Miscible Gas Injection Research Articles

Multiphase transient analysis for monitoring of CO2 flooding

The potential of well test technology is discussed in this paper to estimate the miscible condition and displacement fronts position during CO2 flooding. To interpret the multiphase well test curve of CO2 flooding process, an accurate compositional numerical model is developed in this study. The model includes fully EoS-based compositional nonlinear formulation, unstructured gridding and multi-segmented well. A systematic well test analysis of CO2 flooding at different regimes, including immiscible, multi-contact miscible and first-contact miscible gas injection, was performed for hydrocarbon systems with different number of components. Based on the interpretation root cause analysis, proposed in this work, the specific characteristics of the well test curve of CO2 flooding have been identified and described. These characteristics provide the guidance for the distinction among the different regime of CO2 displacement. It was demonstrated that the most important characteristics stay invariant from the number of components involved into numerical study. Finally, a tangent line method has been proposed to detect the key point on the pressure derivative curve corresponding to a CO2 front. This method allows to predict the displacement front position for problems of practical interest.

Assessment of miscible light-hydrocarbon-injection recovery efficiency in Bakken shale formation using wireline-log-derived indices

High original oil-in-place estimates accompanied by low primary recovery potential of organic-rich shale formations make them suitable candidates for enhanced oil recovery (EOR) projects. The organic-rich shale formation under investigation in this paper is the Bakken shale formation that exhibits significant variations in lithology, rock texture, clay content, porosity, and total organic carbon (TOC). Three wireline-log-derived EOR-efficiency indices are generated across the 200-feet-thick Upper, Middle, and Lower Bakken formations to identify flow units suitable for EOR using light, miscible hydrocarbon injection.R-index is one of the three EOR-efficiency indices. R-index is calculated using kerogen content, water saturation, permeability, principal pore throat diameter, and porosity. Microscopic Displacement (MD) Index computes the microscopic displacement efficiency for the miscible gas injection. An important step in computing MD-index is to decompose NMR T2 distribution at each depth using factor analysis to compute the free oil, movable water, and bound fluid volumes. Moreover, the MD-index accounts for the effect of pore confinement on miscible oil volume and the effect kerogen content on the displacement efficiency. MD-index relies on a novel method to calculate the miscible free-oil volume from subsurface NMR T2-distribution logs. Lastly, k-means clustering method was used to generate the third index, referred as the KC-index, which is in the form of a step-wise curve. KC-index partitions the entire formation into four groups, representing miscible-gas-injection recovery potentials at discrete levels. The method uses water saturation, porosity, permeability, bound fluid volume, and principal pore throat diameter derived from various logs.The proposed log-derived EOR-efficiency indices generate consistent predictions of miscible light-hydrocarbon injection performance in the Bakken shale formation at various resolutions. Indices indicate that several formation zones in the middle section of the formation will have much higher recovery potential in comparison to the upper and lower sections of the formation. At a resolution of 1-foot depth interval, several flow units were successfully identified in the middle section that exhibit high miscible-gas-injection recovery potential.

Sensitivity analysis and economic optimization studies of inverted five-spot gas cycling in gas condensate reservoir

Abstract Gas condensate reservoirs usually exhibit complex flow behaviors because of propagation response of pressure drop from the wellbore into the reservoir. When reservoir pressure drops below the dew point in two phase flow of gas and condensate, the accumulation of large condensate amount occurs in the gas condensate reservoirs. Usually, the saturation of condensate accumulation in volumetric gas condensate reservoirs is lower than the critical condensate saturation that causes trapping of large amount of condensate in reservoir pores. Trapped condensate often is lost due to condensate accumulation-condensate blockage courtesy of high molecular weight, heavy condensate residue. Recovering lost condensate most economically and optimally has always been a challenging goal. Thus, gas cycling is applied to alleviate such a drastic loss in resources. In gas injection, the flooding pattern, injection timing and injection duration are key parameters to study an efficient EOR scenario in order to recover lost condensate. This work contains sensitivity analysis on different parameters to generate an accurate investigation about the effects on performance of different injection scenarios in homogeneous gas condensate system. In this paper, starting time of gas cycling and injection period are the parameters used to influence condensate recovery of a five-spot well pattern which has an injection pressure constraint of 3000 psi and production wells are constraint at 500 psi min. BHP. Starting injection times of 1 month, 4 months and 9 months after natural depletion areapplied in the first study. The second study is conducted by varying injection duration. Three durations are selected: 100 days, 400 days and 900 days. In miscible gas injection, miscibility and vaporization of condensate by injected gas is more efficient mechanism for condensate recovery. From this study, it is proven that the application of gas cycling on five-spot well pattern greatly enhances condensate recovery preventing financial, economic and resource loss that previously occurred.

