An experimental and numerical study of chemically enhanced water alternating gas injection

In this work, an experimental study combined with numerical simulation was conducted to investigate the potential of chemically enhanced water alternating gas(CWAG) injection as a new enhanced oil recovery method.The unique feature of this new method is that it uses alkaline, surfactant, and polymer additives as a chemical slug which is injected during the water alternating gas(WAG) process to reduce the interfacial tension(IFT) and simultaneously improve the mobility ratio. In essence, the proposed CWAG process involves a combination of chemical flooding and immiscible carbon dioxide(CO2)injection and helps in IFT reduction, water blocking reduction, mobility control, oil swelling, and oil viscosity reduction due to CO2 dissolution. Its performance was compared with the conventional immiscible water alternating gas(I-WAG) flooding. Oil recovery utilizing CWAG was better by 26 % of the remaining oil in place after waterflooding compared to the recovery using WAG conducted under similar conditions. The coreflood data(cumulative oil and water production) were history matched via a commercial simulator by adjusting the relative permeability curves and assigning the values of the rock and fluid properties such as porosity, permeability, and the experimentally determined IFT data. History matching of the coreflood model helped us optimize the experiments and was useful in determining the importance of the parameters influencing sweep efficiency in the CWAG process. The effectiveness of the CWAG process in providing enhancement of displacement efficiency is evident in the oil recovery and pressure response observed in the coreflood. The results of sensitivity analysis on CWAG slug patterns show that the alkaline–surfactant–polymer injection is more beneficial after CO2 slug injection due to oil swelling and viscosity reduction. The CO2 slug size analysis shows that there is an optimum CO2 slug size,around 25 % pore volume which leads to a maximum oil recovery in the CWAG process. This study shows that the ultralow IFT system, i.e., IFT equaling 10-2or 10-3m N/m, is a very important parameter in CWAG process since the water blocking effect can be minimized.     

A laboratory study of hot WAG injection into fractured and conventional sand packs

Gas injection is the second largest enhanced oil recovery process,next only to the thermal method used in heavy oil fields.To increase the extent of the reservoir contacted by the injected gas,the gas is generally injected intermittently with water.This mode of injection is called water-alternating-gas(WAG).This study deals with a new immiscible water alternating gas(IWAG) EOR technique,"hot IWAG" which includes combination of thermal,solvent and sweep techniques.In the proposed method CO2 will be superheated above the reservoir temperature and instead of normal temperature water,hot water will be used.Hot CO2 and hot water will be alternatively injected into the sand packs.A laboratory test was conducted on the fractured and conventional sand packs.Slugs of water and CO2 with a low and constant rate were injected into the sand packs alternatively;slug size was 0.05 PV.Recovery from each sand pack was monitored and after that hot water and hot CO2 were injected alternatively under the same conditions and increased oil recovery from each sand pack and breakthrough were measured.Experimental results showed that the injection of hot WAG could significantly recover residual oil after WAG injection in conventional and fractured sand packs.     

Study on Reducing Injection Pressure of Low Permeability Reservoirs Characterized by High Temperature and High Salinity

In view of the problems of high injection pressure and low water injection rate in water injection wells of low permeability reservoirs featuring high temperature and high salinity, two new surfactants were synthesized, including a quaternary ammonium surfactant and a betaine amphoteric surfactant. The composite surfactant system BYJ-1 was formed by mixing two kinds of surfactants. The minimum interfacial tension between BYJ-1 solution and the crude oil could reach 1.4×10~(-3) mN/m. The temperature resistance was up to 140 ℃, and the salt resistance could reach up to 120 g/L. For the low permeability core fully saturated with water phase, BYJ-1 could obviously reduce the starting pressure gradient of low permeability core. While for the core with residual oil, BYJ-1 could obviously reduce the injection pressure and improve the oil recovery. Moreover, the field test showed that BYJ-1 could effectively reduce the injection pressure of the water injection well, increase the injection volume, and increase the liquid production and oil production of the corresponding production well.     

