CO2 Minimum Miscibility Pressure: A Correlation for Impure CO2 Streams and Live Oil Systems

1985 ◽  
Vol 25 (02) ◽  
pp. 268-274 ◽  
Author(s):  
R.B. Alston ◽  
G.P. Kokolis ◽  
C.F. James
Keyword(s):  
Molecular Weight ◽  
Miscible Displacement ◽  
Volatile Components ◽  
Co2 Flooding ◽  
Minimum Miscibility Pressure ◽  
Oil Fraction ◽  
Gas Drive ◽  
First Contact ◽  
Solution Gas ◽  
Live Oil

Abstract This paper presents an empirically derived correlation for estimating the minimum pressure required for multicontact miscible (MCM) displacement of live oil systems by pure or impure CO2 streams. Minimum miscibility pressure (MMP) has been correlated with temperature, oil C5+ molecular weight, volatile oil fraction, intermediate oil fraction, and composition of the CO2 stream. The effects of temperature and oil C5+ molecular weight on pure CO2 MMP have been well documented. However, CO2 sources are rarely pure, and solution gas usually is present in reservoir oils. The correlation presented in this paper accounts for the additional effects on MMP caused by the presence of volatile components (methane, C1; and N2) and intermediate components (ethane, C2; propane, C3; butane, C4; hydrogen sulfide, H2S; and CO2) in the reservoir oil. This correlation also is capable of estimating MMP for a contaminated or enriched CO2 stream on the basis of the pure CO2 MMP. Introduction Miscible displacements using hydrocarbon solvents have been described in the literature by many authors.1–6 The use of a slim tube apparatus for the establishment of MMP requirements for enriched or vaporizing gas drives was presented by Deffrenne et al.5 and Yarborough and Smith.7 Rutherford8 referred to these systems as conditionally miscible processes. The initial work of Rathmell et al.9 and Ballard and Smith10 illustrated that the mechanisms of CO2 displacements are similar to those of high-pressure MCM vaporizing gas drives. Since the high solubility of CO2 in reservoir oils diminishes the pressure required for miscibility to occur, a CO2 vaporizing gas drive can operate in the same manner as a lean-gas injection process, but at significantly lower pressures. Correlations for the prediction of MMP requirements for CO2 flooding are extremely helpful in the screening of candidate reservoirs for CO2 floods. Holm and Josendal11 were the first to introduce a method for estimating the MMP required for CO2 displacing oil. Other correlations for CO2 MMP have been introduced by the Natl. Petroleum Council,12 Yellig and Metcalfe,13 and Johnson and Pollin,14 as well as a new correlation from Holm and Josendal.15,16 This paper presents an empirical approach to MMP estimation. Included in this study are the effects of solution gas (live oil systems) and the effects of impure CO2 sources. Concepts of Miscible Displacement Miscible displacement is represented most easily by a ternary diagram. A pseudoternary diagram for a hypothetical hydrocarbon system is shown in Fig. 1. This is a pseudoternary representation since the apexes do not consist of pure components, but it can be used to qualitatively describe the process of miscible displacement. Fig. 1 has been divided into three areas: Zone 1, Zone 2, and Zone 3. Zone 1 represents the area of first-contact miscibility. Any solvent falling within this region can be mixed with the reservoir oil shown, such that any and all mixtures will fall outside of the two-phase region. Zone 2 represents the region of multicontact miscibility. Solvents within this area, while not initially miscible in all proportions with the reservoir oil, eventually will achieve miscibility through the repeated contacts of the reservoir oil and equilibrium fluids. There are two types of MCM processes: vaporizing gas drive, where the solvent is enriched by components vaporized from the reservoir oil, and condensing or enriched gas drive, where the solvent contributes to the enrichment of the reservoir fluid.17 Commercially viable CO2-miscible EOR processes are usually of the MCM type, because reservoir pressure requirements for this process are significantly lower than required for first contact miscibility. Zone 3 represents the area of immiscible displacement. Displacement of the reservoir oil by an fluid falling within Zone 3 will result in multiphase flow. The mass transfer between the oil and displacing fluid is such that miscibility cannot be achieved.

