ROLE OF GEOMICROBIOLOGY IN ENHANCED RECOVERY OF OIL: STATUS QUO

1978 ◽  
Vol 18 (1) ◽  
pp. 161
Author(s):  
B. Bubela
Keyword(s):  
Biological Activity ◽  
Crude Oil ◽  
Oil Recovery ◽  
Field Experiments ◽  
Enhanced Recovery ◽  
Reservoir Rock ◽  
Oil Viscosity ◽  
Reservoir Water ◽  
Composite Effect ◽  
General Terms

The forthcoming decrease in availability of known, presently economical deposits of crude oil in the foreseeable future, makes it imperative that the search for new oil deposits be intensified and the present methods of oil recovery be improved or new ones introduced. From the work reported in the literature it is obvious that microbiology may play a significant role in both cases. Among many parameters influencing oil recovery, viscosity of the oil and the surface tension between the rock, oil and water are of great importance. Microorganisms growing in the reservoir produce gases and surfactants, which may, to some extent, regenerate the endogenous energy of the reservoir and facilitate movement of the crude oil to the well. The composition of the crude oil may become altered by biodegradation of asphaltic, napthenic and/or paraffinic components of the oil. The fraction being biodegraded varies according to the microbiological population present. In general terms mixed populations are more effective in biodegradative processes and production of surfactants. A combination of sewage microorganisms and reservoir microorganisms adapted to 95°C and high pressure, was found satisfactory. Molasses is a suitable supplementary substrate for the growth of such a mixed population. A decrease of viscosity of oil, resulting from biological degradation, may be a composite effect of degradation of highly polymerised hydrocarbons, precipitation of asphaltenes and solution of biologically produced gases in the oil. Such biogenic gases dissolved in the reservoir water may, in combination with biologically produced acids, contribute to the slow solution of the sedimentary rock, thus increasing the rock's permeability and facilitating migration of the oil through the reservoir.The biological activity in the reservoir is influenced by a number of parameters (pH, Eh, temperature, pressure, oil-water dispersion, mineralisation). The permeability of the reservoir rock is of primary importance. Rocks of permeability less than 150 md are not suitable for biologically enhanced recovery. Field tests indicate that biological activity in a reservoir may result in a drop of 50 per cent in the oil viscosity, a three-fold increase of oil production over several months, increase in water acidity and additional production of gas with a recorded pressure increase from 2 atm to 27 atm. The area affected by the biological activity depends on the mineralogy and permeability of the reservoir rock, sandstone and limestone of permeability higher than 600 md being most suitable.Further properly controlled and documented laboratory and field experiments are urgently required before the feasibility of microbiologically enhanced oil recovery can be firmly established.

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

2021 ◽  
Author(s):  
Ali Reham Al-Jabri ◽  
Rouhollah Farajzadeh ◽  
Abdullah Alkindi ◽  
Rifaat Al-Mjeni ◽  
David Rousseau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Field ◽  
Reservoir Rock ◽  
Sultanate Of Oman ◽  
Industrial Chemicals ◽  
Oil Viscosity ◽  
Injection Strategy ◽  
Operational Conditions

Abstract Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.

scholarly journals Experimental Study on Reducing CO2–Oil Minimum Miscibility Pressure with Hydrocarbon Agents

Energies ◽  
2019 ◽  
Vol 12 (10) ◽  
pp. 1975 ◽  
Author(s):  
Junrong Liu ◽  
Lu Sun ◽  
Zunzhao Li ◽  
Xingru Wu
Keyword(s):  
Crude Oil ◽  
Petroleum Ether ◽  
Oil Recovery ◽  
Mass Concentration ◽  
Co2 Flooding ◽  
Oil Viscosity ◽  
Injection Wells ◽  
Boiling Range ◽  
Minimum Miscibility Pressure ◽  
Soluble Surfactants

