Screening guidelines and data analysis for the application of in-situ polymer gels for injection well conformance improvement

Excessive water production represents a major industry challenge because of its serious economic and environmental impacts. Polymer gels have been effectively applied to mitigate water production and extend the productive lives of mature oilfields. However, selecting a proper gel technology for a given reservoir is a challenging task for reservoir engineers because of the associated geological and technical complexities and the absence of efficient screening tools. A comprehensive review for the worldwide gel field projects was conducted to develop an integrated systematic methodology that determines the applicability of three injection well gel technologies including bulk gels, colloidal dispersion gels, and weak gels. Comparative analysis, statistical methods, and a machine learning technique were utilized to develop a conformance agent selection advisor that consists of a standardized selection system, conventional screening criteria, and advanced screening models. The results indicated that gel technology selection is a two-step process that starts by matching problem characteristics with gel technical specifications and mechanisms. Then, the initial candidate technology is confirmed by screening criteria to ensure gel compatibility with reservoir conditions. The most influential conformance problem characteristics in the matching process are channeling strength, volume of problem zone, problem development status, and the existence of crossflow. In addition to crossflow, the presence of high oil saturations or unswept regions in the offending zones requires the application of flood-size treating technologies that combine both displacement and diversion mechanisms. The selection and design of gel technologies for a given conformance problem greatly depend on the timing of the gel treatment in the flood life --Abstract, page iv

Enhanced oil recovery by CO2 injection in carbonate reservoirs.

The majority of carbonate reservoirs have low porosity and permeability in general because of having a high amount of matrixes that make a heterogeneous reservoir, however high permeable layers are fractured. This study shows the effect of carbon dioxide injection on the oil recovery factor using an ECLIPSE 300 compositional reservoir simulator for 3D modelling and the change of carbonate components reaction during CO2 injection in experimental work. In addition, a high recovery factor has been recorded during miscible CO2 injection compared to immiscible injection. Water alternative gas (WAG) has been used as an enhanced oil recovery (EOR) method to overcome an unfavourable mobility ratio of CO2 flooding. Miscible CO2 injection with the aid of WAG has also had a great impact on the dissolution of carbonate components in dissolving calcite and dolomite components. Consequently, CO2 flooding has a relatively low recovery factor without any EOR techniques such as gravity stable displacement, WAG or mobility control. CO2 injection below minimum miscibility pressure (MMP) reduces CO2 emission, while it takes too long time to maintain reservoir pressure. On the other hand, CO2 flooding above MMP improves pressure maintenance; causes oil swelling, and increases the oil density

Developments in modeling and optimization of production in unconventional oil and gas reservoirs

