Pressure Evolution and Production Performance of Waterflooding in n-Heptane-Saturated Fired Berea Cores

SPE Journal ◽  
2014 ◽  
Vol 19 (04) ◽  
pp. 674-686 ◽  
Author(s):  
N.. Rezaei ◽  
A.. Firoozabadi
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Injection Pressure ◽  
Injection Rate ◽  
Production Performance ◽  
Breakthrough Time ◽  
Initial Water ◽  
Viscous Forces ◽  
The Core ◽  
Recovery Performance

Summary This work presents experimental results and interpretation of injection pressure and recovery performance of waterflooding in strongly water-wet fired Berea cores saturated with n-heptane. The experiments were conducted at constant injection rate at room conditions, and the effects of injection rate and initial water saturation on the oil-recovery performance and dynamic-injection pressure were investigated. Elements of surprise were observed in the injection-pressure data. The pressure profiles showed four distinct regimes, each governed by capillary or viscous forces. At low capillary numbers (Ca=uμ/σ<10–6), capillarity governed two pressure regimes, corresponding to the core inlet and outlet. In the early part of waterflooding, pressure stayed constant for a considerable time before hydrodynamic pressure gradient could overcome the capillary pressure gradient. After viscous forces dominated, a linear increase in injection pressure over time was observed up to breakthrough time. A sudden pressure rise was observed close to breakthrough because of capillary retention at the core outlet. The pressure became constant after the breakthrough when the water- and oil-saturation distributions were stabilized. Changing the injection rate by an order of magnitude in the range from 2.2 to 22.2 pore volumes (PV)/D (equivalent to Ca = 10–7 to 10–6) did not appreciably change the oil-recovery performance; similar breakthrough time and final oil recovery were observed. The effect of initial water saturation was also investigated. When lowering the initial water saturation beyond that established in oil flooding, production performance and injection pressure were similar to those of a core without the initial water saturation. The injection pressure at breakthrough was found to decrease with increase of the initial water saturation. Waterflooding was modeled by including the capillary pressure and excellent agreement was obtained with experimental results of production and injection pressure. We find that in the absence of in-situ saturation measurements, the injection pressure is a better variable for tuning the model parameters compared with the production history alone.

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

2014 ◽  
Vol 1073-1076 ◽  
pp. 2310-2315 ◽  
Author(s):  
Ming Xian Wang ◽  
Wan Jing Luo ◽  
Jie Ding
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Low Permeability ◽  
Reservoir Permeability ◽  
Engineering Parameters ◽  
The Common ◽  
Common Problems ◽  
Low Permeability Reservoirs

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

Coreflood Model Calibration for Alkali Surfactant Polymer Process from a High Salinity Reservoir to Design an ASP Pilot

2021 ◽  
Author(s):  
Marisely Urdaneta
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Water Saturation ◽  
Polymer Concentration ◽  
Chemical Flooding ◽  
Adsorption Parameters ◽  
Oil Saturation ◽  
The Core ◽  
Asp Flooding

Abstract This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.

A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment

SPE Journal ◽  
2020 ◽  
pp. 1-26
Author(s):  
Sajjaat Muhemmed ◽  
Harish Kumar ◽  
Nicklaus Cairns ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Carbon Dioxide ◽  
Water Saturation ◽  
Injection Rate ◽  
Mineral Dissolution ◽  
Carbonate Mineral ◽  
Carbonate Minerals ◽  
Oil Saturation ◽  
The Core ◽  
Three Phase ◽  
Water Saturated

Summary Limited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media. A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F. A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents’ calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process. In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b < 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study

scholarly journals Magnetic Resonance Imaging of Methane Hydrate Formation and Dissociation in Sandstone with Dual Water Saturation

Energies ◽  
2019 ◽  
Vol 12 (17) ◽  
pp. 3231
Author(s):  
Stian Almenningen ◽  
Per Fotland ◽  
Geir Ersland
Keyword(s):  
Magnetic Resonance Imaging ◽  
Magnetic Resonance ◽  
Methane Hydrate ◽  
Water Saturation ◽  
High Water ◽  
Growth Patterns ◽  
Resonance Imaging ◽  
Initial Water ◽  
Hydrate Dissociation ◽  
The Core

This paper reports formation and dissociation patterns of methane hydrate in sandstone. Magnetic resonance imaging spatially resolved hydrate growth patterns and liberation of water during dissociation. A stacked core set-up using Bentheim sandstone with dual water saturation was designed to investigate the effect of initial water saturation on hydrate phase transitions. The growth of methane hydrate (P = 8.3 MPa, T = 1–3 °C) was more prominent in high water saturation regions and resulted in a heterogeneous hydrate saturation controlled by the initial water distribution. The change in transverse relaxation time constant, T2, was spatially mapped during growth and showed different response depending on the initial water saturation. T2 decreased significantly during growth in high water saturation regions and remained unchanged during growth in low water saturation regions. Pressure depletion from one end of the core induced a hydrate dissociation front starting at the depletion side and moving through the core as production continued. The final saturation of water after hydrate dissociation was more uniform than the initial water saturation, demonstrating the significant redistribution of water that will take place during methane gas production from a hydrate reservoir.

