Oil recovery from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of these rocks and the lack of sufficient spontaneous capillary imbibition driving force to push oil out from the matrix to the fracture network. Chemical processes such as surfactant/alkali-induced wettability alteration and interfacial tension (IFT) reduction have shown great potential to reduce the residual oil saturation in matrix blocks, leading to significant incremental oil recovery (IOR). However, the IOR response time is the most crucial decision factor in field projects. The magnitude and time efficiency of recovery depend on the degree of wettability alteration and IFT reduction, the nature and density of fracture network, and the dimensions of matrix blocks.
Oil recovery experiments were performed for the same matrix rock and chemical formulation, but for different sized cores to gain a better understanding of the time dependence of the recovery process. The measured oil recoveries were history-matched. The simulation models were then used to predict the recovery response times for larger cores. The controlled and systematic laboratory measurements for several core sizes helped in developing dimensionless scaling groups to aid in understanding the time dependence and upscaling of laboratory results to field-scale applications.
This finding is significant as it illustrates the extent of wettability alteration and IFT reduction needed in fractured reservoirs. Laboratory measurements and simulation work substantiate the validity and the range of applicability of upscaled procedures, and indicate the importance of viscous and buoyancy forces in larger field cases. The results of this work will be useful for the design of future field projects.
Wettability is a key property, which controls multiphase fluid flow in oil recovery processes. It is well known that the asphaltene deposition on rock surface changes the wettability of the rock. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration in crude oil/brine/rock (COBR) system because of asphaltene deposition; a sophisticated mathematical model describing this phenomenon is absent.
In this paper, based on available experimental data in the literature and known physical mechanisms of asphaltene deposition on the rock in the COBR system, a model for wettability alteration due to asphaltene instability in crude oil is presented. Contact angle is introduced as a function of asphaltene stability index (ASI), which is determined thermodynamically based on the difference between the fugacity of asphaltene and the heaviest component in the oil. The shape of this function depends on pH, salinity and cation valency of brine, and asphaltene content of crude oil. We implemented our proposed model along with asphaltene precipitation, flocculation, and deposition models into an in-house compositional simulator, UTCOMP, developed at The University of Texas at Austin. Permeability and porosity reduction due to asphaltene deposition are also considered. Furthermore, relative permeabilities and capillary pressure are modified because of contact angle alteration during simulation.
Although the amount of asphaltene deposition in the reservoir may not be comparable to the wellbore, a significant change in wettability occurs after the deposition of first layer of asphaltene on the rock surface. The result of our simulation shows that wettability alteration affects oil recovery, specifically when the brine produces unstable water film on the rock surface. In this case, rock wettability can change from 30° (water-wet) to 150° (oil-wet) and yield change in recovery depending on absolute permeability reduction magnitude and change in trapped oil saturation as well as end-point relative permeability.
We introduce a new numerical algorithm to forecast gas production in organic shale that simultaneously takes into account gas diffusion in kerogen, slip flow, Knudsen diffusion, and Langmuir desorption. The algorithm incorporates the effects of slip flow and Knudsen diffusion in apparent permeability, and includes Langmuir desorption as a gas source at kerogen surfaces. We use the diffusion equation to model both lateral gas flow in kerogen as well as gas supply from kerogen to surfaces.
Slip flow and Knudsen diffusion account for higher-than-expected permeability in shale-gas formations, while Langmuir desorption maintains pore pressure. Simulations confirm the significance of gas diffusion in kerogen on both gas flow and stored gas. Relative contributions of these flow mechanisms to production are quantified for various cases to rank their importance under practical situations.
Results indicate that apparent permeability increases while reservoir pressure decreases. Gas desorption supplies additional gas to pores, thereby maintaining reservoir pressure. However, the rate of gas desorption decreases with time. Gas diffusion enhances production in two ways: it provides gas molecules to kerogen-pore surfaces, hence it maintains the gas desorption rate while kerogen becomes a flow path for gas molecules. For a shale-gas formation with porosity of 5%, apparent permeability of 59.7 µD, total organic carbon of 29%, effective kerogen porosity of 10%, and gas diffusion coefficient of 10-22 m2/s, production enhancements compared to those predicted with conventional models are: 9.6% due to slip flow and Knudsen diffusion, an extra 42.6% due to Langmuir desorption, and an additional 61.7% due to gas diffusion after 1 year of production. The method introduced in this paper for modeling gas flow indicates that the behavior of gas production with time in shale-gas formations could differ significantly from production forecasts performed with conventional models.
This study establishes a risk-neutral binomial lattice method to apply real options theory to valuation and decision-making in the petroleum exploration and production (E&P) industry under uncertain oil prices.
