EOR and reservoir simulation

An experimental study of nanofluids intended for enhanced oil recovery is presented in this work. An aqueous solution of anionic surface-active agents with addition of light non-ferrous metal nanoparticles was used as the focus of the study. It is shown that the use of the nanofluid permitted a 70–90% reduction of surfacetension on an oil boundary in comparison with surface-active agent aqueous solution and is characterized by ashift in dilution. Use the developed nano-suspension results in a considerably increase EOR

Tunu is a mature giant gas field, located in swamp area of Mahakam delta. It covers an area of 75 km long and 15 km wide with enormous multi-layer sand-shale series deposited within a deltaic environment. The production commenced in 1990 and peaked in 1999 (1.5 Bcfd yearly average), with current production around 600 MMscfd, and nearly 1,200 wells drilled from 34 platforms. As the field is entering into the late stage of its life and number of new wells being drilled is decreasing, the field potential is now quite dependent on the existing perforation portfolio. Owing to the significant number of wells, with multi-layer reservoirs encountered by each well, the perforation portfolio needs to be managed in an efficient and detailed manner. An intensive well review has been performed, involving more than 9,000 reservoirs located in over 800 active wells. It commenced with an evaluation of perforation gain and its associated risks at reservoir level, which are then progressively summarized into higher levels; well, platform, and field. Perforation sequences are then defined for each well following a bottom-up perforation strategy while also adapting the risks of each reservoir. Ultimately, an organized reservoir chart is constructed where we can dynamically surveil the field perforation portfolio. Results of this intensive well review have enabled the shift of production forecast methodology from statistical toward deterministic approach. In the new approach, for instance, perforation sequences and time interval between the sequences in each well are deterministically determined on a well by well basis according to the aforementioned reservoir chart. Compared to the previous methodology, this new approach yields a better representation of the actual operations. Another area benefited by the results of the intensive well review is the optimization of well intervention planning. The identified workload is grouped together based on the remaining perforation portfolio of each platform while also respecting their location to define several well intervention clusters. Implementation of this clustering system optimizes perforation planning which reduces the time spent by perforation barges to travel from one platform to another, thus allowing more time for perforation.

Nowadays various recovery mechanisms are used in the petroleum industry to increase hydrocarbon production as much as possible in a given oil and gas field. Water flooding being the main technology used, it recovers 10 to 40 percent of the oil in place. Many factors are causes of this low recovery percentage that can be the fingering effect etc. The remaining oil in the reservoir can be divided into two categories that are: the remaining oil beyond water flooding process and bypassed oil.
The purpose of this research is to examine the efficiency of polymer flooding compared to water flooding, examine the effect of oil viscosity change due to change in reservoir pressure and temperature, and make a proper choice of polymer concentration for better oil recovery for the Tambaredjo oil field by doing simulation on the black oil reservoir model.
Firstly, water flooding was simulated, and various cases were investigated such as water injection rate and well pattern. The five spots well pattern has given a higher recovery compared to two spots and nine spots well patterns. And the water injection rate of 22,000Stb/Day has given better recovery compared to 11,000Stb/Day, 15,000Stb/Day, 20,000Stb/Day and 22,000Stb/Day. Thus, the five spots well pattern and 22,000Stb/Day were used in the second step which is polymer flooding.
Secondly, polymer flooding was simulated and various values of polymer concentration were set. The better polymer concentration was 22lb/bbl because it has given a better oil recovery compared to 2lb/bbl, 6lb/bbl, 10lb/bbl,14lb/bbl and 18lb/bbl.
Thirdly, an examination of oil viscosity change was done by varying the reservoir oil viscosities in the oil PVT table. This case helped to understand the effect of reservoir pressure and temperature change that affect reservoir oil viscosity and thus affect also the oil recovery.
The oil recovery increased from 16% (case of water flooding) to 24.5% (case of polymer flooding). This allows us to conclude that with the reservoir model on which the study was done, polymer flooding is not favorable for the Tambaredjo oil field. But this last sentence would be validated after performing one of the stimulations methods to see if there will be an increase in the oil recovery from this field. A study would be undertaken to examine either one of the stimulation methods would improve the oil recovery from the Tambaredjo oil field.