Life Cycle Analysis of Carbon Dioxide Emission Utilization in Enhanced Oil Recovery (EOR) Activity

The focus of this research is to analyze potential environmental impact in the utilization of carbon dioxide (CO2) as miscible gas injection on Enhanced Oil Recovery (EOR) activity. The reinjection of CO2 would reduce the amount of CO2 release in the air and is considered relatively as a new innovative approach. Responsible innovation (RI) is a research framework that considers aspects of sustainability both in terms of social, economic, and environmental toward an innovation made with five dimensions; reflexivity, deliberation, anticipation, responsiveness, and participation. However, RI does not have a specific quantitative approach to support the analysis. Therefore, this research proposes the use of simplified Life Cycle Assessment (LCA) as the quantitative analysis tool to support the RI analysis, using the case study of Subang Gas-Well, West Java, Indonesia. The case study has four main process units of CO2-Enhanced Oil Recovery, from the Well in Subang, CO2 Recovery, CO2 Transmission and the EOR Oil Well in Jatibarang. Based on the calculation, among the various impact categories, the biggest potential environmental impact is the contribution to acidification impact, followed by photo-oxidant formation, climate change and depletion of abiotic resources.

Determination of asphaltene precipitation using a CPA equation of state

ABSTRACTAsphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. Therefore, predicting asphaltene phase behavior through thermodynamic modeling may help to control its precipitation and reduce the associated problems. In this work, a new modified CPA equation of state (EoS) was used to model asphaltene precipitation. This equation is based on a combination of a new physical part and the Wertheim association term.The results of the new model were compared with the experimental data of five oil samples. The results showed that this modified CPA EoS can predict asphaltene precipitation with good accuracy.

Experimental Study of Miscible Thickened Natural Gas Injection for Enhanced Oil Recovery

Hydrocarbon-miscible gas flooding typically involves injection of an associated gas (AG) mixture containing mainly methane (CH4) enriched with light hydrocarbon fractions and possibly acid gases. The AG mixture has been recognized as an excellent candidate for miscible gas injection (MGI). However, in general, the viscosity of the AG at reservoir conditions is significantly lower than that of crude oil leading to an unfavorable mobility ratio and low volumetric sweep efficiency during flooding. This study assesses the suitability of a library of commercially available polymers to thicken AG as a means of mobility control. The focus of the study is on the Field A located in the Harweel cluster in southern Oman. First, soluble polymeric thickeners for an AG mixture (CH4 60%, C2H6 9%, C3H8 6%, and CO2 25%) were identified using a parallel gravimetric extraction technique combined with cloud point measurements. Then, the viscosity of the identified soluble polymeric candidates in AG mixture was measured in a capillary viscometer at reservoir conditions. Three polymers were found to be completely or partially soluble in the AG mixture at 377 K and 55 MPa including poly(1-decene) (P-1-D), poly(methyl hydro siloxane) (PMHS), and poly(dimethylsiloxane) (PDMS). P-1-D found to be an effective thickener in AG mixture under conditions relevant to Field A, i.e., high temperatures and pressures. The polymer is soluble in the concentration range of 1.5–9 wt%. The viscosity of the P-1-D- thickened AG mixture increased by 2.2–7.4 times greater than AG mixture viscosity at 358–377 K. Furthermore, reservoir condition core flooding experiments were performed to examine the effectiveness of P-1-D-thickened AG gas mixture flooding to enhance oil recovery. The thickened-AG mixture flooding resulted in delayed gas breakthrough and subsequently 10–12% additional oil recovery.