Simplified graphical correlation for determining flow rate in tight gas wells in the Sulige gas field

The Sulige tight gas reservoir is characterized by low-pressure, low-permeability and lowabundance. During production, gas flow rate and reservoir pressure decrease sharply; and in the shut- in period, reservoir pressure builds up slowly. Many conventional methods, such as the indicative curve method, systematic analysis method and numerical simulation, are not applicable to determining an appropriate gas flow rate. Static data and dynamic performance show permeability capacity, kh is the most sensitive factor influencing well productivity, so criteria based on kh were proposed to classify vertical wells. All gas wells were classified into 4 groups. A multi-objective fuzzy optimization method, in which dimensionless gas flow rate, period of stable production, and recovery at the end of the stable production period were selected as optimizing objectives, was established to determine the reasonable range of gas flow rate. In this method, membership functions of above-mentioned optimizing factors and their weights were given. Moreover, to simplify calculation and facilitate field use, a simplified graphical illustration （or correlation） was given for the four classes of wells. Case study illustrates the applicability of the proposed method and graphical correlation, and an increase in cumulative gas production up to 37% is achieved and the well can produce at a constant flow rate for a long time.     

Diffusion coefficients of natural gas in foamy oil systemsunder high pressures

The diffusion coefficient of natural gas in foamy oil is one of the key parameters to evaluate the feasibility of gas injection for enhanced oil recovery in foamy oil reservoirs.In this paper,a PVT cell was used to measure diffusion coefficients of natural gas in Venezuela foamy oil at high pressures,and a new method for determining the diffusion coefficient in the foamy oil was developed on the basis of experimental data.The effects of pressure and the types of the liquid phase on the diffusion coefficient of the natural gas were discussed.The results indicate that the diffusion coefficients of natural gas in foamy oil,saturated oil,and dead oil increase linearly with increasing pressure.The diffusion coefficient of natural gas in the foamy oil at 20 MPa was 2.93 times larger than that at 8.65 MPa.The diffusion coefficient of the natural gas in dead oil was 3.02 and 4.02 times than that of the natural gas in saturated oil and foamy oil when the pressure was20 MPa.However,the gas content of foamy oil was 16.9times higher than that of dead oil when the dissolution time and pressure were 20 MPa and 35.22 h,respectively.     

Classifi cation of carbonate gas condensate reservoirs using well test and production data analyses

Carbonate reservoir patterns play an important role in the production performance of oil and gas wells,and it is usually classified through static data analysis which cannot reflect the actual well performance.This paper takes the Tazhong No.1 gas field in the Tarim Basin,China as an example to investigate the classification of carbonate reservoirs.The classification method mainly combines well test analysis with production analysis—especially the Blasingame type curve method.Based on the characteristics of type curves for well test analysis and the Blasingame method,the relationship between the type curves and reservoir pattern was established.More than 20 wells were analyzed and the reservoirs were classified into 3 major patterns with 7 sub-classes.Furthermore,the classification results were validated by dynamic performance analysis of wells in the Tazhong No.1 gas field.On the basis of the classification results,well stimulation(i.e.water flooding in a single well) was carried out in three volatile-oil wells,and the oil recovery increased by up to 20%.     

Physical simulation of fluid low and production performance in extra-low permeability porous media

For extra-low permeability reservoirs,with a permeability of about 0.3×10-3 μm2,fluid flow and production performance in cores were studied.A long core holder with a multi-location piezometric measurement was specially designed.An artificial long core,about 700 mm long and with a cross section of 45mm×45mm,was used.In the experiment,pressure distribution along the core can be measured in real time.Single phase flow in the core was investigated.Different modes of production in long cores were also simulated including natural depletion,water flooding,and advanced water flooding.Through physical simulation,flow parameters were collected and production characteristics in extra-low permeability cores were studied.From experimental results,it can be seen that fluid flow in extra-low permeability cores is different from that in high permeability cores.Transmission of pressure in extra-low permeability cores is very slow,and it needs a long time for the pressure to become stable.The distribution curve of pressure along the core is nonlinear and the production rate in extra-low permeability reservoirs decreases sharply.The development effects of different production modes in extra-low permeability cores were compared with one another.Among the production modes,advanced water flooding has much potential for effective development of extra-low permeability reservoirs.Natural depletion and conventional water flooding can also be used in early production periods.In addition,the countermeasures and some ideas especially for the potential development of extra-low permeability reservoirs are suggested.     