Recently, the need to decrease CO2 concentration in the atmosphere has been recognized because of the role of CO2 as a greenhouse gas that contributes to global warming. Carbon Capture and Sequestration (CCS) is one of the most promising long term solutions for the reduction of CO2 in the atmosphere. To this end, injection of CO2 into saline aquifers has been proposed and investigated theoretically and experimentally in the last years. Modeling the storage of CO2 in saline aquifers on a reservoir scale is very demanding with respect to computational cost. Long-term subsurface storage of CO2 in saline aquifers may induce a range of chemical processes in response to disturbances in existing chemical equilibria that include, but are not limited to, dissolution of primary minerals and precipitation of secondary carbonates. CCS projects also can be done above the ground by injecting CO2 into designated fractures. The work presented in this thesis focuses on developing a fundamental understanding and modeling approach for 3 basic aspects of sequestration: 1) the effect of CO2 solubility on rates of geochemical reactions, 2) density of brine after dissolution of CO2, and 3) time dependent porosity variation of a single fracture due to precipitation of carbonates.
A new method is developed to determine the reaction rates of minerals, on the basis of transition state theory, in saline aquifers containing brine and a supercritical CO2 phase. A general Arrhenius-type equation that depends explicitly on the pH of brine is employed to determine the reaction rates. The dependence of pH on the amount of aqueous CO2 dissolved in brine is modeled in this study. An accurate pressure-volume-temperature-composition (PVTx) model is employed to determine the dissolution of supercritical CO2 in brine for the temperature range of 50-100°C and pressures up to 600 bar. Solubility of CO2 and dissolution rate of calcite predicted by the model are validated with experimental data available in the literature for specific thermodynamic and salinity conditions. The effects of CO2 activity on pH and reaction rates are evaluated by means of four different models for the activity coefficient of dissolved CO2. The results indicate that dissolution of CO2 decreases the pH of the system but an increase in the temperature and salinity values limits the pH reduction. The rates of reactions are found to increase with pressure and temperature. The results suggest that among the available mineral compositions in deep saline aquifers, the dissolution rate of anorthite is the rate limiting factor. The significance of the pre-exponential factor and the reaction order associated with the modified Arrhenius equation is evaluated to determine the sensitivity of the reaction rates as a function of the system pH. We find that the transition state theory can reasonably reproduce experimental data with new parameters that we are obtained in this study on the basis of sensitivity analysis. Finally, we develop a long-term geochemical modeling of CO2 storage on a designated fracture above the ground to investigate the impacts of temperature, pressure, and salinity on the reaction rates and, subsequently, the critical time of blockage due to precipitation of carbonates.
With regards to the second focus of this thesis, the effect of CO2 solubility on the density of binary H2O-CO2 and ternary H2O-CO2-NaCl solutions in saline aquifers is investigated. These solution densities as dispensable properties play pivotal roles in estimating the dynamic evolution of plume containing aqueous CO2 and brine and also affect fracture dynamics in geologic media. An improved model is proposed to predict the density of saturated binary and ternary solutions as a function of pressure, temperature, and salinity. The model is based on an extended form of the Redlich-Kwong Equation of State that yields more representative values of the molar volumes of liquid CO2. The extension involves finding new coefficients for the cubic Redlich-Kwong equation to match one of the solutions with the liquid molar volume deduced from experimentally measured density of binary solutions. The new coefficients are constrained to ensure that the solution branch corresponding to the molar volume in the gas phase remains unchanged. Due to variability in the experimentally measured density of binary solutions, an effective liquid molar volume is obtained with the help of a multi-parameter non-linear regression with respect to pressure and temperature. The proposed model is validated by comparing it with experimental data and is used to study the density-pressure-temperature-salinity relationship. It is found that the density of the saturated solution is proportional to the mole fraction of dissolved CO2. In general, solution density is found to increase with pressure but decreases with an increase in temperature within the range of 50-100_C. It is also found that the solution density decreases monotonically with an increase in salinity.
Finally, a new model is presented to simulate a reactive fluid within a fracture. Permeability of a fracture controls the path of aqueous CO2 migration, therefore aperture width of a fracture has a pivotal effect on solubility and mineral trapping of injected CO2. This study investigates the impact of the formation of precipitates within fractures on CO2 transport and storage capacity. The problem involves the flow of CO2 between finite walls that represents a single fracture. Fluid convection, diffusion, and chemical reactions inside a finite space are solved as a simplified representation of natural mineral trapping. The model is composed of direct numerical simulation of incompressible ow and transport combined with the kinetics of corresponding chemical reactions. For each time step, transport and reactions are solved by means of a finite difference method using a sequential non-iterative approach. The purpose of the current study is to show the time evolution of the aperture shrinkage caused by precipitation of calcite. The current model predicts the actual efficiency of the mineral trapping mechanism by considering the physical properties of the fluid such as its density, pH, and the characteristics of the mineral compositions. It is found that for low Peclet numbers (Pe < 100), the critical time for a fracture blockage is insensitive to the Reynolds number and increases with the Peclet number. At a high Peclet number Pe = 1000, however, the critical time generally decreases with increasing Reynolds number.

An offshore gas field located about 56 km from the coast of East Africa with the water depth of 1153 m. The permeability distribution varies across different layers with an overall permeability of 680 mD, and porosity distribution for the reservoir varies 0.21-023. The reservoir thickness also varies up to 50 m thick. This work identifies parameters that will contribute to the impact of water coning by observing the effect of water coning/cresting in horizontal gas wells and predicting the performance of these wells using Petrel simulator. Results have shown that, locating horizontal well in East-west will have early water breakthrough and not recommended due to the impact of edge aquifer and less recovery compared to north-south and original wells orientation (northwest-southeast). Varying height of perforation of the well and standoff between 30 m and 40 m will delay water coning and high recovery with more extended plateau length period. The gas recovery was observed to be low, due to the distribution of permeability layer for the horizontal wells and low productivity index (performance of the well). Rate-dependent skin and mechanical skin evolution in time show that increasing non-Darcy /turbulence factor reduces the performance of the well and decreases gas recovery, the high drawdown tendency is observed before water breakthrough time. Horizontal gas wells have a constant horizontal length of 300 m. Increasing tubing head pressure from 40 bar to 100 bar result to decrease plateau length period of the gas production, low water production rate, and low gas recovery. Varying the kv/kh ratio from 0.1, 0.6 to 1 shows early water breakthrough by 6 months earlier from the base case with 0.1 hence will not delay water coning and the gas recovery is reduced by 5%. There is a stronger of the aquifer from the west side, which is predictable to cause water coning than on the east side. This aquifer impacts the gas recovery reduction by 19 %, with water coning radial extension of 1.7 km and peak water production rate for 16 years. The aquifer influx rate is seen to be increased by 69% when the aquifer volume is double. Therefore, from the results, producing at a high rate that has high recovery before the impact of aquifer or water has occurred to the wells, known as outrunning of the aquifer. To avoid water coning, using advance completion technique such as inflow control devices (ICD), installing a down hole gauge. Also, it is essential not to perforate if well is near to gas water contact, the horizontal wells should be located at maximum distance from gas water contact to maximize gas recovery. Not only that but also use of fully open choke allows much water production rate increase, which leads to water coning.