Application of population balance equation in modeling of asphaltene particle size distribution and characterization of aggregation mechanisms under miscible gas Injection

Abstract Particle size distribution (PSD) is an important factor that determines how asphaltene instability can damage porous media during natural depletion and enhanced oil recovery processes. In this work, aggregate size distribution under natural depletion and miscible nitrogen injection processes are determined via image analysis techniques and the results are modelled by population balance equation. Unimodal distribution curves in natural depletion show the dominance of particle-particle aggregation mechanism and the clustering is detected only around crude oil bubble point pressure. It is also observed that miscible nitrogen injection considerably increases the number and size of asphaltene flocs and directs the agglomeration process towards cluster-cluster aggregation (i.e. bimodal distribution curves) which can severely damage porous media. Results of population balance modeling characterize dominant aggregation mechanisms providing one optimum collision factor for unimodal curves and two optimum collision factors for bimodal distributions which confirms the alteration of aggregation mechanism due to miscible gas injection.

Determination of asphaltene precipitation using a new CPA-based equation of state

ABSTRACTAsphaltene precipitation during natural depletion and miscible gas injection is a common problem in oilfields throughout the world. Therefore, predicting asphaltene phase behavior through thermodynamic modeling may help to control its precipitation and reduce the associated problems. In this work, a new modified cubic-plus-association (CPA) equation of state (EoS) was used to model asphaltene precipitation. This equation is based on a combination of a new physical part and an association term.The new physical part has an evolved cubic equation of state with a new attractive term in this work. The results of the new modification of CPA EoS were compared with the experimental data of two oil samples (oil samples 1 and 2) that belonged to Moradi et al. The results showed that this modified CPA EoS can predict asphaltene precipitation with good accuracy.

Compositional modeling of fracture-to-fracture miscible gas injection in an oil-rich shale

The ultra-low permeability of shale makes injection from a well to other wells difficult. A novel scheme was proposed in a recent patent (Dombrowski et al., 2015) where gas is injected into a hydraulic fracture along a horizontal well and production occurs from an adjacent fracture, intersecting the same well. Compositional reservoir modeling was performed to investigate the effectiveness of the proposed gas injection scheme. The computational domain consists of two hydrofrac half-stages along a horizontal well. The results show 15.7% and 12.5% OOIP incremental recovery over 5000 days of CO2 injection for the base models with the matrix permeability of 10μD and 1μD, respectively, demonstrating that the gas injection scheme has the potential to vastly improve oil recovery in oil-rich shale formations. The effects of reservoir properties and injection conditions on oil recovery were investigated by changing the injection pressure, reservoir heterogeneity, distribution of natural fractures, hydrofrac spacing, size of pore space, and compositions of the injection gas. Most of them affect the oil recovery significantly. Recovery by miscible hydrocarbon gas injection is comparable to CO2; so it should be considered as an alternative.

Adaptive implicit finite element methods for multicomponent compressible flow in heterogeneous and fractured porous media

AbstractThis work presents adaptive implicit first‐order and second‐order discontinuous Galerkin (DG) methods for the transport of multicomponent compressible fluids in heterogeneous and fractured porous media, discretized by triangular, quadrilateral, and hexahedral grids. The adaptive implicit method (AIM) combines the advantages of purely explicit or implicit methods (in time). In grid cells with high fluxes or low pore volumes, the transport update is done implicitly to alleviate the Courant‐Friedrichs‐Lewy (CFL) time step constraints of the conditionally stable explicit approach. Grid cells with a large CFL condition are updated explicitly. Combined, this allows higher efficiency than explicit methods, but it reduces the “penalty” of implicit methods, which exhibit high numerical dispersion and are more computationally and storage expensive per time step. The advantages of AIM are modest for uniform grids and rock properties. However, in heterogeneous or fractured reservoirs explicit methods may become impractical, while a fully implicit approach introduces unnecessary numerical dispersion and is overkill for low‐permeability layers and matrix blocks. In such applications, AIM is shown to be significantly more efficient and accurate. The division between explicit and implicit grid cells is made adaptively in space and time. This allows for a high level of explicitness and can also adapt to high fluxes caused by, e.g., viscous and gravitational flow instabilities. Numerical examples demonstrate the powerful features of AIM to model, e.g., solute transport, carbon sequestration in saline aquifers, and miscible gas injection in fractured oil and gas reservoirs.