CO2 flooding is an important method for improving oil recovery for reservoirs with low permeability. Even though CO2 could be miscible with oil in regions nearby injection wells, the miscibility could be lost in deep reservoirs because of low pressure and the dispersion effect. Reducing the CO2–oil miscibility pressure can enlarge the miscible zone, particularly when the reservoir pressure is less than the needed minimum miscible pressure (MMP). Furthermore, adding intermediate hydrocarbons in the CO2–oil system can also lower the interfacial tension (IFT). In this study, we used dead crude oil from the H Block in the X oilfield to study the IFT and the MMP changes with different hydrocarbon agents. The hydrocarbon agents, including alkanes, alcohols, oil-soluble surfactants, and petroleum ethers, were mixed with the crude oil samples from the H Block, and their performances on reducing CO2–oil IFT and CO2–oil MMP were determined. Experimental results show that the CO2–oil MMP could be reduced by 6.19 MPa or 12.17% with petroleum ether in the boiling range of 30–60 °C. The effects of mass concentration of hydrocarbon agents on CO2–oil IFT and crude oil viscosity indicate that the petroleum ether in the boiling range of 30–60 °C with a mass concentration of 0.5% would be the best hydrocarbon agent for implementing CO2 miscible flooding in the H Block.

Asphaltene Deposition Induced by Carbon Oxide and its Influence on Displacement Efficiency

2012 ◽  
Vol 594-597 ◽  
pp. 2451-2454
Author(s):  
Feng Lan Zhao ◽  
Ji Rui Hou ◽  
Shi Jun Huang
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Carbon Oxide ◽  
Viscosity Reduction ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Asphaltene Deposition ◽  
Total Oil

CO2is inclined to dissolve in crude oil in the reservoir condition and accordingly bring the changes in the crude oil composition, which will induce asphaltene deposition and following formation damage. In this paper, core flooding device is applied to study the effect of asphaltene deposition on flooding efficiency. From the flooding results, dissolution of CO2into oil leads to recovery increase because of crude oil viscosity reduction. But precipitated asphaltene particles may plug the pores and throats, which will make the flooding effects worse. Under the same experimental condition and with equivalent crude oil viscosity, the recovery of oil with higher proportion of precipitated asphaltene was relatively lower during the CO2flooding, so the asphltene precipitation would affect CO2displacement efficiSubscript textency and total oil recovery to some extent. Combination of static diffusion and dynamic oil flooding would provide basic parameters for further study of the CO2flooding mechanism and theoretical evidence for design of CO2flooding programs and forecasting of asphaltene deposition.

Correlation of Crude Oil Steam Distillation Yields With Basic Crude Oil Properties

1983 ◽  
Vol 23 (06) ◽  
pp. 937-945 ◽  
Author(s):  
Ching H. Wu ◽  
Robert B. Elder
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Boiling Point ◽  
Steam Distillation ◽  
Recovery Process ◽  
Steam Injection ◽  
Steam Pressure ◽  
Oil Viscosity ◽  
Simulated Distillation ◽  
Distillation Yield