Quantifying the Impact of Permeability Heterogeneity on Secondary-Recovery Performance

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 455-468 ◽  
Author(s):  
B.. Rashid ◽  
A.H.. H. Muggeridge ◽  
A.. Bal ◽  
G.. Williams
Keyword(s):  
Oil Recovery ◽  
Single Phase ◽  
Viscosity Ratio ◽  
Shear Strain Rate ◽  
Breakthrough Time ◽  
Permeability Heterogeneity ◽  
Secondary Recovery ◽  
Recovery Performance ◽  
The Impact ◽  
Immiscible Displacements

Summary An improved heterogeneity/homogeneity index is introduced that uses the shear-strain rate of the single-phase-velocity field to characterize heterogeneity and rank geological realizations in terms of their impact on secondary-recovery performance. The index is compared with the Dykstra-Parsons coefficient (Dykstra and Parsons 1950) and the dynamic Lorenz coefficient (Shook and Mitchell 2009). The results show that the index's ranking ability is preserved for miscible and immiscible displacements at different viscosity/mobility ratios. Neither the Dykstra-Parsons coefficient (Dykstra and Parsons 1950) nor the dynamic Lorenz coefficient (Shook and Mitchell 2009) can consistently discriminate between different realizations in terms of breakthrough time and oil recovery at 1 pore volume injected (PVI) for tracer flow or adverse-viscosity-ratio miscible and immiscible floods.

scholarly journals Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiang Li ◽  
Yuan Cheng ◽  
Wulong Tao ◽  
Shalake Sarulicaoketi ◽  
Xuhui Ji ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

scholarly journals Geological sequestration of CO2 in a water-bearing reservoir in hydrate-forming conditions

2020 ◽  
Vol 75 ◽  
pp. 51
Author(s):  
Raghvendra Pratap Singh ◽  
Karanpal Singh Shekhawat ◽  
Malay K. Das ◽  
Krishnamurthy Muralidhar
Keyword(s):  
Water Saturation ◽  
Formation Rate ◽  
Hydrate Formation ◽  
Injection Pressure ◽  
Injection Well ◽  
Reservoir Temperature ◽  
Isothermal Model ◽  
Initial Water ◽  
Continuous Increase ◽  
Hydrate Reservoir

Higher concentration of carbon dioxide in the atmospheric air is a major environmental challenge and requires immediate attention for quicker mitigation. In that respect, the novel idea of CO2 sequestration in geological settings is worth examining from a quantitative perspective. In the present study, numerical simulation of CO2 injection into a porous reservoir is performed. The selected reservoir presents suitable thermodynamic conditions for CO2 hydrate formation. Unsteady simulations are carried out in one space dimension under isothermal and non-isothermal frameworks. An additional simulation of CO2 injection in a depleted methane hydrate reservoir is also reported. In the present study, the response of the reservoir to storage of CO2 is analyzed with respect to four parameters – reservoir porosity, initial water saturation and reservoir temperature and injection pressure. Quantities of interest are hydrate formation patterns and the cumulative CO2 mass sequestration in the reservoir as a function of time. Numerical experiments show that the initial water saturation is an important parameter as it affects both CO2 gas migration and hydrate formation. Isothermal simulation yields results that are similar to the non-isothermal model, thus suggesting that the isothermal assumption may be adopted for future CO2 injection studies. Hydrate formation rate of CO2 near the injection well is found to be one order of magnitude higher than the interior but its magnitude is quite small when compared to water and gas saturations. Higher injection pressure leads to a continuous increase in injected mass of CO2 primarily due to increased gas density, though an increase in hydrate formation near the injection well is also observed. Lower reservoir temperature supports a higher amount of hydrate formation from the injected mass of CO2 and is clearly desirable.

Effect of Initial Water Saturation on Bypassed Oil Recovery during CO2 Injection at Different Miscibility Conditions

2015 ◽  
Vol 29 (7) ◽  
pp. 4114-4121 ◽  
Author(s):  
Keyvan Kazemi ◽  
Behzad Rostami ◽  
Maryam Khosravi ◽  
Danial Zeinabady Bejestani
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Injection ◽  
Initial Water ◽  
Bypassed Oil

Pore-Scale Modeling of Wettability Effects and Their Influence on Oil Recovery

1999 ◽  
Vol 2 (01) ◽  
pp. 25-36 ◽  
Author(s):  
A.B. Dixit ◽  
S.R. McDougall ◽  
K.S. Sorbie ◽  
J.S. Buckley
Keyword(s):  
Crude Oil ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Aging Process ◽  
Water Saturation ◽  
Contact Angles ◽  
Initial Water ◽  
Water Imbibition ◽  
Pore Level ◽  
Capillary Pressure Curves

Summary The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed. Introduction In crude oil/brine/rock (COBR) systems, pore level displacements of oil and brine and hence the corresponding petrophysical flow parameters (e.g., Pc and krw/kro) describing these displacements are governed by the pore geometry, topology and wettability of the system. A number of excellent review papers are available that describe experimental investigations of the effect of wettability on capillary pressure and oil-water relative permeability curves.1–5 In COBR systems, wettability alterations depend upon the mineralogical composition of the rock, pH and/or composition of the brine, crude oil composition, initial water saturation, reservoir temperature, etc.6–12 Therefore, in recent years, interest in restoring the wettability of reservoir core using crude oil and formation brine has greatly increased.3,4,13,14 In this approach, cleaned reservoir core is first saturated with brine and then oil flooded to initial water saturation using crude oil. The core containing crude oil and brine is then aged to alter its wettability state. Wettability measurements, such as Amott and USBM tests, and waterflood experiments are then typically conducted on the aged core. This entire process broadly mimics the actual flow sequences in the reservoir; consequently, the wettability alterations are more realistic than those achieved using chemical treatment methods. During the aging process, wettability may be altered to vastly different degrees depending upon many factors, including those mentioned above. In addition, aging time, thickness of existing water films and wetting film disjoining pressure isotherms also play important roles. Hence, the final wettability state of a re-conditioned core will generally be case specific.

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