A compositional model for CO_2 ooding including CO_2 equilibria between water and oil using the Peng–Robinson equation of state with the Wong–Sandler mixing rule

This paper presents a three-dimensional, three-phase compositional model considering CO_2 phase equilibrium between water and oil. In this model, CO_2 is mutually soluble in aqueous and hydrocarbon phases, while other components, except water,exist in hydrocarbon phase. The Peng–Robinson(PR) equation of state and the Wong–Sandler mixing rule with non-random two-liquid parameters are used to calculate CO_2 fugacity in the aqueous phase. One-dimensional and three-dimensional CO_2 flooding examples show that a significant amount of injected CO_2 is dissolved in water. Our simulation shows 7% of injected CO_2 can be dissolved in the aqueous phase, which delays oil recovery by 4%. The gas rate predicted by the model is smaller than the conventional model as long as water is undersaturated by CO_2, which can be considered as "lost" in the aqueous phase. The model also predicts that the delayed oil can be recovered after the gas breakthrough, indicating that delayed oil is hard to recover in field applications. A three-dimensional example reveals that a highly stratified reservoir causes uneven displacement and serious CO_2 breakthrough. If mobility control measures like water alternating gas are undertaken, the solubility e ects will be more pronounced than this example.     

Non-Darcy flow in oil accumulation （oil displacing water） and relative permeability and oil saturation characteristics of low-permeability sandstones

Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil (gas) saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone (oil displacing water), we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that: 1) Oil migration (oil displacing water) in low-permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2) With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fl uidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity is less than 1.0, the percolation curve is a “concaveup” non-Darcy percolation curve; 3) Oil-water two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4) The oil saturation of low-permeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.     

Evaluating the potential of surface-modified silica nanoparticles using internal olefin sulfonate for enhanced oil recovery

Recently, nanoparticles have proven to enhance oil recovery on the core-flood scale in challenging high-pressure high-temperature reservoirs. Nanomaterials generally appear to improve oil production through wettability alteration and reduction in interfacial tension between oil and water phases. Besides, they are environmentally friendly and cost-effective enhanced oil recovery techniques. Studying the rheological properties of nanoparticles is critical for field applications. The instability of nanoparticle dispersion due to aggregation is considered as an unfavorable phenomenon in nanofluid flooding while conducting an EOR process. In this study, wettability behavior and rheological properties of surface-treated silica nanoparticles using internal olefins sulfonates(IOS_(20–24) and IOS_(19–23)), anionic surfactants were investigated. Surface modification effect on the stability of the colloidal solution in porous media and oil recovery was inspected. The rheology of pure and surfacetreated silica nanoparticles was investigated using a HPHT rheometer. Morphology and particle size distributions of pure and coated silica nanoparticles were studied using a field emission scanning electron microscope. A series of core-flood runs was conducted to evaluate the oil recovery factor. The coated silica nanoparticles were found to alter rheological properties and exhibited a shear-thinning behavior as the stability of the coated silica nanoparticles could be improved considerably.At low shear rates, the viscosity slightly increases, and the opposite happens at higher shear rates. Furthermore, the surfacemodified silica nanoparticles were found to alter the wettability of the aqueous phase into strongly water-wet by changing the contact angle from 80° to 3° measured against glass slides representing sandstone rocks. Oil–water IFT results showed that the surface treatment by surfactant lowered the oil–water IFT by 30%. Also, the viscosity of brine increased from 0.001 to 0.008 Pa s by introducing SiO_2 nanoparticles to the aqueous phase for better displacement efficiency during chemicalassisted EOR. The core-flood experiments revealed that the ultimate oil recovery is increased by approximately 13% with a surfactant-coated silica nanofluid flood after the conventional waterflooding that proves the potential of smart nanofluids for enhancing oil recovery. The experimental results imply that the use of surfactant-coated nanoparticles in tertiary oil recovery could facilitate the displacement efficiency, alter the wettability toward more water-wet and avoid viscous fingering for stable flood front and additional oil recovery.     

Influence of formation heterogeneity on foam flooding performance using 2D and 3D models: an experimental study

The formation heterogeneity is considered as one of the major factors limiting the application of foam flooding. In this paper, influences of formation properties, such as permeability, permeability distribution, interlayer, sedimentary rhythm and 3D heterogeneity, on the mobility control capability and oil displacement efficiency of foam flooding, were systematically investigated using 2D homogeneous and 2D/3D heterogeneous models under 120 °C and salinity of 20 × 10~4 mg/L. The flow resistance of foam was promoted as the permeability increased, which thus resulted in a considerable oil recovery behavior.In the scenario of the vertical heterogeneous formations, it was observed that the permeability of the high-permeable layer was crucial to foam mobility control, and the positive rhythm appeared favorable to improve the foam flooding performance.The additional oil recovery increased to about 40%. The interlayer was favorable for the increases in mobility reduction factor and oil recovery of foam flooding when the low permeability ratio was involved. For the 3D heterogeneous formations,foam could efficiently adjust the areal and vertical heterogeneity through mobility control and gravity segregation,and thus enhancing the oil recovery to 11%–14%. The results derived from this work may provide some insight for the field test designs of foam flooding.     