Dengan permintaan energy semakin meningkat terutama energy fosill fuel ( oil & gas), maka sangat penting untuk meningkatkan recovery factor dan gas terutama pada fase tertiary  ( EOR) . Injeksi polimer  merupakan salah satu dari bagian chemical flooding injection( EOR) dapat  meningkatkan nilai recovery factor ,  polimer  yang digunakan  adalah sintetsis ( add cross) dan biopolymer ( XC-P), Uji yang dilakukan adalah uji larutan ( rheology) dan juga uji fisik batuan dari hasil uji tersebut baru dapat dilakukan core flooding metode untuk mengetahui nilai Rf. Hasil yang didapat dari core flooding  penambahan polimer yang paling baik adalah larutan G4 dengan core sintetis T2, dengan niali Rf dari hasil injeksi polimer 0.26 (26 %), mobility ratio 0.25853, XC-P ( G4) memiliiki kestabilan terhadap kenaikan salinitas terutama pada salinitas 15.000 ppm. Untuk core properties T2 memiliki porositas 44%, Ka brine 2.196624 mD, Ka. Polimer 0.926591 mD

Kata Kunci : EOR, Polimer Synthetic, Biopolimer, uji rheology, recovery factor

In order to reduce the permeability to water or brine, there is a possibility of polymer injection into the reservoir. In the present work, special focus has been paid in polymer [partially hydrolyzed polyacrylamide (PHPA)] injection as a part of chemical method. Tests were conducted in the laboratory at the ambient temperature to examine the reduction in permeability to water or brine in the well-prepared sand packed after the polymer injection. The experiments were performed to study the effect of polymer adsorption on permeability reduction by analyzing residual resistance factor values with different concentrations of polymer solutions. The rheological behavior of the polymer has also been examined. The experimental results also indicate that the adsorption behavior of polymer is strongly affected by salinity, solution pH, and polymer concentration. To investigate the effect of polymer adsorption and mobility control on additional oil recovery, polymer flooding experiments were conducted with different polymer concentrations. It has been obtained that with the increase in polymer concentrations, oil recovery increases.

The limitation of Steam Injection to depths (usually not more than 5000-ft) has been a subject of concern in the application of Steam Injection for heavy and extra heavy oil recovery. This is usually as a result of the complex mechanism of heat loses occurring in the wellbore and consequently the heat loss distribution in the reservoir. A conventional approach to the optimization of steam injection has been based on isolated analysis of the well system aimed at maintaining adequate steam quality at the sandface at optimal injection rate, pressure, temperature and overall heat transfer coefficient. This often result to total neglect of the effect of the interaction between the well system and the reservoir system in the Model results. This research work therefore presents an integrated approach in the modelling of steam injection project that incorporates both the well system and the reservoir system. In this study, a three (3) case-study wells were analyzed which are located at INJ1 (1, 1), PROD1 (5, 5) and PROD2 (9, 1) respectively. The results of the findings reveals that the conventional practice of maintaining sufficient SQ at the sandface is not the last optimization strategy in real field scenario. This is because the efficiency of the heavy oil displacement by the steam is a co-function of the effective SQ at the sandface, the FHLR/FHLT and the relative distance of the injector(s) from the producer(s) which are characterized by the thermal properties of the reservoirs. As part of the objectives of this study, a novel numerical approach using PROSPER wellbore simulator is presented for analysing the impact of reservoir back pressure on the estimated SQ. The results as presented in the work shows that wrong estimations of downhole SQ can result from the total neglect of Reservoir Pressure especially in relatively deeper wells.

This article provides a summary and overview of enhanced oil recovery (EOR) technologies. Thermal recovery methods, gas injection and chemical techniques are the main categories of the EOR. Each category has its own criteria and conditions to improve oil recovery.