Abstract Steam distillation can occur in reservoirs during steam injection and in-situ combustion processes. To estimate the amount of vaporized oil caused by steam distillation, we established correlations of steam distillation yields with the basic crude oil properties. These correlations were based on steam distillation tests performed on 16 crude oils from various pans of the U.S. The gravity of oils varied from 12 to 40 deg. API [0.99 to 0.83 g/cm3]. The viscosity of oil ranged from 5 to 4,085 cSt [5 to 4085 mm /s] at 100 deg. F [38 deg. C]. The steam distillations were performed at a saturated steam pressure of 220 psia [1.5 MPa]. One oil sample was used in experiments to investigate the effect of steam pressure (220 to 500 psia [1.5 to 3.4 MPa]) on the steam distillation yield. The experiments were carried out to a steam distillation factor (Vw/Voi) of 20, with the factor defined as the cumulative volume of condensed steam used in distillation, Vw, divided by the initial volume of oil, Voi. At a steam distillation factor of 20, the distillation yields ranged from 13 to 57% of the initial oil volume. Several basic crude oil properties can be used to predict steam distillation yields reasonably well. A correlation using oil viscosity in centistokes at 100 deg. F [38 deg. C] can be used to predict the steam distillation yield within a standard error of 4.3 %. The API gravity can be used to estimate wields within 5.6%. A gas chromatographic analysis was made for each crude oil to obtain the component boiling points (simulated distillation temperatures). A correlation parameter was selected from the simulated distillation results that can be used to estimate the steam distillation yields within 4.5%. Introduction Steamflooding has been used commercially to recover heavy oils for several decades. Although it is considered a heavy-oil recovery process, it has been demonstrated to be an effective and commercially feasible process for recovering light oils. To enhance the effectiveness of the oil recovery process, it is important to fully understand and utilize the basic steamflooding mechanisms. Willman et al. investigated the mechanisms of steamflooding. They concluded that oil viscosity reduction, oil volume expansion, and steam distillation are the major mechanisms for oil recovery. Since then, more research has been done on all phases of steam injection. However, steam distillation and its ramifications on recovery have not been quantified fully because of lack of experimental data. Steam distillation can lower the boiling point of a water/oil mixture below the boiling point of the individual components. SPEJ P. 937^

scholarly journals An experimental investigation of asphaltene stability in heavy crude oil during carbon dioxide injection

2019 ◽  
Vol 10 (3) ◽  
pp. 919-931 ◽  
Author(s):  
Sherif Fakher ◽  
Mohamed Ahdaya ◽  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Crude Oil ◽  
Pore Size ◽  
Oil Recovery ◽  
Asphaltene Precipitation ◽  
Carbon Dioxide Injection ◽  
Oil Viscosity ◽  
Membrane Pore ◽  
Pore Sizes ◽  
Filter Membrane

Abstract Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs.

Prediction of Recovery in Unstable Miscible Flooding

1972 ◽  
Vol 12 (02) ◽  
pp. 143-155 ◽  
Author(s):  
E.L. Claridge
Keyword(s):  
Economic Evaluation ◽  
Crude Oil ◽  
Oil Recovery ◽  
Pore Space ◽  
Vertical Direction ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Recovery Processes ◽  
First Choice

Abstract A new correlation bas been developed for estimating oil recovery in unstable miscible five-spot pattern floods. It combines existing methods of predicting areal coverage and linear displacement efficiency and was used to calculate oil recovery for a series of assumed slug sizes in a live-spot CO2 slug-waterflood pilot test. The economic optimum slug size varies with CO2 cost; at anticipated CO2 costs the pilot would generate an attractive profit if performance is as predicted Introduction Selection of good field prospects for application of oil recovery processes other than waterflooding is often difficult. The principal reason is that other proposed displacing agents are far more costly proposed displacing agents are far more costly than water and usually sweep a lesser fraction of the volume of an oil reservoir (while displacing oil more efficiently from this fraction). Such agents must be used in limited amounts as compared with water; and this amount must achieve an appreciable additional oil recovery above waterflooding recovery. For these reasons, there is in general much less economic margin for engineering error in processes other than waterflooding. The general characteristics of the various types of supplemental recovery processes are well known, and adequate choices can be made of processes to be considered in more detail with respect to a given field. Comparative estimates must then be made of process performance and costs in order to narrow the choice. A much more detailed, definitive process-and-economic evaluation is eventually process-and-economic evaluation is eventually required of the chosen process before an executive decision can be made to commit large amounts of money to such projects. It is in the area between first choice and final engineering evaluation that this work applies. A areal cusping and vertical coning into producing wells. These effects can be seated by existing "desk-drawer" correlation which can confirm or deny the engineer's surmise that he has an appropriate match of recovery process and oil reservoir characteristics is of considerable value in determining when to undertake the costly and often manpower-consuming task of a definitive process-and-economic evaluation. process-and-economic evaluation. An examination of the nature of the developed crude oil resources in the U.S. indicates that the majority of the crude oil being produced is above 35 degrees API gravity and exists in reservoirs deeper than 4,000 ft. The combination of hydrostatic pressure on these oil reservoirs, the natural gas usually present in the crude oil in proportion to this pressure, the reservoir temperatures typically found, and the distribution of molecular sizes and types in the crude oil corresponding to the API gravity results in the fact that, in the majority of cases, the in-place crude oil viscosity was originally no more than twice that of water. A large proportion of these oil reservoirs have undergone pressure decline, gas evolution and consequent increase in crude oil viscosity. However, an appreciable proportion are still at such a pressure and proportion are still at such a pressure and temperature that miscibility can be readily attained with miscible drive agents such as propane or carbon dioxide, and the viscosity of the crude oil is such that the mobility of these miscible drive agents is no more than 50 time s that of the crude oil. Under these circumstances, a possible candidate situation for the miscible-drive type of process may exist. process may exist. Supposing that such a situation is under consideration, the next question is: what specific miscible drive process, and how should it be designed to operate? In some cases, the answer is clear: when the reservoir has a high degree of vertical communication (high permeability and continuity of the permeable, oil-bearing pore space in the vertical direction), then a gravity-stabilized miscible flood is the preferred mode of operation; and the particular drive agent or agents can be chosen on the basis of miscibility requirements, availability and cost. SPEJ P. 143

