bluuebunny/crossref_metadata_2025 huggingface dataset:
Doctrines and Realities in Reservoir Engineering
Authors: Vittoratos Euthymios , Kovscek Anthony
Published: April 2017

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 < 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

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

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

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

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

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

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

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

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

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.
Errors in Prediction of Recoveries from Unconventional Resources with Analytical Methods that Ignore the Physics of the Flow
Authors: Jaiswal Aaditi , Alabdulbaqi Nibras , Alsafar Ali , Ershaghi I.
Published: April 2017

While in reality production from unconventional reservoirs with nanoscale pores and complex systems has caused a dramatic increase in oil and gas production, little is known about an effective characterization let alone prediction of long-term performance of individual wells. These systems challenge our classical understanding of petroleum reservoirs developed over decades. In the meantime, and the absence of a full understanding of the source rock systems, some practitioners have resorted to using reservoir engineering tools and techniques for production forecasting from source rocks. These toots borrowed from engineering principles of conventional petroleum reservoirs do not include the peculiar nature of the source rock systems. This, of course, is a long stretch going from applying conceptual models for uniform pore space occupied by hydrocarbons and water, to systems where fractures, microfractures, present significant complications to understanding the physics of the flow in source rocks. In summary, the realm of producing from source rock is one of those examples where before a better understanding of the rock physics is developed, already in different play areas, we have witnessed the phenomenal growth of drilling and completion of thousands of wells over the last decade.

Forecasting EUR (estimated ultimate Recovery) for individual wells producing from source rocks are essential in decision making at all levels. This is quite challenging particularly when only a few months of production data are available to predict the future. An urgent need in the industry has been using rapid methods for estimation of EUR's in the early life of any new well. These estimates have critical economic viability for business success and economic survival. To stay competitive and to provide attractive rates of return, companies prefer to drill in areas with the highest EUR's per well.

Among the techniques in widespread use are the decline curves. These simple regression models are used to estimate up-front guidance regarding total recoverable volumes over a long period. In practice, any forecasting can help to establish the resource base for individual wells and the entire asset. But the question is the validity of such forecasts. Decline curve analysis is based on empirical observations of production decline. In using decline curves, we assume that reservoir conditions and operating conditions causing the historical decline continue unchanged during the forecast period. In this study, we include well production with 5 or more years of history and examine various decline models using the early history data to test the estimated performance vs. the actual performance. We have noted serious limitations on the use of such models.
Integrated Reservoir Characterization of the Middle Bakken in the Blue Buttes Field, Williston Basin, North Dakota
Authors: Alexeyev Alan , Ostadhassan Mehdi , Bubach Bailey , Boualam Aldjia , Djezzar Sofiane
Published: April 2017

This paper discusses the methodology necessary for lithology identification and petrophysical analysis of an unconventional reservoir in Williston Basin. The scope of the work is done on a producing oilfield in the North Dakota portion of the basin. Well logs from 45 wells in Blue Buttes Field were analyzed, mainly focusing on the Middle Bakken section of the Bakken Formation. Reservoir properties, such as permeability, effective porosity, shale volume, and saturation were determined using a set of commercial software. Several methods for analyzing each property were tried, the results were compared and the best method was picked that matched the core analysis such as the XRD scanning.

The results of this study can help with a decision regarding the further development of the reservoir specifically in the Blue Buttes Field or to improve the understanding of various properties from the Middle Bakken. The procedures presented in this paper will help to establish a workflow for similar studies in other unconventional reservoirs in the future. This case study also helps better understand the lithology and rock properties of the Middle Bakken.
Quantitative Risk Analysis for Induced Seismicity in Hydraulic Fracturing versus Waste Water Disposal
Authors: Hosseini S. Mehran , Aminzadeh Fred
Published: April 2017