The research is applied to the switching time from primary to water flooding oil recovery. First, West Texas Intermediate (WTI) oil price evolution in the past 25 years, from January 2, 1986 to May 28, 2010, is studied and modeled with geometric Brownian motion (GBM) and one-factor mean reversion price models. Second, production profile for primary and water flooding oil recovery for a synthetic onshore oil reservoir is generated using UTCHEM simulator. Third, the binomial lattice real options evaluation (ROE) method is established to value the project with flexibility in switching time from primary to water flooding oil recovery.
Seven results and conclusions are reached: 1) for GBM price model, the assumptions of constant drift rate and volatility do not hold for WTI oil prices; 2) one-factor mean reversion model is better to fit WTI oil prices than GBM model; 3) the evolution of WTI oil prices in the past 25 years was according to three price regimes and since 2003, the world economy has increased its tolerance to higher oil prices and to higher price fluctuation from its long run price; 4) the established ROE method can be used to identify the best time to switch from primary to water flooding oil recovery; 5) with one-factor mean reversion oil price model and the most updated cost data, the ROE method finds that water flooding switching time is earlier than that from traditional net present value optimizing method; 6) the ROE results reveal that most of time water flooding should start when oil prices are high; and 7) water flooding switching time is sensitive to oil price models and to the investment and operating costs.
The established ROE framework enhances the valuation and decision-making for petroleum E&P industry including when to switch from one enhanced oil recovery method to another and when to switch from conventional to unconventional hydrocarbon production.
Reservoir souring refers to the onset of hydrogen sulfide (H2S) production during waterflooding. Besides health and safety issues, H2S content reduces the value of the produced hydrocarbon. Nitrate injection is an effective method to prevent the formation of H2S. Designing this process requires the modeling of a complicated set of biogeochemical reactions involved in the production of H2S and its inhibition. This paper describes the modeling and simulation of biological reactions associated with the injection of nitrate to inhibit reservoir souring. The model is implemented in a general-purpose adaptive reservoir simulator (GPAS). To the best of our knowledge, GPAS is the first field-scale reservoir simulator that models reservoir-souring treatment.
The basic mechanism in the biologically mediated generation of H2S is the reaction between sulfate in the injection water and fatty acids in the formation water in the presence of sulfate-reducing bacteria (SRB). There are proposed mechanisms that describe the effect of nitrate injection on souring remediation. Depending on the circumstances, more than one mechanism may occur at the same time. These mechanisms include the inhibitory effect of nitrite on sulfate reduction, the competition between SRB and nitrate-reducing bacteria (NRB), and the stimulation of nitrate-reducing sulfide-oxidizing bacteria (NR-SOB). For each mechanism, we specify the biological species and chemical components involved and determine the role of each component in the biological reaction. For every biological reaction, a set of ordinary-differential equations along with differential equations for the transport of chemical and biological species are solved.
The results of reported experiments in the literature are used to find the input parameters for field-scale simulations. This reservoir simulator can then predict the onset of reservoir souring and the effectiveness of nitrate injection and helps in the design of the process. The comprehensive modeling accounts for variation in biological-system characteristics and reservoir conditions that affect the production and remediation of H2S.
A great deal of research has been focused on transient two-phase flow in wellbores. However, there is lack of a comprehensive two-fluid model in the literature. In this paper, we present an implementation of a pseudo-compositional, thermal, fully implicit, transient two-fluid model for two-phase flow in wellbores. In this model, we solve gas/liquid mass balance, gas/liquid momentum balance, and two-phase energy balance equations to obtain five primary variables: liquid velocity, gas velocity, pressure, holdup, and temperature. This simulator can be used as a stand-alone code or can be used in conjunction with a reservoir simulator to mimic wellbore/reservoir dynamic interactions. In our model, we consider stratified, bubbly, intermittent, and annular flow regimes using appropriate closure relations for interphase and wall-shear stress terms in the momentum equations. In our simulation, we found that the interphase and wall-shear stress terms for different flow regimes can significantly affect the model's results. In addition, the interphase momentum transfer terms mainly influence the holdup value.
The outcome of this research leads to a more accurate simulation of multiphase flow in the wellbore and pipes, which can be applied to the surface facility design, well-performance optimization, and wellbore damage estimation.
Three hydrocarbon phases can co-exist at equilibrium at relatively low temperatures in many CO2 floods. Formation of an aqueous phase in contact with hydrocarbon phases is inevitable in almost all recovery processes, because of the permanent presence of water in the reservoirs either as injection fluid or as initial formation water. Successful modeling of CO2 flooding requires accounting for the presence of four phases. However, as the number of phases increase, flash calculations become more difficult and time-consuming. A possible approach to reduce the computational time of the phase equilibrium calculations is to use reduced methods. This paper presents a general strategy to model the behavior of CO2/hydrocarbon/water systems where four equilibrium phases occur using a reduced flash approach. The speedup obtained by a reduced flash algorithm compared to the conventional flash approach is demonstrated for a different number of components and phases. The results show a significant speedup in the Jacobian matrix construction and in Newton-Raphson iterations using the reduced method when four phases are present. The computational advantage of the reduced method increases rapidly with the number of phases and components. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of two West Texas oil/CO2 mixtures. The results show significant changes in the phase splits and saturation pressures by adding water to these CO2/hydrocarbon systems.