Thermally Active Polymer To Improve Sweep Efficiency of Waterfloods: Simulation and Pilot Design Approaches

2012 ◽  
Vol 15 (01) ◽  
pp. 86-97 ◽  
Author(s):  
R.. Garmeh ◽  
M.. Izadi ◽  
M.. Salehi ◽  
J.L.. L. Romero ◽  
C.P.. P. Thomas ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Pilot Project ◽  
Oil Reservoirs ◽  
Reservoir Rock ◽  
Sensitivity Analyses ◽  
Chemical Components ◽  
Chemical Adsorption ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Thief Zone

Summary A common problem in many waterflooded oil reservoirs is early water breakthrough with high water cut through highly conductive thief zones. Thermally active polymer (TAP), which is an expandable submicron particulate of low viscosity, has been successfully used as an in-depth conformance to improve sweep efficiency of waterfloods. This paper describes the workflow to evaluate technical feasibility of this conformance technology for proper pilot-project designs supported with detailed simulation studies. Two simulation approaches have been developed to model properties of this polymer and its interaction with reservoir rock. Both methods include temperature-triggered viscosification and adsorption/retention effects. Temperature profile in the reservoir is modeled by energy balance to accurately place this polymer at the optimum location in the thief zone. The first method considers a single chemical component in the water phase. The second method is based on chemical reactions of multiple chemical components. Both simulation approaches are compared and discussed. Results show that temperature-triggered polymers can increase oil recovery by viscosification and chemical adsorption/retention, which reduces thief-zone permeability and diverts flow into unswept zones. Sensitivity analyses suggest that ultimate oil recovery and conformance control depend on the thief-zone temperature, vertical-to the horizontal-permeability ratio (Kv/Kh), thief-zone vertical location, injection concentration and slug size, oil viscosity, and chemical adsorption and its reversibility, among other factors. For high-flow-capacity thief zones and mobility ratios higher than 10, oil recoveries can be improved by increasing chemical concentration or slug size of treatments, or both. Reservoirs with low Kv/Kh (< 0.1) and high permeability contrast generally shows faster incremental recoveries than reservoirs with high Kv/Kh and strong water segregation. The presented workflow is currently used to perform in-depth conformance treatment designs in onshore and offshore fields and can be used as a reference tool to evaluate benefits of the TAP in waterflooded oil reservoirs.