Induced seismicity risk is one of the major safety discussions surrounding hydraulic fracturing and waste water disposal. Several reported cases of induced seismicity in both waste water disposal and hydraulic fracturing propelled us to study the differences between the risks in each circumstance, by using a probabilistic-physics-based model. Herein, we present the work of our model for the probabilistic assessment of induced earthquakes that incorporates geomechanical analysis of the state of stress, pore pressure changes, and reservoir boundary conditions. The model considers a randomly distributed network of faults that undergo frictional failure due to overpressure-induced effective stress changes. This model includes the effects of flow properties and flow boundary conditions on overpressure, as well as the influence of initial stress regime on failure. The consequences of different injection parameters, reservoir size and other properties are discussed through case studies. We concluded that, despite the higher rate of injection in cases of waste water disposal, due to much shorter injection intervals, the risk of induced seismicity was much lower. The greatest difference was observed for a bounded reservoir in which the induced seismicity rate increased exponentially. Our proposed model provides a pathway to assess the expected seismic response to fluid injection, and supports the observations of less induced seismicity risk with hydraulic fracturing, compared to waste water disposal.
The Use of Voronoi Mapping for Production Growth in a Heavy Oil Field
Authors: Sharma Jyotsna , Popa Andrei , Tubbs Dallas , Cassidy Steve
Published: April 2017

In this work, we present an application of Voronoi partition technology to identify opportunities for increasing production in heavy oil reservoirs. The Voronoi partitions are a visual way of showing the boundary of influence of each well producing under a gravity drainage mechanism existing in heavy oil reservoirs. In contrast to classical well pattern representation or bubble maps, this approach provides a good estimate of the drainage areas around the wells and aids in identification of by-passed oil and opportunity for well intervention. The successful integration of Voronoi technology and fuzzy logic data led to effective workflows to target the by-passed reserves and identification of well interventions for production growth thus maximizing oil drainage in the Coalinga field.

The subject field presented within this article is a monocline dipping reservoir (14 degrees), with six producing sands located in San Joaquin Valley, California. Given the heterogeneity of the sands, low viscosity of the oil at reservoir conditions, scattered historical steamflood development, and the dipping characteristics; it is a challenge to get good drainage and recovery throughout the field. Therefore, one way to help mitigate this problem is by increasing the number of producers, however drilling new wells is cost intensive. The cheaper alternative is to utilize the existing poor performing wells and sidetrack them to alternate formations to increase productivity. The large number of available wells (over 1000 active & 700 shut-in), presented a lucrative opportunity to pursue the Voronoi technology to automate the process for workover selection and prioritization.

In this study, we demonstrate the methodology used for selection and prioritization of sidetrack candidates. The candidates were ranked based on the properties generated from the Voronoi and fuzzy logic tools, and the best candidates were selected and executed in the field. The lookback study results show a successful agreement of the workflow results and the actual production outcome, thus demonstrating the effectiveness of the proposed workflows.
Observations in the Loss of Well Productivity with High Solid/Liquid Ratios During Frac Jobs
Authors: Gao Song , Ershaghi Iraj
Published: April 2017

There have been various observations about the merits of increasing the proppant volume during hydraulic fracturing of source rocks. A general recommendation has been that larger proppant volumes can help in maintaining fracture flow capacity. In this study, we present data on actual cases related to more than 104 wells producing from the Bakken formation. Two parameters of interest were used as measures of well productivity. First was the average initial flow rate of the well, represented by the cumulative production during the first three months, and then was the production decline represented by the cumulative volume of oil produced in 180 days. Both of these parameters were tested as a function of corresponding sand/liquid ratios for similar completion practices and in the same reservoir. In all cases, we observed an an optimum value for the proppant liquid ratio related to the best case scenarios. Beyond that optimal ratio, the well performance show a deterioration. We attribute this to an overall reduction in fracture conductivity caused by packing of fractures, potential proppant plugging and slurry dehydration under excessive proppants placement.
Compositional Simulation Evaluation of Miscible Gas Injection Performance in Tight Oil Formation
Authors: Mansour Ahmed GH , Khalil Rayan , Gamadi Talal
Published: April 2017