Performance of multiple thermal fluids assisted gravity drainage process in post SAGD reservoirs

Multiple thermal fluids injection process is a new heat-carrier process proposed in recent years as an EOR process for heavy oil reservoirs. Compared with the conventional saturated-steam injection process, it combines the multiple advantages of immiscible and/or miscible gas injection and thermal recovery processes. In this paper, based on the ideas of the multiple thermal fluids injection process and the conventional steam assisted gravity drainage (SAGD) process, a new recovery process, multiple thermal fluids assisted gravity drainage (MFAGD) process is proposed to enhance heavy oil recovery for post SAGD reservoirs. Two 3D gravity drainage experiments (SAGD and SAGD-MFAGD) are first conducted to explore EOR mechanisms of the multiple thermal fluids in heavy oil reservoirs. Subsequently, numerical simulations are performed to match the experimental measurements. Then the EOR mechanisms and the remaining oil saturation distribution are analyzed. Furthermore, the differences between the SAGD, steam-and-gas-push (SAGP) and MFAGD processes are discussed. From a dimensionless scaling analysis for gravity drainage process, lab scale parameters are converted to field scale ones, and a field scale simulation model is developed. Through the analysis and simulation, the reservoir adaptability of the MFAGD process is investigated, and its operation parameters are numerically optimized. Experimental results indicate that a strategic combination of the SAGD and MFAGD processes can tremendously improve the development of heavy oil reservoirs. The MFAGD process can be adopted as a follow-up recovery technique after the SAGD process for heavy oil reservoirs. As its EOR mechanisms, in addition to the conventional thermal recovery mechanisms of steam injection, the results show that heat insulation, energy recovery, gas dissolution, foamy oil and auxiliary well cleanup are all its important mechanisms. In comparison with SAGD, this new process has a higher recovery rate, a lower steam injecting volume and a lower cumulative steam-oil ratio (cSOR). Numerical results also show that the steam chamber from MFAGD is shaped like a liquid drop instead of a conventional inverted triangle from SAGD. The net-to-gross value and formation thickness have a great influence on the performance of MFAGD. It is found that for MFAGD, the optimal steam-gas ratio in the standard conditions is 1:1, the steam injection rate is 200m3/d, and the operation pressure is 3.0MPa for the study reservoir. The MFAGD process will be a potentially important EOR method for post SAGD heavy oil and oil sands reservoirs.

Uniqueness, repeatability analysis and comparative evaluation of experimentally determined MMPs

Miscible gas injection processes like CO2 flooding are recommended to be carried out at minimum miscibility pressure (MMP) for effective enhanced recovery of trapped oil. There are several methods for MMP determination, but slim tube and vanishing interfacial tension (VIT) are deployed experimental techniques in this study. Uniqueness and repeatability of slim tube determined MMP was tested by conducting 55 slim tube runs for three different Omani crude oil samples (L-721, MZE and N) using three different coil lengths of constant diameter and three different injection rates. VIT technique accuracy and reliability was evaluated by comparing VIT determined MMPs, for same three considered crude oil samples, with aforementioned different slim tube systems determined MMPs. A trend of decrease in MMP with increase in coil length was found. No unique trend was found between MMP and injection rate. Lowest MMP and highest recovery were observed with highest coil length and lowest injection rate. It may be attributed to more stable displacement process which results in earlier developed miscibility and almost complete displacement of remaining more coil length retained oil. Therefore, both slim tube design and procedure need to be standardized. PVT software predicted MMP close to lower coil length slim tube system determined MMP for sample L-721 and higher coil length measured MMP for sample MZE. VIT approach determined MMPs were found to lie in between the MMPs measured by slim tube system with medium and longer coil lengths for same three oil samples. Since VIT estimated MMPs are in close match with more liable slim tube design determined MMPs, this technique can be utilized as a reliable and cheap alternative compared to more expensive and time consuming slim tube technique for accurate MMP determination without any potential of significant error.