textThe development of unconventional resources such as shale gas and tight oil exploded in recent years due to two key enabling technologies of horizontal drilling and multi-stage fracturing. In reality, complex hydraulic fracture geometry is often generated. However, an efficient model to simulate shale gas or tight oil production from complex non-planar fractures with varying fracture width along fracture length is still lacking in the petroleum industry. In addition, the pore size distributions for shale gas reservoirs and conventional gas reservoirs are quite different. The diffusivity equation of conventional gas reservoirs is not adequate to describe gas flow in shale reservoirs. Hence, a new diffusivity equation including the important transport mechanisms such as gas slippage, gas diffusion, and gas desorption is required to model gas flow in shale reservoirs. Furthermore, there are high cost and large uncertainty in the development of shale gas and tight oil reservoirs because of many uncertain reservoir properties and fracture parameters. Therefore, an efficient and practical approach to perform sensitivity studies, history matching, and economic optimization for the development of shale gas and tight oil reservoirs is clearly desirable. For tight oil reservoirs, the primary oil recovery factor is very low and substantial volumes of oil still remain in place. Hence, it is important to investigate the potential of CO₂ injection for enhanced oil recovery, which is a new subject and not well understood in tight oil reservoirs. In this research, an efficient semi-analytical model was developed by dividing fractures into several segments to approximately represent the complex non-planar fractures. It combines an analytical solution for the diffusivity equation about fluid flow in shale and a numerical solution for fluid flow in fractures. For shale gas reservoirs, the diffusivity equation of conventional gas reservoirs was modified to consider the important flow mechanisms such as gas slippage, gas diffusion, and gas desorption. The key effects of non-Darcy flow and stress-dependent fracture conductivity were included in the model. We verified this model against a numerical reservoir simulator for both rectangular fractures and planar fracture with varying width. The well performance and transient flow regime analysis between single rectangular fracture, single planar fracture with varying width, and single curving non-planar fracture were compared and investigated. A well from Marcellus shale was analyzed by combining non-planar fractures, which were generated from a three-dimensional fracture propagation model developed by Wu and Olson (2014a), and the semi-analytical model. Contributions to gas recovery from each gas flow mechanism were analyzed. The key finding is that modeling gas flow from non-planar fractures as well as modeling the important flow mechanisms in shale gas reservoirs is significant. This work, for the first time, combines the complex non-planar fracture geometry with varying width and all the important gas flow mechanisms to efficiently analyze field production data from Marcellus shale. We analyzed several core measurements for methane adsorption from some area in Marcellus shale and found that the gas desorption behaviors of this case study deviate from the Langmuir isotherm, but obey the BET (Brunauer, Emmett and Teller) isotherm. To the best of our knowledge, such behavior has not been presented in the literature for shale gas reservoirs to behave like multilayer adsorption. The effect of different gas desorption models on calculation of original gas in place and gas recovery prediction was compared and analyzed. We developed an integrated reservoir simulation framework to perform sensitivity analysis, history matching, and economic optimization for shale gas and tight oil reservoirs by integrating several numerical reservoir simulators, the semi-analytical model, an economic model, two statistical methods, namely, Design of Experiment and Response Surface Methodology. Furthermore, an integrated simulation platform for unconventional reservoirs (ISPUR) was developed to generate multiple input files and choose a simulator to run the files more easily and more efficiently. The fracture cost was analyzed based on four different fracture designs in Marcellus shale. The applications of this framework to optimize fracture treatment design in Marcellus shale and optimize multiple well placement in Bakken tight oil reservoir were performed. This framework is effective and efficient for hydraulic fracture treatment design and production scheme optimization for single well and multiple wells in shale gas and tight oil reservoirs. We built a numerical reservoir model to simulate CO₂ injection using a huff-n-puff process with typical reservoir and fluid properties from the Bakken formation by considering the effect of CO₂ molecular diffusion. The simulation results show that the CO₂ molecular diffusion is an important physical mechanism for improving oil recovery in tight oil reservoirs. In addition, the tight oil reservoirs with lower permeability, longer fracture half-length, and more heterogeneity are more favorable for the CO₂ huff-n-puff process. This work can provide a better understanding of the key parameters affecting the effectiveness of CO₂ huff-n-puff in the tight oil reservoirs.Petroleum and Geosystems Engineerin

Updated screening criteria for steam flooding based on oil field projects data

Enhanced oil recovery (EOR) screening is considered the first step in evaluating potential EOR techniques for candidate reservoirs. Therefore, as new technologies are developed, it is important to update the screening criteria. Many of the screening criteria for steam flooding that have been described in the literature were based on data collected from EOR surveys biennially published in the Oil & Gas Journal. However, these datasets contain some problems, including outliers, missing data, inconsistent data and duplicate data, that could affect the accuracy of the results. Despite the importance of ensuring the quality of a dataset before running analyses, data quality has not been addressed in previous research related to EOR screening criteria. The objective of this current work was to update the screening criteria for steam flooding by using a database that had been cleaned. The original dataset included 1,785 steam flooding field projects from around the world (Brazil, Canada, China, Colombia, Congo, France, Germany, Indonesia, Trinidad, U.S. and Venezuela). These projects had been reported in the Oil and Gas Journal from 1980 to 2012. After detecting and deleting the duplicate projects, only 626 field projects remained. To analyze and describe the results of the dataset, both graphical and statistical methods were used. A box plot and cross plots were used to detect and identify data problems, allowing for the removal of outliers and inconsistent data. Histogram distributions and box plots were used to show the distribution of each parameter and present the range of the dataset. New screening criteria were developed based on these statistics and the defined data parameters. The developed criteria were compared with previously published criteria, and their differences are explained. --Abstract, page iii

Neuro-Simulation Tool for Enhanced Oil Recovery Screening and Reservoir Performance Prediction

Assessment of the suitable enhanced oil recovery method in an oilfield is one of the decisions which are made prior to the natural drive production mechanism. In some cases, having in-depth knowledge about reservoir’s rock, fluid properties, and equipment is needed as well as economic evaluation. Both putting such data into simulation and its related consequent processes are generally very time consuming and costly.  In order to reduce study cases, an appropriate tool is required for primary screening prior to any operations being performed, to which leads reduction of time in design of ether pilot section or production under field condition. In this research, two different and useful screening tools are presented through a graphical user interface. The output of just over 900 simulations and verified screening criteria tables were employed to design the mentioned tools. Moreover, by means of gathered data and development of artificial neural networks, two dissimilar screening tools for proper assessment of suitable enhanced oil recovery method were finally introduced. The first tool is about the screening of enhanced oil recovery process based on published tables/charts and the second one which is Neuro-Simulation tool, concerns economical evaluation of miscible and immiscible injection of carbon dioxide, nitrogen and natural gas into the reservoir. Both of designed tools are provided in the form of a graphical user interface by which the user, can perceive suitable method through plot of oil recovery graph during 20 years of production, costs of gas injection per produced barrel, cumulative oil production, and finally, design the most efficient scenario