Studying the performance of different techniques to improve oil recovery of tight oil reservoirs have become the main focus of many researchers because of the significant contribution of these reservoirs to the USA daily oil production. Recent studies have shown possibility of using EOR methods to improve oil recovery of tight and ultra-tight oil reservoirs as an attempt to encouagre the development of these reservoirs. This paper studies the feasibility and limitations of applying miscible gas flooding to enhancing oil recovery of tight and ultra-tight formation. A compositional simulation study was conducted and three main factors were used to study the performance of gas flooding; formation permeability, distance between wells, and gas injection period. Five permeability values, 1 md, 0.1 md, 0.01 md, 0.001 md, and 0.0001md, were used to build five simulation models then these models were used to study the performance and define the limitations of gas flooding process for each model. The results of the first part of the compositional simulation study show that the oil recovery has been improved when the miscible gas displacement process was applied to a formation that has permeability larger than 0.01 md becuase gas flooding did not significantly improve oil recovery for the models that have formation permeability less than 0.01 md. Second, we used the distance between the injection and production wells and gas injection period to investigate the performance and the limitations of applying gas flooding on each models. As a result of that, it has been found that formation permeability has a significant effect on the selection of well spacing. Forthermore, the study helped to recommend the well spacing that should be considered for different formation permeability values. Finally, this study promotes the understanding of implementing the miscible gas flooding in tight and ultra-tight oil formation and helps in the selection of the best candidate to apply gas flooding base on its permeability. Furthermore, it helps in optimize the well spacing of tight formation if gas flooding process is considered in future.
Above-Zone Pressure Response to Distinguish Between Fault and Caprock Leakage
Authors: Mosaheb Mojtaba , Zeidouni Mehdi
Published: April 2017

Deep saline aquifers are widely considered for injection/disposal of fluids (e.g. CO2 and wastewater) in the subsurface. However, target injection aquifers may be overlain by a regionally leaky caprock, which allows for fluid migration from the injection zone. In addition, target aquifers may also be intersected by leaky faults, which can accommodate leakage by connecting the target aquifer to other permeable zones. Leakage from the injection zone to an above permeable zone will be associated with pressure rise in that zone. The above zone pressure response has recently been extensively investigated in studying leakage in the context of CO2 geological sequestration. Both leaky fault and leaky caprock are considered as potential leakage pathways. Before analyzing above-zone pressure response for leakage characterization, it is important to determine whether the feature causing leakage is a fault or the semi-pervious caprock. The focus of this study is to provide a diagnostic tool to identify the leaky fault from a leaky caprock based on the pressure response.

A fault is a planar interface that can act as a conduit both normal and through the fault plane. Caprock is a very low permeability medium which is assumed to act as sealing layer to the reserved fluids. However, there may be heterogeneities associated with regional permeability variations in the caprock, which can accommodate leakage. An injection well makes a local high pressure region near the well that may result in significant leakage through the caprock or a fault intersecting the reservoir.

In this work, we investigate leakage from an injection layer into an overlying layer through a leaky fault and a leaky caprock based on the pressure changes. We present analytical models for pressure response to interlayer communication via a caprock and a leaky fault. The fault leakage causes a linear flow in the overlying layer. However, leakage through the cap rock is different in nature for which most leakage occurs at the vicinity of the injection well The flow regime occurred in the above-zone due to leakage are the base of our method to identify the leaky fault from the leaky caprock. Results show that fault leakage makes linear flow and caprock leakage show late-time radial flow in the above-zone. In order to detect these flow regimes by the common pressure transient analysis methods, the observed pressure in the above-zone must be normalized based on the time variable leakage rate.
Life After CHOPS: Alaskan Heavy Oil Perspective
Authors: Mathur Bakul , Dandekar Abhijit Y. , Khataniar Santanu , Patil Shirish L.
Published: April 2017

Heavy oil reservoirs in Alaska provide for major production challenges. The diverse set includes proximity to permafrost layers, very high viscosity oil and low mechanical strength pay zones. The Ugnu deposits of Alaska North Slope (ANS) hold more than 6 billion barrel of oil in place. The dead oil viscosity at reservoir temperature ranges from 1,000 to 1,000,000 cp1. In an effort to achieve sustained well life, this paper focuses on the unique set of challenges occurring in the Ugnu reservoir and presents the best possible way of maximizing production.