scholarly journals Minimum miscibility pressure computation in eor by flare gas flooding

2018 ◽  
Vol 10 (2) ◽  
pp. 61
Author(s):  
Tjokorde Walmiki Samadhi ◽  
Utjok W.R. Siagian ◽  
Angga P Budiono
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Molar Ratio ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Minimum Miscibility Pressure ◽  
Gas Flooding ◽  
Model Oil ◽  
Gas Drive

The technical feasibility of using flare gas in the miscible gas flooding enhanced oil recovery (MGF-EOR) is evaluated by comparing the minimum miscibility pressure (MMP) obtained using flare gas to the MMP obtained in the conventional CO2 flooding. The MMP is estimated by the multiple mixing cell calculation method with the Peng-Robinson equation of state using a binary nC5H12-nC16H34 mixture at a 43%:57% molar ratio as a model oil. At a temperature of 323.15 K, the MMP in CO2 injection is estimated at 9.78 MPa. The MMP obtained when a flare gas consisting of CH4 and C2H6 at a molar ratio of 91%:9% is used as the injection gas is predicted to be 3.66 times higher than the CO2 injection case. The complete gas-oil miscibility in CO2 injection occurs via the vaporizing gas drive mechanism, while flare gas injection shifts the miscibility development mechanism to the combined vaporizing / condensing gas drive. Impact of variations in the composition of the flare gas on MMP needs to be further explored to confirm the feasibility of flare gas injection in MGF-EOR processes. Keywords: flare gas, MMP, miscible gas flooding, EORAbstrakKonsep penggunaan flare gas untuk proses enhanced oil recovery dengan injeksi gas terlarut (miscible gas flooding enhanced oil recovery atau MGF-EOR) digagaskan untuk mengurangi emisi gas rumah kaca dari fasilitas produksi migas, dengan sekaligus meningkatkan produksi minyak. Kelayakan teknis injeksi flare gas dievaluasi dengan memperbandingkan tekanan pelarutan minimum (minimum miscibility pressure atau MMP) untuk injeksi flare gas dengan MMP pada proses MGF-EOR konvensional menggunakan injeksi CO2. MMP diperkirakan melalui komputasi dengan metode sel pencampur majemuk dengan persamaan keadaan Peng-Robinson, pada campuran biner nC5H12-nC16H34 dengan nisbah molar 43%:57% sebagai model minyak. Pada temperatur 323.15 K, estimasi MMP yang diperoleh dengan injeksi CO2 adalah 9.78 MPa. Nilai MMP yang diperkirakan pada injeksi flare gas yang berupa campuran CH4-C2H6 pada nisbah molar 91%:9% sangat tinggi, yakni sebesar 3.66 kali nilai yang diperoleh pada kasus injeksi CO2. Pelarutan sempurna gas-minyak dalam injeksi CO2 terbentuk melalui mekanisme dorongan gas menguap (vaporizing gas drive), sementara pelarutan pada injeksi flare gas terbentuk melaui mekanisme kombinasi dorongan gas menguap dan mengembun (vaporizing/condensing gas drive). Pengaruh variasi komposisi flare gas terhadap MMP perlu dikaji lebih lanjut untuk menjajaki kelayakan injeksi flare gas dalam proses MGF-EOR.Kata kunci: flare gas, MMP, miscible gas flooding, EOR

CT Imaging of Wormhole Growth Under Solution-Gas Drive

1999 ◽  
Vol 2 (01) ◽  
pp. 37-45 ◽  
Author(s):  
Bernard Tremblay ◽  
George Sedgwick ◽  
Don Vu
Keyword(s):  
Pressure Gradient ◽  
Production Process ◽  
Heavy Oil ◽  
Sand Production ◽  
High Permeability ◽  
Drive Mechanism ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas ◽  
Live Oil