Integrating support vector regression with genetic algorithm for CO2-oil minimum miscibility pressure (MMP) in pure and impure CO2 streams

Accurate knowledge of the minimum miscibility pressure (MMP) is essential in successful design of any miscible gas injection process, particularly in CO2 flooding. It is however well-acknowledged that experimental measurements are expensive, time-consuming, and cumbersome. As a direct consequence, a support vector regression model combined with genetic algorithm (GA-SVR) was proposed to predict pure and impure CO2-crude oil MMP. The accuracy and reliability of the proposed model were evaluated through 150 data sets collected in the open literature and compared with approaches commonly used to estimate the MMP (Lee correlation, Shokir correlation, Orr-Jensen correlation, Yellig-Metcalfe correlation, Alston correlation, Emera-Sarma correlation, Cronquist correlation, Kamari et al. correlation, and Fathinasab-Ayatollahi correlation). The results showed that the proposed model for predicting the MMP is in excellent agreement with experimental data and outperforms all the existing methods considered in this work in prediction of pure and impure CO2-oil MMP. Furthermore, outlier diagnosis was performed on the whole data sets to identify the applicable range of all models investigated in this work by detecting the probable doubtful MMP data.

Miscible and Immiscible Gas-Injection Pilots in a Middle East Offshore Environment

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18513, “A Case Study on Miscible and Immiscible Gas-Injection Pilots in a Middle East Carbonate Reservoir in an Offshore Environment,” by Jitendra Kumar, Pawan Agrawal, and Elyes Draoui, Abu Dhabi Marine Operating Company, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Hydrocarbon-gas injection improves microscopic-displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can affect the ultimate recovery negatively because of viscous fingering and gravity override. This paper describes a gas-injection pilot that has been implemented in offshore Middle East carbonate reservoirs (a second pilot is described in the complete paper) to assess injectivity, productivity, macroscopic-sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. Introduction The carbonate field is part of the Lower Cretaceous Lower Lekhwair formation. The field is divided into A, B, and C reservoirs, 20 to 35 ft thick individually. Each reservoir is vertically separated by nonpay tight intervals of similar thickness, composed of argillaceous limestone, isolating each reservoir from the others. Depending on the reservoir, oolitic shoal facies can be more abundant. Near the flank area, the formation is water-wet, and, as one moves toward the crestal area, the formation becomes oil-wet. The reservoir fluid is undersaturated at initial pressure of 4,200 psig at datum depth and a temperature of 220°F. Oil gravity is 40 °API, and oil contains 1–2 mol% carbon dioxide and an insignificant amount of hydrogen sulfide. All three reservoirs have common contact and similar oil properties, with a strong compositional gradient. Production from the field started in the late 1960s through natural depletion, which indicated weak aquifer support. Before pilot implementation, laboratory experiments were performed to determine the feasibility of hydrocarbon-gas injection. Pressure/volume/temperature experiments showed that the minimum miscibility pressure (MMP) is approximately 4,500 psia, which is higher than initial reservoir pressure, but the crude oil has a strong swelling effect. Unsteady-state coreflood experiments performed with a 200-cm-long core showed a recovery of 70% for immiscible flood and a recovery of 92% for miscible flood. Full-field compositional simulation of gas injection incorporating a tuned equation of state indicated significant incremental oil and reasonable pressure support.