The paper accentuates on the observations derived from the field data which shows that deliberate sand production with the hydrocarbon stream while employing a Progressive Cavity Pump (PCP) as artificial lift method has favorable effect on the primary oil recovery. The developments have led to the advent of technique called Cold Heavy Oil Production with Sand (CHOPS) as initial production method for shallow heavy oil reservoirs. Sand production leads to the formation of high porosity channels or wormholes that can range up to hundreds of meters. The co-mingling of heavy oil and sand develops the behavior of foamy oil by creating a bubbly flow inside the reservoir. The combination of these wormholes with foamy oil behavior are the primary factors that result in enhanced production during CHOPS. One of the major hindrances to its successful application is the selection of post CHOPS production method, that has been addressed in this paper with the help of modeling and simulation The present research is based on modeling one of the wells drilled into the M80 sands of the Ugnu formation and then analyzing the post CHOPS recovery for the well. The research uses modeling of CHOPS well with the help of a wormhole fractal pattern and a foamy oil model. Simulation of polymer injection is then being employed from a nearby well. The recovery obtained from the simulations have been analyzed to provide a basis for selecting the appropriate enhanced oil recovery method after CHOPS.

Alternative recovery techniques following the primary cold production include water flooding, polymer injection, miscible gas injection and thermal recovery methods. Water flooding becomes unviable because of the mobility contrast between the highly viscous oil and water. The high permeability zones provide a bypass for water, producing elevated water cuts as a consequence. Another aspect unique to Alaskan heavy oil reservoirs is the proximity to the permafrost layer with the hydrocarbon bearing zone making thermal recovery methods unappealing. Polymer injection and miscible gas injection become favorable non-thermal secondary and tertiary recovery methods in this case. This paper analyses the performance of polymer flooding on a reservoir that has been produced with CHOPS. The results indicate almost 12% increment in recovery with polymer flooding as compared to the natural depletion.
Analytical Cyclic Steam Modeling Revisited and Applied to the Shallow Low Permeability California Diatomite
Authors: Elias Ramon , Medizade Mason
Published: April 2017

The commercial production of oil from the low permeability and shallow Opal A diatomite in California has been one of the most important resource development accomplishments of recent times. Corresponding oil-in-place estimates range from 24 to 80 billion barrels with oil recovery efficiencies of 50% and more. Most of the production comes from cyclic steam stimulation (CSS).

This paper discusses changes made to an existing analytical thermal simulator to modelCSS production from diatomite. Algorithms were added to enable well stimulation and reservoir dilation. Field production data was compiled from public sources and history matched to calibrate the input parameters. The model was then run to show how stimulation and dilationinfluence oil and water production. The conclusions give new insightson production from the diatomite.

This is the first published application of CSS analytical modeling for this resource.
Augmented Text Mining for Daily Drilling Reports using Topic Modeling and Ontology
Authors: Arumugam Sethupathi , Rajan Shebi , Gupta Sanjay
Published: April 2017

Exploring Textual data has been often presented as a challenge across all the industries around the world. This challenge has been alleviated to an extent by the biomedical industry using text mining to improve cancer research. This paper proposes applying similar techniques to explore daily drilling reports, these reports are rarely exploited for well planning. It is paramount to identify relevant drilling reports for the current well planning operations and to utilize advanced text mining techniques to track drilling operations against geological formations and offset wells in terms of caving, mud loss, vibrations, sudden increase/decrease of ROP, additional torque, etc.

This paper focuses on knowledge discovery using statistical analysis, theme based Report classification and domain based ontology to identify offset wells which have encountered risks and events. Tetxual contents are extracted from the drilling reports and analyzed using bag of words, frequency distribution and pie charts to obtain high-level view of the drilling reports. The processed Textual is further analyzed using Latent Dirichlet Allocation (LDA) into theme based models; in LDA each report is viewed as a mixture of themes that are present within the textual corpus. Outcome of LDA model helped to establish Ontology association between the symptoms and their corresponding causes. This helps Geologists in identifying offset wells with operational challenges and equips them for faster root cause analysis that can lead to better well planning.

