Lou, Xuanqing (Pennsylvania State University) | Chakraborty, Nirjhor (Pennsylvania State University) | Karpyn, Zuleima (Pennsylvania State University) | Ayala, Luis (Pennsylvania State University) | Nagarajan, Narayana (Hess Corp.) | Wijaya, Zein (Hess Corp.)
The design of oil recovery processes by gas injection or vapor solvent relies on knowledge of diffusion coefficients to enable meaningful production predictions. However, lab measurements of diffusion coefficients are often performed on bulk fluids, without accountability for the hindrance caused by the pore network structure and tortuosity of porous media. As such, our ability to predict effective diffusion coefficients in porous rocks is inadequate and, additional laboratory work is needed to investigate the impact of the medium itself on transport by diffusion. In addition, experimental data on multi-phase diffusion coefficients are particularly scarce for tight rocks. This study therefore proposes an experimental methodology, based on a pressure-decay technique, to measure diffusion of injected gas in oil saturated porous rocks. A diffusion experiment of gas into bulk oil (without porous medium) provides an upper limit estimation of this gas-liquid diffusion coefficient. Diffusion experiments using limestone and Bakken shale provide insight into different degrees of restriction in high permeability versus low permeability media. Two analytical models and one numerical model were implemented and compared to determine the diffusion coefficients from the time-dependent experimental pressure-decay data. These diffusion coefficients were found in agreement with literature on corresponding data, demonstrating the validity of the modeling approaches used. Results indicate considerable hindrance to diffusion in porous media relative to bulk oil and relates to the tortuosity and constrictivity of the rock matrix. The diffusion coefficient of methane in bulk oil is 3.8 × 10−9 m2/s. In our limestone sample, this diffusion coefficient drops by one order of magnitude, ranging between 1.5 to 6.5 × 10−10 m2/s and, it drops by another order of magnitude in the Bakken shale sample to 2.0 × 10−11 m2/s.
Yegin, Cengiz (Texas A&M University) | Zhang, Ming (Biopharm Frontida) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Balaji, Karthik (University of Southern California) | Peksaglam, Zumra (University of Southern California) | Dhannoon, Diyar (Texas A&M University) | Putra, Dike (Rafflesia Energy) | Wijaya, Zein (HESS) | Saracoglu, Onder (Consultant) | Temizel, Cenk (Aera Energy)
Current analyses indicate that 50% of oil produced in USA and the world will be through EOR technologies in the next 20-25 years, and heuristics suggest that polymer flooding should be applied in reservoirs with oil viscosities between 10 and 150 mPa.s. The key factor limiting the recommended range is that for oil viscosities greater than 150 mPa.s, where injected water viscosity values required for a favorable mobility ratio give rise to prohibitively low values of polymer injectivity and pumping efficiencies. Herein, we propose that a novel type of supramolecular system based on the complexation of long chain amino amides and maleic acid with reversibly adjustable viscosities can enable us to overcome the injectivity limitation.
The concept is that viscosity of the injected supramolecular system will be maintained initially at low values for easy injection and pumping, and then increased by means of an external pH stimulus just before or upon contacting oil. Our promising lab-scale preliminary studies have indicated that such supramolecular systems possess not only reversible pH-responsive properties, but are also very tolerant to high salinities and temperatures.
While polymers degrade and break up upon experiencing sudden extreme shear stresses and temperatures, supramolecular solutions merely disassemble and re-assemble. Therefore, supramolecular solutions can be considered as healable polymer solutions in a way. Supramolecular solutions can adapt to the confining environment. For instance, when a high molecular weight polymer macromolecule is forced to flow into narrow channels and pores, molecular scission processes may take place.
Supramolecular solutions can have a significant impact in the cases where thermal methods cannot be used for some viscous oils due to thin zones, permafrost conditions and environmental constraints. This project is primarily aimed at developing novel supramolecular assemblies with adjustable viscosity and interfacial properties that have robust tolerance against high temperatures and salinities. Such supramolecular assemblies will be used to significantly improve the feasibility and cost-effectiveness of displacement fluids used in EOR. Overall, there is a significant potential for application of supramolecular solutions in the US and throughout the world.