Summary The cold production process has increased primary heavy oil production and has been applied with commercial success in the Lloydminster area (Alberta, Canada). In this process, the production of sand is encouraged in order to form high permeability channels (wormholes) within the formation. The process depends on the formation and flow of foamy oil into the wormholes as these grow away from the wellbore and into the reservoir. The formation and growth of a wormhole was visualized using a computed tomography scanner, in an experiment in which oil flowed through a horizontal sandpack and out an orifice. The only drive mechanism was the formation and expansion of methane bubbles within the live oil. The pressure gradient at the tip of the wormhole was approximately 1 MPa/m when it started to develop at the orifice. Two conditions appear necessary for wormholes to keep growing:the pressure gradient at the tip of the wormhole must be sufficiently large to dislodge the sand grains,the pressure gradient along the wormhole must be large enough to transport the sand from the tip to the orifice. The pressure gradient at the tip of the wormhole was 2.9 MPa/m when it reached its maximum length. This suggests that, although the pressure gradient at the tip was sufficient for erosion to occur, the sand could not be carried along the wormhole causing the wormhole to stop growing. The pressure depletion experiment suggests that wormholes can easily develop in uncemented sand in the field since the maximum oil production rate during wormhole growth (18 cm3/day) was significantly lower than in the field. The minimum pressure gradient (11 kPa/m) necessary for sand transport along the wormhole is important in calculating the extent of wormhole growth in the field. Introduction Cold production is a nonthermal recovery process used in uncemented heavy oil reservoirs in which sand and oil are produced together. Production rates from wells on cold production can be up to 30 times larger than the rate predicted by Darcy flow without sand production. In order to better understand the role of sand production in the cold production process, tracer injection tests were performed by well operators.1,2 Tracer dye velocities of 7 m/min were measured between certain wells. The dye showed up 18 h later at 2 km away from the injection well.1,2 The rapid flow of the tracer suggested that it flowed through a small channel excluding the possibility of a fracture or cavity around the well. We confirmed directly the development of high conductivity channels "wormholes" in the laboratory in two previous experiments.3,4 An orifice was located at the end of a sandpack and heavy oil was injected into the sandpack at constant flow rates. The heavy oil did not contain any dissolved gas. A high permeability channel (wormhole) was observed to develop at a critical flow rate. The drive mechanism in these experiments was external since a constant flow rate was maintained using a positive displacement pump. The drive mechanism for the cold production process is solution-gas drive.5 We wanted to determine whether or not a wormhole would develop under solution-gas drive. The pressure vessel used in the two previous external drive experiments was modified to handle the live oil. This required maintaining a back pressure at the orifice end of the sandpack. This back pressure was reduced at a constant rate of 205 kPa/day during the experiment. We observed that a wormhole developed in the sandpack even though the only drive mechanism was the expansion of gas bubbles in the heavy oil. The critical pressure gradient required for the wormhole to start growing (1 MPa/m) was significantly lower than in the two previous dead oil experiments: 800 MPa/m in a first experiment3 and 32 MPa/m in a second experiment.4 This significant difference in the critical pressure gradient is attributed to a destabilization of the sand grains at the wormhole tip due to the growth of the gas bubbles in the pressure depletion experiment. The wormhole stopped growing when the pressure gradient along the wormhole was equal to 11 kPa/m. These measurements are required in order to estimate how far these wormholes can extend in the field. This experiment shows that a wormhole can develop in a sandpack by solution gas drive. Materials The Clearwater sand used in preparing the pack was obtained from collection tanks at Suncor's former cold production pilot field in Burnt Lake, Alberta, Canada. The sand was packed in 2 cm layers with a hydraulic press under 27.6 MPa. The high packing stress was necessary to obtain a porosity of 34% representing field conditions (32-34%) and to give the sand a cohesive strength comparable to field values by creating more interlocking between sand grains. The porosity of naturally deposited sand ranges from 37% for a well-sorted, well-rounded, medium to coarse sand, to more than 50% for poorly sorted, fine-grained sands with irregular shaped grains.6 Either compaction or cementation is required to reduce the porosity of naturally deposited sands to field values. Porosity reduction by compaction of sand sediments can occur by plastic flow, crushing, fracturing, or pressure solution at grain contacts.7 An average particle size distribution of the sand after packing at 27.6 MPa is shown in Fig. 1. The average size of the sand grains was 198 microns. The fines content (less than 37 microns) was 8.4% by weight. The permeability of the sand pack was 1.7 Darcy. The pore volume of the sandpack was 2336 cm3.