Prediction of asphaltene deposition parameters in porous media using experimental data during miscible gas injection

ABSTRACTThe study of asphaltene deposition under actual field conditions is impossible. Therefore, many models have been derived based on experimental data. All models have some matching parameters, which are estimated along with numerical solving or simulation to match experimental and simulation data, so it is possible that these were estimated as required (tuning factor).In this study, two miscible CO2 injection dynamic tests in porous media were performed. In these tests, CO2 and live oil were injected into the core simultaneously. The CO2 concentration was more than the onset concentration for asphaltene precipitation.The main objective of this work was to determine the deposition coefficients from the experimental data, so these were predicted by using basic equations using the material balance. Also, by mathematical methods, the relation between these parameters was determined.Results from this work imply that the deposition parameters can be estimated from the experimental data and these parameters are not constant during modeling and simulation.

Experimental and analytical methods to determine minimum miscibility pressure (MMP) for Bakken formation crude oil

The Bakken is one of the shale reservoirs that has been discovered to hold a vast amount of resource and is contributing to the production boom in the US. This unconventional reservoir, like most others, displays favorable initial production rates due to stimulation by hydraulic fracturing, but production rates quickly decline after few months. Due to the extremely low permeability and low recoveries, miscible gas injection is considered for improving the recovery of oil in the Bakken formation. Feasibility of miscible gas injection in the Bakken would depend on the analysis of minimum miscibility pressure (MMP) experiments.The Rising Bubble Apparatus (RBA) has been chosen for the purpose of these experiments. The RBA provides results in a short amount of time using small amounts of fluid samples. The RBA consists of a cell gage containing a flat glass tube where oil samples are placed and an injection needle where gas is injected into the flat glass tube. To simulate reservoir conditions, the glass tube is pressurized using de-ionized water, and heating plates surrounding the cell are used to regulate temperature. Visual observation of the injected gas bubble behavior is captured by a camera as it rises and moves upward along the oil column. By observing the shape and dissolution behavior of the bubble, the MMP can be determined.MMP results from a Bakken crude sample are shown to range from 2100 to 3500psi at temperatures from 160 to 240°F using CO2 as the injection fluid. Other injection fluids such as nitrogen and hydrocarbon gases have been tested and also provided reasonable MMP values. MMP results from Bakken crude oil samples were compared to existing correlations, and the correlations were found to produce mostly unreliable MMP results for the Bakken oils evaluated in the study. On the other hand, an equation of state phase behavior program showed similarities with the RBA MMP results.The impact of different injection fluids, inclusive of CO2 and enriched hydrocarbon gases is the subject of this study. MMP results are influenced by the choice of injection fluids, providing valuable information for economic production and increased recovery in the Bakken formation. The results from this study provide a range of MMP data that can be used in planning pilot tests for miscible gas injection in the Bakken.

Experimental study of gas–oil relative permeability curves at immiscible/near miscible gas injection in highly naturally fractured reservoir

The main aim of this work is to investigate gas–oil relative permeability curves as the main flow function in different gas injection scenarios, immiscible and near miscible in case of highly fractured reservoirs.In this research, some experiments have been done on the reservoir core sample selected from sandstone formation in one of the Iranian naturally fractured oil reservoirs. The core is saturated with oil sample and CO2 is injected into oil saturated core sample. Experiments have been performed on both of the sandstone and artificial fractured sandstone, represented as no fractured and highly fractured reservoirs, based on incremental pressure algorithm approaching into near miscible condition. Inverse modeling method has been used to calculate relative permeability curves.By comparing the relative permeability curves in immiscible and near-miscible conditions, the results show that in sandstone core type this change is considerable, but in highly artificial fractured sandstone with a high ratio of artificial fractured to sandstone absolute permeability (Kef /Ks) is not substantial. Moreover the results show that in the described case of artificial fractured core type so simple conventional relative permeability methods have the same results compared to a sophisticated inverse modeling method. The other main result is the lack of miscibility activation in near miscible injection through the highly fractured reservoirs leading to viscose dominant flow rather than capillary.Finally by considering this changing behavior, a better knowledge of gas front movement through highly fractured reservoirs in low IFT regions can be obtained.