Temizel, Cenk (Aera Energy) | Saputelli, Luigi (Frontender Corp.) | Nabizadeh, Mehdi (International Petro Asmari Company) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Wijaya, Zein (HESS)
In field development and management, optimization has turned out to be an integral component for decision-making. Optimization involves computationally intensive complex formulations but simplifies making decisions. For reaching the optimal solution to a defined objective function, optimization software can be combined with a numerical reservoir simulator. Hence, robust and faster results are imperative to optimization problems.
To maximize cumulative recovery and net present value (NPV), the reservoir simulator works on maximizing these predefined objective functions that can be multi-objective leading to Pareto sets with "trade-offs" between objectives. In optimization algorithms with predefined objective functions, there is a need for these objective functions to be flexible by using conditional statements through procedures, since generally they do not provide the flexibility required by the physical reservoir fluid flow phenomenon to "maneuver" throughout optimization iterations.
In this study, a commercial reservoir simulator is coupled with an optimization software. As the need was discuss earlier, conditional statements are implemented in the simulator as procedures. Operating the software/simulator combination under pseudo-dynamic objective functions is achieved through these procedures. Highest recovery for the time period mentioned in the conditional statement for the simulation is achieved by trying sets of combinations of parameters, which also makes the optimization process faster and more robust. Throught the use of these conditional statements, the procedures are able to implement piecewise objective functions as codes for a given time frame.
The objective function to be maximized by the optimization process in this study cumulative production. The optimized recoveries with pseudo-dynamic objective functions provide an enhanced recovery, as compared to that of an optimization case with predefined constant objective function in the optimization software throughout the iterations of the optimization and simulation process.
Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Balaji, Karthik (University of Southern California) | Peksaglam, Zumra (University of Southern California) | Malik, Vidhi (University of Southern California) | Zhang, Ming (Rafflesia Energy) | Biopharm, Frontida (Rafflesia Energy) | Putra, Dike (Rafflesia Energy) | Wijaya, Zein (HESS) | Dhannoon, Diyar (Texas A&M University) | Temizel, Cenk (Aera Energy LLC)
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.
Yegin, Cengiz (Texas A&M University) | Zhang, Ming (University of Southern California) | Biopharm, Frontida (University of Southern California) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Peksaglam, Zumra (University of Southern California) | Wijaya, Zein (HESS) | Putra, Dike (Rafflesia Energy) | Anggraini, Henny (HESS) | Temizel, Cenk (Aera Energy) | Ramadurai, Balaji (Tata Consultancy Services)
Multiple analysis has indicated that over 50% of the oil production in the next 20-25 years is going to be produced through enhanced recovery procedures including polymer flooding. The heuristics for polymer flooding says that it is feasible to apply polymer flooding in reservoirs having oil viscosities in the range of 10 to 150 mPa.s. The main factor limiting this heuristic limit for polymer floods is that the injected water viscosity required for higher mobility ratio leads to pumping inefficiencies and low polymer injectivity rates. In this paper, we suggest a supramolecule based on the complexation of a long-chain amino-amide and maleic acid which can adjust its viscosity values reversibly to overcome the heuristic problem related to polymer floods.
The concept is fundamentally based on the fact the supramolecule system which is injected in the reservoir will initially be maintained at a low viscosity and on application of external pH stimuli will increase in viscosity values prior to contact with oil. Our laboratory studies indicate that such a system is also tolerant to high temperatures and salinities
Popular polymer systems used floe EOR purposes on experiencing extreme shear stresses and temperature break-up and degrade, however the supramolecule system dissemble and reassemble making the supramolecular system "healable" in a manner. The supramolecular systems can also adapt to confining environments, for example, on flow through narrow channels, the supramolecules undergo molecular scission.