Generalized Minimum Miscibility Pressure Correlation (includes associated papers 15845 and 16287 )

1985 ◽  
Vol 25 (06) ◽  
pp. 927-934 ◽  
Author(s):  
O. Glaso
Keyword(s):  
Molecular Weight ◽  
Miscible Displacement ◽  
Ternary Diagram ◽  
Hydrocarbon Gases ◽  
Mole Percent ◽  
Plait Point ◽  
Minimum Miscibility Pressure ◽  
Interpretation Criteria ◽  
Miscible Flooding ◽  
Hydrocarbon Gas

Abstract This paper presents a generalized correlation for predicting the minimum miscibility pressure (MMP) required for predicting the minimum miscibility pressure (MMP) required for multicontact miscible displacement of reservoir fluids by hydrocarbon, CO2, or N2 gas. The equations are derived from graphical correlations given by Benham et al. and give MMP as a function of reservoir temperature, C7+ molecular weight of the oil, mole percent methane in the injection gas, and the molecular weight of the intermediates (C2 through C6) in the gas. CO2 and N2 are represented in the current correlation by "equivalent" methane/propane- and methane/ethane-mixture injection gases, respectively. The study shows that for hydrocarbon systems, paraffinicity has an effect on MMP. In the equations, the C7+ paraffinicity has an effect on MMP. In the equations, the C7+ molecular weight of the oil is corrected to a K factor of 11.95, thereby accounting for varying paraffinicity. An additional temperature effect on N2 MMP is related to the API gravity of the oil. The N2 correlation, however, is not tested against measured MMP data other than those used to develop the equation and should be used with care. A correlation that accounts for the additional effect on CO2 MMP caused by the presence of intermediate components in the reservoir oil is presented. Predicted MMP's from the correlations developed are compared to experimental slim-tube displacement data from the literature and from our displacement tests on North Sea gas/oil systems. These displacement tests have been performed with a packed slim tube, where the effect of viscous fingering is reduced to a minimum. Introduction Multicontact miscibility is represented most easily with a ternary diagram, where the composition of the driving or displaced fluid is altered. This is obtained by vaporization of light hydrocarbon components into a driving gas or by condensation of hydrocarbon components from a driving gas into the reservoir oil. Miscibility between reservoir oils and hydrocarbon gases is achieved either by vaporization or by condensing-gas-drive mechanism, depending on the reservoir oil and injection-gas composition. With N2 and CO2, miscibility is obtained by vaporization, but with CO2, miscibility usually is achieved at lower pressure because CO2 extracts much higher-molecular-weight hydrocarbons from the reservoir oil than N2 gas. The prediction of miscibility conditions from ternary diagrams is based on experimentally determined or calculated gas and liquid compositions of a reservoir-oil/injection-gas mixture. The experimental gas and liquid equilibrium data are not easy to obtain and are often time-consuming to determine, especially near the plait point. The method for calculating gas and liquid data with point. The method for calculating gas and liquid data with equations of state to predict miscibility relies largely on gas and liquid compositions near the plait-point region. It is generally accepted that such data may not be sufficiently accurate. Flow experiments offer the most reliable method to determine the pressure required for miscibility with CO2, N 2, and hydrocarbon gas. The slim-tube method has been most widely used to determine miscibility. Different experimental procedures and interpretation criteria, however, have ted to different definitions of miscibility and have caused considerable confusion. The limitation of the slim-tube test and the problems associated with miscible displacement in porous media have been described by several authors. Phase behavior and mechanisms of miscible flooding with CO2, N2, and hydrocarbon gas have also been described by several authors. Correlations for predicting MMP have been proposed by a number of investigators and are important tools in the selection of potential reservoirs for gas miscible flooding. Therefore, the correlations must be as accurate as possible. Several CO2 MMP correlations have been published, but none of these can be used with enough published, but none of these can be used with enough confidence for final project design. They are useful, however, for screening and preliminary work. Correlations on CO2 miscible flooding have shown temperature to be the most important parameter but they disagree regarding the effect of oil type (e.g., C7+ properties of the oil). Compared with CO2 miscible flooding, very little has been published on high-pressure hydrocarbon gas miscible flooding. A recent publication gives a correlation for predicting MMP with lean hydrocarbon gases and nitrogen. In 1960, Benham et al. presented empirical curves that can estimate miscibility conditions for reservoir oils that are displaced by rich gas within a pressure range of 1,500 to 3,000 psia [10.34 to 20.68 MPa]. They assumed a limiting tie line (at the critical composition on a ternary diagram) parallel to the C1–C7+ axis and estimated mole percent methane in the injection gas from calculated percent methane in the injection gas from calculated critical points with pressure, temperature, molecular weights of C2 through C4 in the gas, and the C5+ molecular weight of the oil as variables. From Benham et al.'s data, the proposed equations have been derived for predicting MMP. SPEJ P. 927