The Capillary number hypothesis is very empirical in Surfactant flooding Enhanced Oil Recovery (EOR) method. which is of modest experience on the North Sea and many other offshore platforms. The capillary number drives the force wetting processes, which is controlled by the balance between capillary and viscous forces. The mobilization of oil trapped in pores of water-wet rock is steered by capillary number that is typically within specific ranges (𝟏0E−𝟓 to 𝟏0E−𝟒). There is high uncertainty and confusion in the parameterization of capillary number formula, as every quantity is given on a macroscale level. As demonstrated herein, a new microscopic capillary number parameterization was proposed. This paper is written to improve the numerical formulation of capillary number in surfactant flooding model. The new formula for capillary number was derived based on existing equations as a function of residual oil saturation and tested. Thus, the proposed mobility mechanism easily accounts for a broader critical range of capillary number(𝟏0E−𝟔 to 𝟏0E−𝟒) in comparison with available models with a critical capillary number(𝟏0E−𝟓 to 𝟏0E−𝟒). We used an existing model to quantify the effect of capillary number on a miscible and immiscible relative permeability curves by computing the interpolation parameter 𝑭_𝒌𝒓 as a tabulated function of the Logarithm (base 10) of the capillary number using a new capillary number formulation.

Magnetic iron oxide and titanium dioxide nanoparticles (NPs) have been synthesized inside stable oil-in-water microemulsions in harsh environment of high temperature-high salinity (HT-HS). Screening of anionic−nonionic mixture of commercial surfactants was carried out to identify the appropriate compositions for the production of stable microemulsions in harsh environment. The effects of salinity and NPs formation on interfacial tension and rheological properties of micro-emulsions were evaluated and compared with other studies. It was found that oil-in-water microemulsions exhibit a non-Newtonian behavior in the absence of NPs, while the surfactant solutions show Newtonian behavior. The shear-thinning characteristic of microemulsions was improved and the interfacial tension between microemulsions and oil phase was increased after generation of NPs. A set of flooding experiments were accomplished using a microfluidic device to assess the efficiency of enhanced oil recovery on the pore scale in the absence and presence of NPs. The flooding tests confirmed the improvement of oil recovery efficiency after the formation of NPs inside the microemulsions. The oil displacement of API flooding was equal to 69.8% and the maximum oil displacement of 76.9% was observed after the injection of microemulsion containing iron oxide NPs.

Enhanced Oil Recovery (EOR) has been implemented since 1975 to help address growing domestic consumption in India. However, less than 4% of India’s oil is currently being produced by EOR techniques. Further resources could be tapped in the future to help reduce the country’s dependence on imported oil which now accounts for 79% of total consumption. This is particularly important as India became the 3rd largest oil consumer in mid-2015, behind China and the United States, with demand set to rise in line with increases in population and development.

Two of the basins where EOR has been applied are the Cambay and Barmer Basins, located in the states of Gujarat and Rajasthan respectively. The basins were formed due to continental rifting during the Late Cretaceous associated with the break-up of the super continent Gondwana. The rifting created two elongated NNW-SSE depressions which have been filled with fluvial and marine deposits resulting in the source, seal and reservoir rocks which are present today. Important trapping mechanisms include rift related structural traps as well as stratigraphic pinch outs.

Despite similar evolutions for both basins, there has been a marked difference in the exploration of the two. The Cambay Basin has entered into a mature stage after extensive exploration and production over the past 70 years and still accounts for ~13% of India’s yearly oil production. Conversely, the Barmer Basin was unattractive for exploration until 1999, when new seismic surveying and processing techniques were applied. A total of 37 discoveries have been made since then and the basin now accounts for ~23% of India’s yearly oil production.

This paper looks into the impact of two EOR techniques: In-Situ Combustion (ISC) and Chemical Flooding, in the Cambay and Barmer Basins respectively. The production gain from these techniques, combined with cost reduction through improved efficiencies, could help to promote the techniques to other fields in the country.

All along its rugged coastline, and high in the mountain ranges of its desert quarters, historic port cities and forts bear witness to Oman' s rich heritage of trading and seafaring. In ancient times, dhows from Oman traded frankincense with the far-off kingdoms of Rome and China. Later, Oman would become home to a maritime empire that reached as far as Zanzibar in East Africa. Today, the thriving Sultanate of Oman is reasserting its role at the crossroads of Asia, Europe and Africa and steering a course to a dynamic and prosperous future. The Government of His Majesty Sultan Qaboos bin Said Al Said and its partners in the private sector are investing in new infrastructure and industries, adding value to the country' s oil and gas resources and creating jobs for Oman' s young and resourceful people. At the same time, Oman is applying state-of-the-art technologies to sustain its production of hydrocarbons, developing know-how that is exportable across the Middle East. As traders and travellers from across the world rediscover its legendary charms, Oman is embarking on a new era of growth and opportunity.