The supramolecules proposed could be used for viscous oil in thin oil sand zones, permafrost and other environmentally constraining systems. This paper primarily focusses, on the development and properties of a novel supramolecular system which has adjustable viscosities and interfacial properties and can be resistant to high temperatures and salinities. This Supramolecular system can significantly improve the feasibility and cost-effectiveness of a polymer flood process and can be utilized universally.
Temizel, Cenk (Aera Energy) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Peksaglam, Zumra (University of Southern California) | Wijaya, Zein (HESS) | Inceisci, Turgay (Turkish Petroleum) | Abdelfatah, Elsayed Raafat (University of Oklahoma)
Certain heavy oils that foam under severe depressurization give rise to increased recovery factor and an increased rate of production under solution gas drive. Alongwith stabilizing foam, at lower volume ratios, these oils have the ability of stabilizing dispersion of gas bubbles. Chemistry of oil and its viscosity are the reasons for this. In comparison to conventional oils, response of foamy oils to drawdown of pressure is more favorable; primary recovery factor, rate of production, volume ratio of oil to gas that is recovered and the length of time that a given pressure gradient or rate of production can be maintained, all increase substantially. It is a complex phenomenon with intrinsic properties, thus it requires a robust understanding of each factor in this recovery process. In this study, the significance of factors that influence foamy oil recovery in horizontal wells is investigated and outlined.
A robust commercial optimization and uncertainty software is coupled with a full-physics commercial simulator that models the phenomenon with bubbly oil approach in order to investigate the significance of major parameters, on performance of horizontal wells in a foamy oil reservoir in the North Sea. Fluid properties of Maini et al. are employed. Foamy oil is modeled as small bubbles in oil along with small mobile droplets of gas in oil, larger trapped droplets of gas phase and flowing discontinuous gas foam where bubbles can affect viscosity and compressibility along with foam mobility reduction in relative permeability effects, which are region dependent is incorporated.
Sensitivity and optimization has been done on major reservoir parameters, such as, fluid and rock properties and well operational parameters. Tornado diagrams have been used to portray the significance of each parameter. It is observed that a robust approach on handling of uncertainties in reservoir are as important as management of well operational parameters in the scope of reservoir management.
Reasons for the favorable response of foamy oils in solution gas drive are not well understood and tentative explanations that have been put forward are controversial, where utilization of horizontal wells adds another degree of complexity. This study provides an in depth optimization and uncertainty analysis to outline the significance of each major parameter involved in production performance and ultimately the recovery efficiency in foamy oil reservoirs produced with horizontal wells.
Temizel, Cenk (Aera Energy) | Thanon, Diyar (Texas A&M University) | Inceisci, Turgay (Turkish Petroleum) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Wijaya, Zein (HESS) | Raafat, Elsayed (University of Oklahoma)
Started in the late 1800s in the US, water being relatively inexpensive, readily available in large volumes and also being very effective at significantly increasing oil recovery, waterflooding has been the most common secondary recovery method applied throughout the world, contributing to pressure maintenance in the reservoir and displacing the oil phase. While there are several parameters that influence the performance of a waterflood, water quality is one of the most important factors as it may cause scaling in injection wells as well as some formation damage through chemical phenomena such as, cation exchange in the reservoir, resulting in decreased the recoveries.
As waterfloods continue over decades, prevention of scale formation becomes a more significant factor that needs to be properly treated. Precipitation of inorganic scale is a major issue in injecting brines with a high concentration of divalent ions. Scaling tendency of water is highly correlated with the hardness of injection water.
Following corrosion, insoluble iron precipitates can cause damage in injection wells since precipitates can lead to severe reductions in well injectivity. Water needs to be treated in a proper way, if the water contains high concentrations of calcium, magnesium or iron. In most waterflood applications, seawater needs to be used and this phenomenon is also an issue when injecting seawater into formations that contain brines with high salinity.
In this study, we provide a comprehensive analysis of this common problem by investigating the significance of parameters affecting the severity of scale formation through utilizing a seawater scale buildup model that will be simulated using a commercial simulator along with an in-depth review of previous studies.