Numerical Simulation Research on Energy Supplement of Low Permeability Reservoirs with Fractured Horizontal Wells

The fractured horizontal wells are widely used in many large oil fields to enhance oil recovery.Currently most of fractured horizontal wells were developed in elastic recovery.It is urgently needed to supply formation energy because of the fast production and pressure decline.In this paper,a five-spot model of horizontal wells was built based on the Jilin Oilfield geological data from the horizontal wells demonstration area.Compositional simulation were applied to study on the effectiveness of four development methods for three types of low permeability reservoirs with fractured horizontal wells and the impact of the distribution of the fracture was analyzed.Reasonable suggestions were proposed for three types of low permeability reservoirs from two aspects,development mode and fracturing design.This paper will provide some guidance for fractured horizontal well development.     

A study of hydrate plug formation in a subsea natural gas pipeline using a novel highpressure flow loop

The natural gas pipeline from Platform QK18-1 in the southwest of Bohai Bay to the onshore processing facility is a subsea wet gas pipeline exposed to high pressure and low temperature for a long distance. Blockages in the pipeline occur occasionally. To maintain the natural gas flow in the pipeline, we proposed a method for analyzing blockages and ascribed them to the hydrate formation and agglomeration. A new high-pressure flow loop was developed to investigate hydrate plug formation and hydrate particle size, using a mixture of diesel oil, water, and natural gas as experimental fluids. The influences of pressure and initial flow rate were also studied. Experimental results indicated that when the flow rate was below 850 kg/h, gas hydrates would form and then plug the pipeline, even at a low water content (10%) of a water/oil emulsion. Furthermore, some practical suggestions were made for daily management of the subsea pipeline.     

Pore-scale investigation of residual oil displacement in surfactant–polymer flooding using nuclear magnetic resonance experiments

Research on the Gangxi III area in the Dagang Oilfield shows that there was still a significant amount of oil remaining in oil reservoirs after many years of polymer flooding.This is a potential target for enhanced oil recovery(EOR).Surfactant–polymer(SP) flooding is an effective chemical EOR method for mobilizing residual oil and improving displacement efficiency macroscopically,but the microscopic oil displacement efficiency in pores of different sizes is unclear.Nuclear magnetic resonance(NMR) is an efficient method for quantifying oil saturation in the rock matrix and analyzing pore structures.In this paper,the threshold values of different pore sizes were established from the relationship between mercury injection curves and NMR T2 spectrums.The distribution and migration of residual oil in different flooding processes was evaluated by quantitatively analyzing the change of the relaxation time.The oil displaced from pores of different sizes after the water flood,polymer flood,and the SP flood was calculated,respectively.Experimental results indicate that(1) the residual oil in medium pores contributed the most to the incremental oil recovery for the SP flood,ranging from 40 % to 49 %,and small pores usually contributed \30 %;(2) the residual oil after the SP flood was mainly distributed in small and medium pores;the residual oil in medium pores accounted for 47.3 %–54.7 %,while that trapped in small pores was 25.7 %–42.5 %.The residual oil in small and medium pores was the main target for EOR after the SP flood in oilfields.     

Feasibility of Gas Drive in Fang-48 Fault Block Oil Reservoir

The Fang-48 fault block oil reservoir is an extremely low permeability reservoir, and it is difficult to produce such a reservoir by waterflooding. Laboratory analysis of reservoir oil shows that the minimum miscibility pressure for CO2 drive in Fang-48 fault block oil reservoir is 29 MPa, lower than the formation fracture pressure of 34 MPa, so the displacement mechanism is miscible drive. The threshold pressure gradient for gas injection is less than that for waterflooding, and the recovery by gas drive is higher than waterflooding. Furthermore, the threshold pressure gradient for carbon dioxide injection is smaller than that for hydrocarbon gas, and the oil recovery by carbon dioxide drive is higher than that by hydrocarbon gas displacement, so carbon dioxide drive is recommended for the development of the Fang-48 fault block oil reservoir.     