Advancing technology in thermal recovery and declining conventional oil resources are leading to the increased application of thermal heavy oil recovery processes. Heavy oil resources in carbonate rock are estimated at 1.6 trillion bbl, one-third of which is in the Middle East, making it a crucial part of the global energy supply. A thorough understanding of reservoir properties (including but not limited to natural fracture systems, fluid saturation, permeability and rock matrix) is fundamental to optimizing recoveries with existing uncertainties, where efficient optimization through simulation can lead to the application of optimum operational decision parameters combined with improved understanding of the significance of such uncertainty parameters. Steam-assisted gravity drainage (SAGD) provides many advantages compared to conventional surface mining extraction techniques and alternate thermal recovery methods. These advantages include significantly greater per-well production rates, greater reservoir recoveries, reduced water treating costs, and dramatic reductions in steam-oil ratios (SORs). However, carbonate reservoirs exhibit varying properties in terms of porosity, permeability, and flow mechanisms. Many other engineering considerations exist for SAGD, including recovery rate, thermal efficiency, capability and economics of drilling horizontal well pairs, steam quality, steam injection rate, steam pressure, sand production, reservoir pressure maintenance, and water intrusion. In this study, such parameters are simulated and optimized by coupling a numerical reservoir simulator with commercial optimization software featuring exploratory, gradient, and direct methods. A dual permeability approach to modeling naturally fractured reservoirs is used. The results are discussed and the significance of both uncertainty and decision parameters is outlined in addition to the added benefits of optimized solutions using various optimization techniques. The results and observations show significant improvement using the optimum combination of decision parameters, such as steam injection rate, pressure, and temperature, to improve recoveries with a good understanding of the significance of uncertainty parameters, including rock and formation properties, in addition to overburden conditions that can affect the SAGD process. Reservoir management requires effective risk management where a sound understanding of uncertainties is fundamental to success. This study outlines all of these parameters in a comparative way, which can be useful in future industry applications. Modeling fractures in carbonates in heavy oil reservoirs is not an easy task because of the modeling and computational difficulties. It is important to have solid thorough examples, including building the model, setting up the optimization workflow of uncertainty, and outlining the results in a comparative manner to enhance understanding for more efficient reservoir management during SAGD processes.

With the relatively modest natural gas price, producing oil from unconventional shale reservoirs has attracted more and more interest from oil operators. Although many tremendous efforts have been made to develop shale resources, the ultimate oil recovery is still low (5–10%). Because of the important role of shale resources in the future oil and gas industry, more stimulation and production strategies are being considered and tested to find ways to improve oil production from shale reservoirs. Before applying a specific method to enhance oil recovery (EOR) in the field or conducting a research in laboratory, the simulation approach is a cheap and fast approach to evaluate its EOR potential. The analysis of simulation results will be helpful in designing laboratory experiments and field testing. In this paper we use a simulation approach to evaluate the EOR potential in shale oil reservoirs by gas flooding and waterflooding. Production behavior and oil recovery of different schemes are discussed through sensitivity studies. Simulation results of primary production, gas injection and water injection are compared. Results show that miscible gas injection has a higher potential to improve oil recovery from shale oil reservoirs than water injection. Gas injection above a minimum miscible pressure (MMP) can be fully miscible with oil, thus reducing oil viscosity significantly, in addition to the mechanism of pressure maintenance. Simulation results indicate that the oil recovery factor can be increased up to 15.1% by gas injection in a hydraulically fractured shale reservoir, whereas the oil recovery factor from the primary depletion is only 6.5%. The oil recovery from waterflooding is about 11.9% which is lower than that from gas flooding. The results indicate that miscible gas flooding could be a way to enhance oil recovery in shale oil reservoirs.

Most giant clastic reservoirs in Iraq will need to apply enhanced oil recovery in the near future, as these reservoirs go to maturity. The need to develop a rapid and cheap assessment of the enhanced oil recovery methods has become a hot topic in petroleum engineering. Different field-scale heterogeneous geological models were built based on the Nahr Umr reservoir in the Subba oilfield to perform compositional reservoir simulations. The BoxeBehnken experimental design was employed to build and verify the proxy assessment model of miscible CO 2-WAG flooding. Four operational parameters of the miscible CO 2-WAG process were considered, including CO 2 slug size, ratio of CO 2 slug size to water slug size, cyclic length and bottom hole pressure. Using the proxy model, significant first order interactions were sorted out and different operating parameter interactions were established and analyzed for the evaluation of the miscible CO 2-WAG process. In similar oil reservoirs with similar geological conditions and fluid properties to the Nahr Umr reservoir, the proxy model can be applied to roughly predict the incremental oil recovery over the miscible CO 2-WAG flooding process at different levels of operating parameters. The approach could serve as screening criteria and a guide for the application of CO 2-WAG projects.

The Capillary number hypothesis is very empirical in Surfactant flooding Enhanced Oil Recovery (EOR) method. which is of modest experience on the North Sea and many other offshore platforms. The capillary number drives the force wetting processes, which is controlled by the balance between capillary and viscous forces. The mobilization of oil trapped in pores of waterwet rock is steered by capillary number that is typically within specific ranges (10 to 10). There is high uncertainty and confusion in the parameterization of capillary number formula, as every quantity is given on a macroscale level. As demonstrated herein, a new microscopic capillary number parameterization was proposed. This paper is written to improve the numerical formulation of capillary number in surfactant flooding model. The new formula for capillary number was derived based on existing equations as a function of residual oil saturation and tested. Thus, the proposed mobility mechanism easily accounts for a br...

Currently, the share of new fields in many places over the world, which are at the initial stage of development, is constantly growing. Fields often have a complex heterogeneous structure with hard-to-recover reserves, therefore, for their effective development, it is necessary to use completely new approaches, including improving existing methods of enhanced oil recovery. In this work, experimental verification of a new technology using oil-soluble polymers and comparing it with technology based on the use of water-soluble polymers has been performed. In laboratory conditions, a new technology for polymer flooding at an early stage of development using oil-soluble polymers was developed and experimentally confirmed. The new technology has made it possible to increase the degree of reserves recovery by an average of 30% compared to existing methods of enhanced oil recovery and to solve a number of problems arising from the use of water-soluble polymers. Such problems are the freezing of aqueous polymer solutions in winter and the poor solubility of polymers in formation waters with a high salt content. The use of new technology can also reduce energy costs by 25%.