Knowledge Discovery begins by extracting facts and events from daily drilling reports. Classification of drilling reports, extraction of key events encountered on geological formations are problems that Geologists face using this approach would allow them to browse large collection of documents, view critical highlights and drill down for detailed information.This solution can be further extended to other reports such fluid report, mud log report and operational reports. All the well reports can be exploited using text mining results to provide greater insight into drilling operation from different perspective.
Recovery Improvement of Gravity Driven Steam Applications Using New Generation Chemical Additives
Authors: Bruns Fritjof , Babadagli Tayfun
Published: April 2017

Reservoirs containing very heavy oil or extremely heterogeneous/fractured geology are not convenient for steamflooding and even cyclic steam injection. Then, steam can be used to heat the reservoir and accelerate the recovery by gravity drainage. Two well-known applications of this method are steam assisted gravity drainage (SAGD) and thermally assisted gas oil gravity drainage. Although the latter is not commercially applied, the former is a proven technology with remarkable production in Canada and Venezuela. Due to the risks caused by the cost and solvent retention, no large scale applications of solvent injection with steam have been implemented. An alternative is to use chemicals as suggested a few decades ago to alter the interfacial forces and improve microscopic displacement. This paper presents experimental results on testing -new generation- chemicals for their capability in recovery improvement.

Sandpack experiments were conducted to evaluate the incremental in oil recovery by chemical additives compared to sole steam injection. Steam and chemicals were heated and introduced to the system from separate channels at the entrance of the vertically situated sandpack (30 cm long, 5 cm in diameter). To generate a purely gravity dominated system (pressure differential of 10–25 psi) a back pressure regulator was used. The chemicals used include thermally stable surface agents, such as surfactants (AAS J1111, O352, LTS-18), Tween 20, biodiesel), ionic liquid (BMMIM BF4), high pH solution (NaBO2), solvent (heptane), and nanoparticles (SiO2). The oil selected was 20,000 cp crude.

Incremental recoveries were monitored and related to the thermal stability of the chemicals. A comparative analysis was provided as to their contribution to the reduction of the cost (less steam and lower temperature) and chemicals were classified based on their recovery improvement performance and thermal stability. Through this experimental schematic, the highest increment in oil recovery was achieved by LTS-18 but also combined a high duration of the experiment with a high water consumption. This reduces the result in economical favorable conditions of the LTS-18. Biodiesel had the best performances in steam-to-oil ratio (SOR) and its effects needs to be further investigated. Tertiary injection of hot water with a surfactant was inefficient. Ionic liquid increased the oil recovery in the tertiary stage after the core was flooded with a low quality steam by 20%.
DyMAS: A Direct Multi-Scale Pore-Level Simulation Approach
Authors: Mohammadmoradi Peyman , Kantzas Apostolos
Published: April 2017

The recent advancements in high-resolution imaging technology offer the opportunity to generate detailed pore-level domains and highlight the need for efficient and reliable digital core analyzers. Here, a new generation of direct pore-scale simulation techniques called dynamic morphology assisted simulation (DyMAS) is proposed. DyMAS, as a hybrid method, couples pore morphological quasi-static and computational fluid dynamic approaches to simulate immiscible multiphase fluid flow at pore-scale with high computational efficiency. DyMAS is a comprehensive modeling approach that has the capability of dealing with pore structures of a wide range of pore sizes, from intergranular to microporosity, simultaneously. It is a selective approach that updates the governing equations along with the interface development to prevent numerical instabilities associated with the interface reconstruction and volume tracking processes. Gravity, viscous, and capillary forces are all taken into account ensuring accurate simulation of the compound fluid displacement patterns, e.g., splitting and coalescence, viscous fingering, ganglia mobilization, gravity segregation, and capillary trapping.