Role of Intermolecular Forces on Surfactant-Steam Performance into Heavy Oil Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-6
Author(s):  
Lee Yeh Seng ◽  
Berna Hascakir
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Intermolecular Forces ◽  
Immiscible Fluids ◽  
Reservoir Rock ◽  
Crude Oils ◽  
Head Group ◽  
Polar Head Group ◽  
Polar Head

Summary This study investigates the role of polar fractions of heavy oil in the surfactant-steamflooding process. Performance analyses of this process were done by examination of the dipole-dipole and ion-ion interactions between the polar head group of surfactants and the charged polar fraction of crude oil, namely, asphaltenes. Surfactants are designed to reduce the interfacial tension (IFT) between two immiscible fluids (such as oil and water) and effectively used for oil recovery. They reduce the IFT by aligning themselves at the interface of these two immiscible fluids; this way, their polar head group can stay in water and nonpolar tail can stay in the oil phase. However, in heavy oil, the crude oil itself has a high number of polar components (mainly asphaltenes). Moreover, the polar head group in surfactants is charged, and the asphaltene fraction of crude oils carries reservoir rock components with charges. The impact of these intermolecular forces on the surfactant-steam process performance was investigated with 10 coreflood experiments on an extraheavy crude oil. Nine surfactants (three anionic, three cationic, and three nonionic surfactants) were tested. Results of each coreflood test were analyzed through cumulative oil recovery and residual oil content. The performance differences were evaluated by polarity determination through dielectric constant measurements and by ionic charges through zeta potential measurements on asphaltene fractions of produced oil and residual oil samples. The differences in each group of surfactants tested in this study are the tail length. Results indicate that a longer hydrocarbon tail yielded higher cumulative oil recovery. Based on the charge groups present in the polar head of anionic surfactants resulted in higher oil recovery. Further examinations on asphaltenes from produced and residual oils show that the dielectric constants of asphaltenes originated from the produced oil, giving higher polarity for surfactant-steam experiments conducted with longer tail length, which provide information on the polarity of asphaltenes. The ion-ion interaction between produced oil asphaltenes and surfactant head groups were determined through zeta potential measurements. For the most successful surfactant-steam processes, these results showed that the changes on asphaltene surface charges were becoming lower with the increase in oil recovery, which indicates that once asphaltenes are interacting more with the polar head of surfactants, then the recovery rate increases. Our study shows that the surfactant-steamflooding performance in heavy oil reservoirs is controlled by the interaction between asphaltenes and the polar head group of surfactants. Accordingly, the main mechanism that controls the effectiveness of the process is the ion-ion interaction between the charges in asphaltene surfaces and the polar head group of crude oils. Because crude oils carry mostly negatively charged reservoir rock particles, our study suggests the use of anionic surfactants for the extraction of heavy oils.

Applied Research of Heat Self-Generated CO2 Technology in Steam Huff and Puff

2014 ◽  
Vol 1010-1012 ◽  
pp. 1693-1698
Author(s):  
Yi Ding ◽  
Guo Wei Qin ◽  
Peng Liu ◽  
Zi Li Fan ◽  
Hong Wei Xiao ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Field Experiments ◽  
Reduction Rate ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Blowing Agent ◽  
Steam Flooding ◽  
Gas Flooding

Heat self-generated CO2 technique is proposed, which is focused on the problems of recovery difficulty, poor effect steam soaking and so on for heavy oil reservoirs. This technology is combining of steam flooding and gas flooding and so on. Its main mechanism is the application of steam heating blowing agent to generate a large volume of gases (including CO2, NH3, etc) in the formation. While some of these gases acting with the oil to reduce the oil viscosity, some form miscible flooding to reduce water interfacial tension, so as to achieve the purpose of enhancing oil recovery. An optimized selection of the heat blowing agents was performed. By comparison the difference before and after the reaction of blowing agent solution, the increase of alkaline is occurred after the reaction, and is helpful to reduce oil viscosity and lower interfacial tension, etc. Studies indicate that heat-generating CO2 flooding technology can get a maximum viscosity reduction rate of 76.7%, oil-water interfacial tension decreased by 54.77%, further improve oil recovery by 4.17% based on the steam drive, which shows a technical advantage toward conventional EOR method. The field experiments indicate that the technique can greatly improve the oil production, which will provide a powerful technical supporting for the efficient development of heavy oil.

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