Developing tools for determination of parameters involved in CO₂ based EOR methods

To mitigate the effects of climate change, CO₂ reduction strategies are suggested to lower anthropogenic emissions of greenhouse gasses owing to the use of fossil fuels. Consequently, the application of CO₂ based enhanced oil recovery methods (EORs) through petroleum reservoirs turn into the hot topic among the oil and gas researchers. This thesis includes two sections. In the first section, we developed deterministic tools for determination of three parameters which are important in CO₂ injection performance including minimum miscible pressure (MMP), equilibrium ratio (Kᵢ), and a swelling factor of oil in the presence of CO₂. For this purposes, we employed two inverse based methods including gene expression programming (GEP), and least square support vector machine (LSSVM). In the second part, we developed an easy-to-use, cheap, and robust data-driven based proxy model to determine the performance of CO₂ based EOR methods. In this section, we have to determine the input parameters and perform sensitivity analysis on them. Next step is designing the simulation runs and determining the performance of CO₂ injection in terms of technical viewpoint (recovery factor, RF). Finally, using the outputs gained from reservoir simulators and applying LSSVM method, we are going to develop the data-driven based proxy model. The proxy model can be considered as an alternative model to determine the efficiency of CO₂ based EOR methods in oil reservoir when the required experimental data are not available or accessible

CO2 Foam Stabilization with Nanoparticles and EOR in Fractured Carbonate Systems

This thesis is a part of an ongoing study of CO2 foam mobility control in the Reservoir Physics group at the Department of Physics and Technology (IFT) at the University of Bergen. The goal of this thesis was to evaluate stabilization of foam and enhanced oil recovery (EOR) using hydrophilic silica nanoparticles and anionic AOS surfactants as foam agents. Foam was generated by co-injection of an aqueous foam agent solution and CO2 as the gaseous phase. Foam is generated in-situ as the two fluids are mixed in the porous medium, resulting in a mobility reduction of CO2. Miscible CO2 and CO2-foam injection tests using surfactants as a foaming agent were performed to study the effect on tertiary EOR in carbonate reservoirs. The experiments were conducted in strongly water-wet, fractured and un-fractured Edward limestone core plugs. Foam is used for mobility control by blocking high permeable zones, resulting in a delay of gas breakthrough and significantly improve the macroscopic sweep efficiency. Supercritical CO2 injections increased on average oil recovery by 20% OOIP compared to ordinary water injection. The highest recovery (63% OOIP) was obtained by first injecting supercritical CO2 followed by CO2-foam. Foam was generated in-situ in cores without fractures, verified by increased pressure drop. Foam generation in fractured was poor, mainly due to lack of generation sites, low stability and high oil saturation. The limited stability of surfactant-generated foam in presence of oil, combined with high reservoir temperature and high salinity are among reasons why foam is not being widely used as a common EOR method. Nanoparticles are reported to work as foam stabilizers and are chemically stable in a wider range of reservoir conditions than surfactants. Experimental investigations using nanoparticles as foaming agents, without the presence of oil, were therefore conducted in this thesis. The sensitivity in parameters such as gas fraction, total injection rate and injection strategies using nanoparticles to generate foam were investigated. The pressure drop across the core was measured to estimate the achieved mobility reduction factor (MRF) and the apparent viscosity of the generated foam. The result shows that independent of the gas fraction an increase in injection rate lead to a higher pressure drop. The apparent viscosity of the foam increased with higher gas fractions for some, but not all injections. The inconsistency is caused by a significant hysteresis effect. Common for the injection experiments is that high liquid or high gas fraction generates foam with a lower apparent viscosity.MAMN-PETRPTEK39

A Novel Mobility Control Technique in Miscible Gas Injection Using Direct Gas Thickening in High Pressure and Temperature Reservoir

This thesis presents for the first time, the details of extensive numerical and experimental evaluations of effectiveness of thickened associate gas injectionat high temperature for miscible gas floodingwith specific focus on FieldAlocated in southern Oman. The study has identified commercialand safe gas thickeners capable of increasing viscosity of injected gas. It hasalso proposedanovel alternating injection technique that canlower the volume of thickeners usedduringfield-scale applications