Steam Flooding after Steam Soak in Heavy Oil Reservoirs through Extended-reach Horizontal Wells

This paper presents a new development scheme of simultaneous injection and production in a single horizontal well drilled for developing small block reservoirs or offshore reservoirs. It is possible to set special packers within the long completion horizontal interval to establish an injection zone and a production zone. This method can also be used in steam flooding after steam soak through a horizontal well. Simulation results showed that it was desirable to start steam flooding after six steam soaking cycles and at this time the oil/steam ratio was 0.25 and oil recovery efficiency was 23.48%. Steam flooding performance was affected by separation interval and steam injection rate. Reservoir numerical simulation indicated that maximum oil recovery would be achieved at a separation section of 40-50 m at steam injection rate of 100-180 t/d; and the larger the steam injection rate, the greater the water cut and pressure difference between injection zone and production zone. A steam injection rate of 120 t/d was suitable for steam flooding under practical injection-production conditions. All the results could be useful for the guidance of steam flooding projects.     

Pressure Transient Analysis of Arbitrarily Shaped Fractured Reservoirs

Reservoir boundary shape has a great influence on the transient pressure response of oil wells located in arbitrarily shaped reservoirs. Conventional analytical methods can only be used to calculate transient pressure response in regularly shaped reservoirs. Under the assumption that permeability varies exponentially with pressure drop, a mathematical model for well test interpretation of arbitrarily shaped deformable reservoirs was established. By using the regular perturbation method and the boundary element method, the model could be solved. The pressure behavior of wells with wellbore storage and skin effects was obtained by using the Duhamel principle. The type curves were plotted and analyzed by considering the effects of permeability modulus, arbitrary shape and impermeable region.     

Modelling of microbial enhanced oil recovery application using anaerobic gas-producing bacteria

Microbial enhanced oil recovery （MEOR） methods apply injection of bacteria to depleted oil reservoirs to produce oil, which had remained unrecovered after the conventional methods of production. The ability ofthermophilic anaerobic bacteria to produce gas as the main mechanism in potential MEOR in high salinities of 70-100 g/L was investigated in this study. Maximum gas production of up to 350 mL per 700 mL of salty solution was produced at a salinity of 90 g/L stably during 2-4 days of experiment. The experimental results were upscaled to the Snorre Oilfield, Norway, and simulated using ECLIPSE software for 27 months. The best scenarios showed that the increase in oil recovery on average was at 21% and 17.8% respectively. This study demonstrated that anaerobic bacteria used in biogas plants could be an attractive candidate for MEOR implementation due to their ability to withstand high temperature and salinity, and produce gas in large volumes.     

Correction of source-rock permeability measurements owing to slip flow and Knudsen diffusion: a method and its evaluation

Source-rock permeability is a key parameter that controls the gas production rate from unconventional reservoirs. Measured source-rock permeability in the laboratory, however, is not an intrinsic property of a rock sample, but depends on pore pressure and temperature as a result of the relative importance of slip flow and diffusion in gas flow in lowpermeability media. To estimate the intrinsic permeability which is required to determine effective permeability values for the reservoir conditions, this study presents a simple approach to correct the laboratory permeability measurements based on the theory of gas flow in a micro/nano-tube that includes effects of viscous flow, slip flow and Knudsen diffusion under different pore pressure and temperature conditions. The approach has been verified using published shale laboratory data.The ‘‘corrected'(or intrinsic) permeability is considerably smaller than the measured permeability. A larger measured permeability generally corresponds to a smaller relative difference between measured and corrected permeability values. A plot based on our approach is presented to describe the relationships between measured and corrected permeability for typical Gas Research Institute permeability test conditions. The developed approach also allows estimating the effective permeability in reservoir conditions from a laboratory permeability measurement.     

无机盐作用下微波辐射高粘度原油的油水分离

Removal of water contained in extra-viscous crude oil is quite difficult because of the high viscosity and high resins content of heavy oil.The microwave technology was introduced for the separation of water from high-viscosity crude oil in the presence of sodium acetate.The decrease in zeta-potential of interface and the viscosity of crude oil are responsible for the accelerated separation of water under microwave irradiation.The influences of the concentration of sodium acetate in sample,irradiation pressure,irradiation time and irradiation power on the separation efficiency were investigated.The optimum technological condition for the refining process was determined.Upon treating the sample 1 (with a water concentration of 50%),the water removal rate was 98.44%,when the optimum conditions were identified to be a sodium acetate concentration of 2%,an irradiation pressure of 0.1 MPa,an irradiation time of 2 min,and an irradiation power of 225 W,with the recovery of sodium acetate reaching 97.88%.Upon treating the sample 2 (the concentration of water was 20%),the water removal rate was 93.85%,when the optimum conditions were determined to be a sodium acetate concentration of 3%,an irradiation pressure of 0.1 MPa,an irradiation time of 4 min,and an irradiation power of 375 W,with the recovery of sodium acetate reaching 93.54%.By using this method,the dehydration efficiency was increased rapidly.