efficient manner. Optimum values for decision parameters that we have control on have been determined by coupling a commercial optimization software with the reservoir simulator. Uncertainty parameters such as surfactant adsorption have been analyzed in terms of significance on the recovery process.
Even though steamflooding is thoroughly studied in the literature, there is no recent in-depth study that not only investigates the decision parameters but also uncertainty variables via a robust coupling of a reservoir simulator and an optimization/uncertainty software that model use of foam in steamflooding. This study aims to fill this gap by outlining the optimization workflow, the comparison of parameters with tornado charts and providing useful information for the industry.
Temperature Transient Analysis for Characterization of Multilayer Reservoirs with Crossflow
Authors: Mao Yilin , Zeidouni Mehdi 
Published: April 2017

Abstract
Multilayer systems are widely encountered in underground hydrocarbon reservoirs. To obtain accurate multilayer properties and understand the flow behavior in a multilayer system, many testing and analysis procedures have been evolved. Recent developments on downhole temperature monitoring systems open new alternatives contributing to multilayer reservoir characterization. The progressing technique, temperature transient analysis, is developed to use the temperature data, which are unique for each layer in a multilayer reservoir.
In this work, we present an analytical solution to determine the individual layer temperature signal associated with constant rate production of slightly compressible fluid from a fully penetrating vertical well in a multilayer reservoir. The analytical solution development process involves identifying the late time individual layer production rates and applying the single layer transient temperature behavior, the results of which are benchmarked with those from the numerical simulation. The temperature signals are presented at the bottom-hole location and further into the reservoir for two-layered and multi-layered systems, for which each layer may be damaged or undamaged. The temperature profiles obtained from analytical solution shows excellent agreement with those from numerical simulation and are sensitive to layer permeability, porosity, and damaged zone properties. In addition, we provide semi-log temperature interpretation techniques to characterize the layer permeability and porosity, and damaged zone radius and permeability considering the availability of adequate data. The simplified characterization methods are also developed in the case of insufficient or inaccurate data to obtain permeability and production rate ratios between layers which helps to identify the layers contributing the most to well production.
Effect of in Situ Emulsification on Heavy Oil and Water Relative Permeability
Authors: Sarwaruddin Mohammad , Burzlaff Alan A 
Published: April 2017

Abstract
The objective of this paper is to provide reservoir engineers fresh insight and a new approach to the description of heavy oil and water relative permeability functions in reservoir simulation. This paper proposes a plausible mechanism of heavy oil flow in porous media influenced by the effect of water-oil emulsification to address the inability of simulation models to replicate primary oil production rates during cold producing operations.
A number of heavy oil reservoirs that naturally flow without stimulation show higher field oil production rates than often can be predicted by numerical simulation. To match the field production, reservoir simulation engineers often exhaust all valid parameter changes in the numerical model and resort to questionable changes on parameter values that usually enjoy high confidence level by physical measurements. To overcome these shortcomings, we first identify in situ water-oil emulsification, a plausible mechanism of heavy oil flow in water-oil systems, and then offer a practical approach to modeling water oil relative permeability for heavy oil-water systems.
Beyond water-oil relative permeability curve adjustments, the parameters that are changed by simulation engineers during reasonable history matching may consist of an unrealistic increase in oil saturation and/or a significant decrease in oil viscosity. Both parameters are usually measured in labs and should not be altered significantly. In addition, sometimes during simulation model calibration, the increase in absolute permeability goes so high that it cannot be supported by any logic or physical measurement.
The new relative permeability modeling approach for heavy oil and water systems considers the fact that naturally occurring heavy oil contains a large quantity of emulsifying agent and the density contrast between heavy oil and water is so low that heavy oil in porous media may flow by a continuous oil and stable emulsion phase. A part of the total oil flow occurs via oil phase that is similar to light oil and water system and the other part flow via a quasi-stable emulsion/water phase.
This practical approach for heavy oil water relative permeability modeling removes the difficulties that a simulation engineer often faces during heavy oil water history matching and calibration. The new modeling approach presented in this paper is successfully applied in modeling cold heavy oil production performance for a heavy oil reservoir in California. One field example is provided in this paper and some results are presented to estimate heavy oil water relative permeability from standard lab data.