A Study of Heavy Oil Solution Gas Drive for Hamaca Field: Depletion Studies and Interpretations

2004 ◽  
Author(s):  
Cengiz Satik ◽  
Carlon Robertson ◽  
Bayram Kalpakci ◽  
Deepak Gupta
Keyword(s):  
Heavy Oil ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

Modelling and Upscaling Unstable Miscible Displacement Processes: Characterisation of Physical Instabilities

2021 ◽  
Author(s):  
Precious Ogbeiwi ◽  
Karl Stephen
Keyword(s):  
Relative Permeability ◽  
Transport Coefficients ◽  
Miscible Displacement ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Fine Grid ◽  
Flow Models ◽  
Reservoir Models ◽  
Flood Simulations ◽  
Physical Instabilities

Abstract The compositional simulations are required to model CO2 flooding are computationally expensive particularly for fine-gridded models that have high resolutions, and many components. Upscaling procedures can be used in the subsurface flow models to reduce the high computation requirements of the fine grid simulations and accurately model miscible CO2 flooding. However, the effects of physical instabilities are often not well represented and captured by the upscaling procedures. This paper presents an approach for upscaling of miscible displacements is presented which adequately represents physical instabilities such as viscous and heterogeneity induced fingering on coarser grids using pseudoisation techniques. The approach was applied to compositional numerical simulations of two-dimensional reservoir models with a focus on CO2 injection. Our approach is based on the pseudoisation of relative permeability and the application of transport coefficients to upscale viscous fingering and heterogeneity-induced channelling in a multi-contact miscible CO2 injection. Pseudo-relative permeability curves were computed using a pseudoisation technique and applied in combination with transport coefficients to upscale the behaviour of fine-scale miscible CO2 flood simulations to coarser scales. The accuracy of the results of the pseudoisation procedures were assessed by applying statistical analysis to compare them to the results of the fine grid simulations. It is observed from the results that the coarse models provide accurate predictions of the miscible displacement process and that the fingering regimes are adequately captured in the coarse models. The study presents a framework that can be employed to represent the dynamics of physical instabilities associated with miscible CO2 displacements in upscaled coarser grid reservoir models.

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