On the determination of CO2–crude oil minimum miscibility pressure using genetic programming combined with constrained multivariable search methods

In addition to reducing carbon dioxide (CO2) emission, the high oil recovery efficiency achieved by CO2 injection processes makes CO2 injection a desirable enhance oil recovery (EOR) technique. Minimum miscibility pressure (MMP) is an important parameter in successful designation of any miscible gas injection process such as CO2 flooding; therefore, its accurate determination is of great importance. The current experimental techniques for determining MMP are expensive and time-consuming. In this study, multi-gene genetic programming has been combined with constrained multivariable search methods, and a simple empirical model has been developed which provides a reliable estimation of MMP in a wide range of reservoirs, injection gases and crude oil systems. The experimental data for developing the proposed correlation consists of 270 data points from twenty-six authenticated literature sources. This model utilizes reservoir temperature, molecular weight of C5+, volatile (N2 and C1) to intermediate (H2S, CO2, C2, C3, C4) ratio and pseudo critical temperature of the injection gas as input parameters. Both statistical and graphical error analyses have been employed to evaluate the accuracy and validity of the proposed model compared to the pre-existing correlations. The results showed that the new model provides an average absolute relative error of 11.76%. Moreover, the relevancy factor indicated that the reservoir temperature has the greatest impact on the minimum miscibility pressure.

A New Simple CO2 Minimum Miscibility Pressure Correlation

The minimum miscibility pressure (MMP) is one of the most important parameter to be determined in miscible gas injection projects to ensure and maximize the displacement sweep efficiency inside the reservoir. Usually the most effective way of determining the MMP is to run slim tube experiments. However, in the early screening stage, we often relay on the published empirical correlations to estimate the MMP and identify the candidate fields for EOR gas injection projects. The main objective of this paper was to examine different published empirical CO2 MMP correlations using measured data mainly obtained from Libya and other published resources, and also to develop a new simple reliable correlation to be applied in the oil industry. The data collected covered a wide range of CO2 MMP (1544-6244 psia) and oil API gravity (28-50ºAPI). Minitab regression tool was extensively used in our study and a wide range of new constructed correlations ranging from simple to complex ones were developed and statistically evaluated. The proposed simple CO2 MMP correlation is mainly function of the measured Pb, API, T and Rsi and has very reliable degree of accuracy (SD=6.7%, ARE=0.44%, AARE=5.74%, R2=95.22%) for the examined data and has shown better performance when compared with the industry popular correlations. The new correlation was validated against 100 measured PVT variables (Pb, Rsi, T and API) obtained from Libya, and the predicted CO2 MMP results have demonstrated very reliable trend (within the measured CO2 MMP trend) with no anomalies.

Numerical modeling of combined low salinity water and carbon dioxide in carbonate cores

This paper investigates the combined effect of injecting low salinity water (LSWI) and carbon dioxide (CO2) on oil recovery from carbonate cores. The combined effect of LSWI and CO2 injection on oil recovery was predicted by performing several 1D simulations using measured reservoir rock and fluid data. These simulations included the effect of salinity on both miscible and immiscible continuous gas injection (CGI), simultaneous water-alternating-gas (SWAG), constant water-alternating-gas (WAG), and tapered (WAG). For SWAG and constant and tapered WAG, both seawater and its dilutions were simulated. CO2 was injected above its minimum miscibility pressure. Baker's three-phase relative permeability model was modified to account for the effect of salinity on the water/oil relative permeability. The results show that SWAG, whether using seawater or its dilutions, outperformed all other tertiary injection modes in terms of oil recovery. Moreover, the SWAG process has both the highest tertiary recovery factor (TRF) and the lowest utilization factor (UF). This study highlights the advantage of using low salinity water along with miscible CO2. The miscible CO2 displaces the residual oil saturation whereas the low salinity water boosts the production rate by increasing the oil relative permeability through wettability alteration towards more a water-wet state. The latter finding was supported by comparing our simulations with the two corefloods reported by Chandrasekhar and Mohanty (2014). These corefloods were conducted in SWAG tertiary mode using seawater and its dilutions. Fractional flow analysis shows that SWAG with low salinity water requires less injected solvent compared to SWAG with seawater and miscible CGI.