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Consultant) | Wijaya, Zein (HESS) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Tran, Minh (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | Al-Kouh, Ahmad (Middle East Oilfield Services) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Voidage replacement is a key element in displacement processes, not only for keeping the reservoir pressure at its initial level but also in mitigating surface subsidence in certain fields. Despite its simple definition, it is a complicated process in reservoir management because of uncertainities involved and lack of all required measurements due to economical or technical restrictions. Thus, every single decision parameter and their relative significance in voidage replacement process is important for robust reservoir management.
In general, voidage replacement is achieved where injection is based on production. This study investigates the case of triggers where the production rate at the bottom hole conditions is predicated on the bottom hole flowing conditions or reservoir gas injection rate. A full-physics commercial reservoir simulator is coupled with robust optimization software, where a miscible flood operation is modeled with a group bottom hole flowing target coupled with voidage replacement gas and water injection targets.
The simulation results of this realistic case is presented in a way to show the relative significance of each operational parameter, which is outlined with tornado charts to serve as a guide in decision making in efficient reservoir management where voidage replacement is a crucial component. It is observed that triggers help to better manage voidage replacement, especially in large reservoirs where reservoir surveillance is a challenge due to number of wells and patterns. The results can be scaled up to different size of reservoirs and patterns with similar recovery processes.
This study scrutinizes the feasibility of a reversal of the typical scenario where injection is based on production. Thus, it serves as a useful and realistic example for efficient reservoir management through optimization of voidage replacement through triggers for production rate.
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Freelance Consultant) | Inceisci, Turgay (Turkish Petroleum) | Wijaya, Zein (HESS) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | Al-Kouh, Ahmad (Middle East Oilfield Services) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. They have a great potential for oil recovery despite these drawbacks. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites, including the use of ‘backpressure method’, coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing including several mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, for instance, in the areas of detection of early steam breach to surface in steam operations and fracture orientation. This method also provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.
Temizel, Cenk (Aera Energy LLC) | Kirmaci, Harun (Turkish Petroleum Corporation) | Inceisci, Turgay (Turkish Petroleum Corporation) | Wijaya, Zein (HESS) | Zhang, Ming (University of Akron) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | Al-Kouh, Ahmad (Middle East Oilfield Services) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Asphaltene precipitation is caused by numerous factors such as temperature, pressure and compositional vartiations. Drilling, completion, acid stimulation, and hydraulic fracturing activities can also result in settling in the near-wellbore region. Heavier crudes have a fewer precipitation issue becasue of dissolving more asphaltene. Thus, it is crucial to understand the significance of each uncertainty and control variables not only theoretically, but also with application to real-life examples, such as with this model that uses a 32-degree API South American oil to demonstrate the importance of each variable to shed light in order to efficiently manage such reservoirs.
A commercial optimization and uncertainty tool is combined with a full-physics commercial simulator, which can create a model to investigate the significance of major factors influencing the performance of wells in temperature-dependent asphaltene precipitation and irreversible flocculation. Temperature-dependent asphaltene precipitation and irreversible flocculation are modelled where no precipitation occurs at the original reservoir temperature, and flocculated asphaltene is allowed to deposit through surface adsorption and pore throat plugging. The exponent in the power law relating porosity reduction to the permeability resistance factor, is modified to change the effect of asphaltene deposition on permeability reduction.
Lower temperatures are specified around the wellbore causing asphaltene precipitation. And then, optimization and sensitivity have been performed on major reservoir parameters including well operational parameters, and fluid and rock properties. Moreover, each parameter has been demonstrated in tornado diagrams. It was concluded that employing feasible methods on handling of reservoir uncertainties are as important as management of well operational parameters for effective reservoir management.
This study provides an in-depth optimization and uncertainty analysis to outline the significance of each major parameter involved in production performance, and ultimately the recovery efficiency in reservoirs with temperature-dependent asphaltene precipitation and irreversible flocculation.