Carbon dioxide flooding is considered one of the most commonly used miscible gas injections to improve oil recovery, and its applicability has grown significantly due to its availability, greenhouse effect and easy achievement of miscibility relative to other gases. Therefore, miscible CO 2-injection is considered one of the most feasible methods worldwide. For long-term strategies in Iraq and the Middle East, most oilfields will need to improve oil recovery as oil reserves are falling. This paper presents a study of the effect of various CO 2-injection modes on miscible flood performance of the highly heterogeneous clastic reservoir. An integrated field-scale reservoir simulation model of miscible flooding is accomplished for this purpose. The compositional simulator, Eclipse composi-tional, has been used to investigate the feasibility of applying different miscible CO 2-injection modes. The process of the CO 2-injection was optimized to start in January 2056 as an improved oil recovery method after natural depletion and waterflooding processes have been performed, and it will continue to January 2072. The minimum miscibility pressure was determined using empirical correlations as a function of reservoir crude oil composition and its properties. Four miscible CO 2-injection modes were undertaken to investigate the reservoir performance. These modes were, namely the continuous CO 2-injection (CCO 2), water-alternating-CO 2-injection (CO 2-WAG), hybrid CO 2-WAG injection, and simultaneous water and CO 2-injection (CO 2-SWAG) processes. All injection modes were analyzed in respect to the net present value (NPV) and net present value index (NPVI) calculations to confirm the more feasible CO 2 development strategy. The results indicated that the application of CO 2-SWAG injection mode of 2:1 SWAG ratio attained the highest oil recovery, NPV and NPVI, among the other modes. The achieved incremental oil recovery by this process was 9.174 %, that is 189 MM STB of the oil produced higher than the waterflooding case, 1.113 % (23 MMSTB of oil) in comparison with the CCO 2-flooding case, 1.176 % (24.3 MMSTB of oil) in comparison with the hybrid CO 2-WAG case and almost 0.987 % (204 MMSTB of oil) when compared with the CO 2-WAG case. The results indicated that the application of CO 2-WAG injection mode of 1.5:1 WAG ratio attained the highest oil recovery after the SWAG process.

A method for isolating water inflow in gas wells is proposed, which consists in pumping a water-insulating composition into the water saturated interval using gas as a blowing fluid. The results of studies on physical models of the reservoir are presented, which prove an increase in the penetrating ability of the water repellent, blockage density of water-permeable channels and a decrease in phase permeability of water. These results were obtained in both water and gas saturated porous mediums. It is observed also that the gas blowing of a water isolating composition contributes in reduction of the reverse removal of the composition from theporous medium, as a result of a more uniform distribution of the water isolating composition in the porous medium.

In reservoir engineering, an oil reservoir is commonly modeled using Darcy’s diffusion equation for a porous medium. In this work we propose a fractional diffusion equation to model the pressure distribution, p(x, t), of fluid in a horizontal one-dimensional homogeneous porous reservoir of finite length, L, and uniform thickness. A chief concern in this work is to examine the sensitivity of the pressure distribution, p(x, t), to different forms of pseudo-diffusivity, K, including cases when it depends upon the order of the fractional derivative (α), 0 ≤ α &lt; 1 (e.g., K ∝ (1 – α)), which may be more realistic for some types of rock formations. In all cases the systems show a near-linear increase in the pressure difference P(x, t) = (p(x, t) – pi)/pi in the reservoir for large times, where pi = p(x, t = 0). For x/L &lt; 0.4, the rate of increase of P with time increases with α, but there is a crossover at x/L = 0.4 and this trend reverses for x/L &gt; 0.4. When K = 10k (k is the con...

The tasks of applying new technologies of oil production are urgent. These technologies must significantly be able to increase the oil recovery of already developed formations, where it is no longer possible to extract significant residual oil reserves by traditional methods. Among these technologies is the microbial enhanced oil recovery method (MEOR). It is a tertiary crude oil recovery technology that allows partial recovery of residual oil that cannot be recovered by primary and secondary methods, thereby extending the life of developed oil reservoirs. MEOR is based on the activation of reservoir microflora. A special group of hydrocarbon-oxidizing microorganisms is able to metabolize hydrocarbons, producing organic solvents such as alcohols and aldehydes, fatty acids with surface activity, gaseous products and other metabolites that increase the mobility of oil.

In this study series of runs were done by a CFD technique in which the injected fluid is nanoparticles/supercritical CO2. Geometry of the porous medium was created with the commercial grid generation tool (Gambit software). Continuity, momentum and volume fraction equations were solved based on the finite volume method. The benefits of existing nanoparticles in the gas injection process have been investigated. The numerical results show that addition of nanosilica into the supercritical CO2 improves the oil recovery. It was also found that by increasing the nanoparticles concentration from 1 Vol. % to 2 Vol. %, the oil recovery factor increases about 5%. In addition, obtained results confirmed that by injecting the nanofluid fingers are reduced. The displacing fluid
containing nanoparticles is more efficient than the supercritical CO2 in sweeping the in-situ oil.