Many naturally fractured reservoirs around the world have depleted significantly and improved oil recovery (IOR) processes are necessary for further development. Hence, the modeling of fractured reservoirs has received increased attention recently. Accurate modeling and simulation of naturally fractured reservoirs is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make them inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent technologies of discrete fracture
modeling suffer from large simulation run times and the industry has not found applications for them yet, even though they give more accurate representations of fractured reservoirs than dual continuum models.
We developed a novel discrete fracture model for an in-house compositional reservoir simulator that borrows the dualmedium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be angled or vertical, honoring the complexity of a typical fractured reservoir. Likewise, the new discrete fracture model does not need mesh refinement around fractures and offers computationally-efficient simulations compared to other discrete fracture models. Examples of water-flooding and gas injection are presented in this paper to demonstrate the accuracy, robustness, and applicability of the developed model for studying IOR processes in naturally fractured reservoirs. Simulations show that favorable rock wettability along with capillary pressure contrasts between matrix and fractures causes noticeable incremental oil recovery in water floods. Likewise, simulations of gas injection demonstrate that high-permeability fractures not only expedite gas breakthrough, but also increase
segregation of gas towards the top of the reservoir, leading to very low sweep efficiency. Furthermore, oil recovery from naturally fractured reservoirs is found to be sensitive to the fracture inclination angle.
Ganjdanesh, Reza (U. of Texas at Austin) | Bryant, Steven Lawrence (U. of Texas at Austin) | Orbach, Raymond (University of Texas) | Pope, Gary Arnold (U. of Texas at Austin) | Sepehrnoori, Kamy (U. of Texas at Austin)
The current approach to carbon capture and sequestration (CCS) from pulverized coal-fired power plants is not economically viable without either large subsidies or a very high price on carbon. Current schemes require roughly a third of a power plant's energy for carbon dioxide capture and pressurization. The production of energy from geopressured aquifers has evolved as a separate, independent technology from the sequestration of carbon dioxide in deep, saline aquifers. A gamechanging new idea is described here that combines the two technologies and adds another: dissolution of carbon dioxide into extracted brine which is then re-injected. A systematic investigation over a range of conditions was performed to explore the best strategy for the coupled process of CO2 sequestration and energy production. Geological models of geopressuredgeothermal aquifers were developed using available data from studies of Gulf Coast aquifers. These geological models were used to perform compositional reservoir simulations of realistic processes with coupled aquifer and wellbore models.
The sequestration of carbon dioxide and other greenhouse gases in deep saline aquifers (Keith, 2009) as well as the extraction of methane and geothermal energy (heat) from deep geopressured-geothermal aquifers (Jones, 1975) have been studied independently in the past. However, capturing and storing CO2 in aquifers is an expensive process without any monetary return on investment. On the other hand, energy extraction from deep geopressured aquifers was abandoned as a result of low natural gas prices in the 70s and 80s (Griggs, 2005), which prevented this process from becoming economically feasible. In this study, we present a new strategy in which the CO2 sequestration and methane/geothermal energy extraction are combined. In fact, we suggest that the cost of the former can be offset by the profits from the latter.
Geologic formations are capable of storing huge amounts of CO2. Specifically, deep saline aquifers are the best candidates for the storage of significant amounts of CO2 emitted by pulverized coal-fired power plants. However, the storage technology faces several constraints. The most important constraint is the cost of the storage process which includes capturing, purifying, pressurizing, and injecting CO2 (Rochelle, 2009). In addition to the storage cost, other possible constraints exist such as the injection capacity of the aquifer and environmental hazards.
Formations of abnormally high pressure and temperature lie along the Gulf Coast of the United States at depths exceeding 10,000 feet. The brine in these formations is saturated with methane. The methane content of this brine is on the order of 30- 45 SCF of methane per barrel and the total amount is estimated to be between 3000 to 46000 TCF (Griggs, 2005). For example, at 34 SCF per barrel, a small geopressured aquifer with a pore volume of 1 billion barrels would hold a volume of dissolved methane of 34 BCF with an energy content of 35 trillion Btu. When CO2 is dissolved in brine saturated with methane, almost all of the methane comes out of the solution and forms a gas phase of almost pure methane (Taggart, 2009). The production of this methane could help offset the cost of CO2 storage. Moreover, the production of methane gas and/or brine saturated with methane while CO2 is being injected will reduce or eliminate concerns about pressure build-up accompanying CO2 injection. This pressure build-up is a key constraint on large-scale sequestration, because it significantly reduces achievable rates of CO2 injection.