The upstream petroleum industry faces operational and technical problems due to increased deposition of
waxes, aromatics and asphaltene from crude oil sludge in oil storage tanks in the form of tank-bottom
sludge (TBS). This results in huge production losses, and threatens environmentally safe operation;
therefore, safer solutions are needed. In this work, nine aromatic ionic liquids (ILs) are synthesized and
tested for the dissolution of TBS with the aid of five solvents, namely, toluene, heptane, decane, ethyl
acetate and hexane. The UV absorbance values of the standard solutions (TBS in solvent) are compared
with the sample solutions (TBS in solvent + ILs). It is observed that ILs significantly improve the
dissolution of TBS in solvents compared with neat solvent alone. Different weight ratios of TBS : ILs (1 : 1,
1 : 0.5 and 1 : 0.1) are considered in this study. Ionic liquids (ILs) based on an imidazolium cation and
various anions, such as [Cl]
, [Br]
, [BF4]
, [H2PO4]
, [HSO4]
, and [PF6]
, are considered in this
investigation. It is observed that the dissolution of TBS in heptane in the presence of [HMIM]+[Br]
is
efficient to a maximum extent of 66% with other solvents showing similar increased solubility effect with
various ILs. In the case of hexane, it should be noted that the efficiency of dissolution of TBS goes on
decreasing with increasing concentration of TBS in hexane. A hold-time study is also performed with
heptane containing ILs and heptanes without ILs to determine the maximum time required for efficient
dissolution of TBS. It is observed that the efficiency is increased beyond 66% in the presence of ILs for
the dissolution of TBS in heptane, provided that the mixture of solvent and ILs are in contact with the
TBS for a prolonged period of 30 days, or even longer as required. FT-IR and 13C-NMR spectral analyses
are also performed so as to understand the efficiency of the ILs in the dissolution of TBS in various
solvents, and it was observed that there is a decrease in the intensity of the peaks in the spectra of
treated TBS with solvents, which is further enhanced by the addition of ILs.

Residual oil saturation can quantitatively be determined by logging and coring methods, but these methods have a small radius of investigation. Therefore, the Single Well Tracer Test (SWTT) method is a better alternative because it has an investigation radius of 10 - 30 ft from the wellbore. However, the measurement of Sor using the SWTT method becomes ineffective if the parameters used are not optimal, causing errors in interpretation. The observation parameters for determining the effect of Sor measurement results on chemical tracer concentrations in SWTT should be conducted. The concentration of MeOH on overflush and shut-in time is used as a reference to determine the effectiveness of surfactant injection, namely changes in Sor before and after surfactant injection. The SWTT principle is to inject the ethyl Acetate (EtAc) into the wellbore, and based on the hydrolysis reaction between EtAc and H2O to produce a product in the form of Ethyl Alcohol (EtOH) as a secondary tracer. This reaction occurs until the equilibrium state. The remaining EtAc dissolve in oil, and cannot be dissolved in water. Meanwhile EtOH dissolve in water. As a result, EtOH moves more easily than EtAc. The impact of this phenomenon is the cumulative production of EtAc and EtOH at different peak concentrations (retardation factor). This difference becomes an indicator for measuring Sor. If the retardation factor is big, the greater the Sor obtained, and vice versa. If the retardation factor is small, the Sor is small also. The STARS simulator is a product issued by the Computer Modeling Group (CMG), modeling can include multicomponent, multiphase, chemical flooding, chemical reaction models and single well tracer tests, this simulator can determine the behavior of reservoir fluids on homogeneous or heterogeneous porous media. After analyzing the relative permeability curve, scenario 1 case 10 is the best scenario because the Sor is 0.4. The parameters used are the concentration of EtAc 0.0025 mole fraction, MeOH 0.011 mole fraction and shut-in time of 2.5 days. After surfactant injection, Sor 0.26 was obtained. This means that there is a 14% Sor decrease after surfactant injection that proves the success of the SWTT method in monitoring the effectiveness of surfactant injection. Based on the peak concentrations of EtAc, and EtOH before and after surfactant injection, it can be concluded that an increase in the concentration of EtAc is followed by a decrease in Sor. On the other hand, the decrease in EtOH concentration was followed by an increase in Sw.

This study is intended to expand the scope of microbial enhanced oil recovery (MEOR) simulation studies from 1D to field scale focussing on fluid viscosity variation and heterogeneity that lacks in most MEOR studies. Hence, we developed a model that incorporates: (1) reservoir simulation of microbe-induced oil viscosity reduction and (2) field-scale simulation and robust geological uncertainty workflow considering the influence of well placement. Sequential Gaussian simulation, co-kriging and artificial neural network were used for the petrophysical modelling prior to field-scale modelling. As per this study, the water viscosity increased from 0.5 to 1.72 cP after the microbe growth and increased biomass/biofilm. Also, we investigated the effect of the various component compositions and reaction frequencies on the oil viscosity and possibly oil recovery. For instance, the fraction of the initial CO 2 in the oil phase (originally in the reservoir) was varied from 0.000148 to 0.005 to promote the reactions, and more light components were produced. It can be observed that the viscosity of oil reduced considerably after 90 days of MEOR operation from an initial 7.1-7.07 cP and 6.40 cP, respectively. Also, assessing the pre-and post-MEOR oil production rate, we witnessed two main typical MEOR field responses: sweeping effect and radial colonization occurring at the start and tail end of the MEOR process, respectively. MEOR oil recovery factors varied from 28.2 to 44.9% OOIP for the various 200 realizations. Since the well placement was the same for all realizations, the difference in the permeability distribution amongst the realizations affected the microbes' transport and subsequent interaction with nutrient during injection and transport.

The paper aims at explaining how politicization (Lagroye, 2003 ; Swyngedouw, 2004) of the industries of the subsurface in France in the last decade contributes to generate conflicting narratives about the limits of the Earth at different scales. By politicization, we mean the social process of rendering political objects that were previously unnoticed, unknown, inserted in regulated procedures, or framed under other narratives. Politicization encompassed a wide array of phenomenon that called for a political action or decision toward an issue that have been constructed through the work of actors. Neutralization processes such as technicization of an issue (Henry, 2007), naturalization of a mechanism and negation of a problem have also to be considered as tactics of depoliticization which are intrinsically political. In this paper, two enhanced oil recovery technologies (EOR) – hydraulic fracturing and carbon dioxide injection – participate to redefine scenarios of energy transition in France. On the one side, unconventional oil and gas extracted with hydraulic fracturing increase the inventory of fossil-fuels. On the other side, underground carbon storage allows controlling downstream flows of carbon and reducing carbon footprint. These two technologies are in turns meant to expand the boundaries of energy production and to contribute to pollution of the environment. However, while public and collective actions in France criticized the expansion of extractivism (Svampa, 2016) through a ban on fracking (Chailleux, 2016), carbon storage was mostly constrained by a weak carbon market and localized opposition. In both cases, local projects allowed various publics to criticize the different scales of regulation of those technical solutions to shape the struggle against climate change. Questioning those local projects, those collectives challenged the uses of the subsurface for energy transition (including gas production and storage, nuclear waste and carbon storage). The credibility, legitimacy and governance of those two EOR technologies determined their definition in regard with energy transition. Compagnon (forthcoming) insists on the lack of credibility and legitimacy of the technofixes related to climate change. He outlines the intractable problems emerging for the global governance of geoengineering. We operationalize such issues in differentiating the credibility, the legitimacy and the governance of a technology. Credibility refers to the demonstration of the feasibility based on the declared objectives of the technofix, the nature of knowledge used by supporters, the economic context of development, and the scenario for the future. Legitimacy refers to the social acceptance or rejection of the technology at the local, national, and international scales. The level of social mobilization is our indicator for legitimacy. Governance targets the type of engagement and frames from industrial and political actors, and the existing regulation. It refers to the structured relationships between actors. The comparison shows contrasted forms of politicization of EOR techniques. Lack of legitimacy and credibility and major weaknesses in the governance precluded the development of hydraulic fracturing. Lack of credibility did not stop the development of carbon capture and storage yet despite a mitigated political support. We discussed the importance of the legitimacy tests, the redefinition of the limits of the Earth in the scenario for the future, and the role of conflicts in shaping the future.

We present the results of an experimental investigation of the effect of gas type and composition on foam transport in porous media. Steady-state foam strengths with respect to three cases of distinct gases and two cases containing binary mixtures of these gases were compared. The effects of gas solubility, the stability of lamellae, and the gas diffusion rate across the lamellae were examined. Our experimental results showed that the steady-state foam strength is inversely correlated with the gas permeability across a liquid lamella, a parameter that characterizes the rate of mass transport. The results are also in good agreement with existing observations that the foam strength for a mixture of gases is correlated with the less soluble component. Three hypotheses with different predictions of the underlying mechanism that explain the role of gas type and composition in foam strength are discussed in detail.

This research simulated oil recovery with emphasis on oil viscosity reduction by direct microbe action and metabolites; predicted hydrogeochemical reactions involved with nutrient – brine interaction in reservoirs. PHREEQC was used to simulate reactions between the reservoir brine and nutrient minus microbe. Hitherto, UTCHEM was employed for the enhancement of oil viscosity by assuming production of gases and by the direct microbe action. The model depicted the precipitation of calcite plus dissolution of k-feldspar combined with the evolution of CO2 and CH4 influenced by temperature and pH. Oil
recovery was directly proportional to salinity reduction and increasing nutrient concentration.

We present the results of an experimental investigation of the effect of gas type and composition on foam transport in porous media. Steady-state foam strengths with respect to three cases of distinct gases and two cases containing binary mixtures of these gases were compared. The effects of gas solubility, the stability of lamellae, and the gas diffusion rate across the lamellae were examined. Our experimental results showed that the steady-state foam strength is inversely correlated with the gas permeability across a liquid lamella, a parameter that characterizes the rate of mass transport. The results are also in good agreement with existing observations that the foam strength for a mixture of gases is correlated with the less soluble component. Three hypotheses with different predictions of the underlying mechanism that explain the role of gas type and composition in foam strength are discussed in detail.