A Holistic Approach to Simulate the Impact of H2S on Production and Injection Surface Facilities Using an Integrated Asset Model as a Digital Twin

2021 ◽  
Author(s):  
Basit Altaf ◽  
AbdelKader Allouti ◽  
Rachit Kedia ◽  
Azer Abdullayev ◽  
Mahmoud Bedewi
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Fuel Gas ◽  
H2s Removal ◽  
Pipeline Network ◽  
Associated Gas ◽  
Field Development ◽  
Digital Twin ◽  
Initial Location ◽  
The Impact

Abstract The presence of hydrogen sulphide (H2S) in produced reservoir fluids mandates precautions in the design and operation of the surface facilities. The toxicity and corrosive nature of H2S, and the need to prevent both plugging of reservoir formations and increasing the sulphur content of the produced oil dictates the criticality of forecasting and monitoring the volumes and concentrations of H2S flowing through the whole asset. Ensuring the concentration is within acceptable operational limits is critical to safeguard the overall asset and the integrity of the surface pipeline network. The objective of this study was to utilize a history matched Digital Twin Integrated Asset Model (IAM) to predict the volumes and concentrations of H2S in a field located offshore Abu Dhabi by modeling the multi-stage separation, H2S removal, and re-injection facilities for gas injection and gas lifts. The field consists of multiple stacked carbonate reservoirs sharing the same surface facilities. The proposed modelling of H2S removal strategy involved a series of steps beginning with the sweetening of the produced associated gas for fuel gas requirements and mixing the extracted H2S volumes with the gas injection and gas lift streams. The sweetening process effectively mitigated any potential asset integrity issues arising due to corrosion of the power generation system and other surface facility assets. The stripped H2S gas, re-combined with the remaining produced gas, was used for gas-lifts and reinjected into the lower reservoirs for pressure maintenance and enhanced oil recovery (EOR). A next-generation surface-subsurface coupled simulator was utilized for the modeling of this field including the full asset surface pipeline network, the H2S removal plant, bypass lines and re-injection facilities for gas injection and gas-lifts. The Digital Twin IAM approach provided a robust method for tracking and predicting the concentration and volume of H2S in the produced gas over a period of 50 years. The simulation allowed tracking the H2S from its initial location in the reservoirs, into the production wells, then through the pipelines, all the way to the surface facilities where the sweetening of the produced is handled. Moreover, the use of the Digital Twin allowed the verification of the disposal plan of the extracted H2S, showing that mixing it with the re-injection gas stream is a feasible option. Recommendations based on the model were provided to the production and facilities team, leading to a robust long-term field development plan that ensures asset integrity.

Theoretical and Numerical Investigation of Supersonic Multiphase Gas Injection

2021 ◽  
Author(s):  
Da Zhu ◽  
Mohan Sivagnanam ◽  
Ian Gates
Keyword(s):  
Shock Wave ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Single Phase ◽  
Gas Injection ◽  
Continuous Phase ◽  
Solid Particles ◽  
Gas Flows ◽  
Theoretical Derivation ◽  
The Impact

Abstract Supersonic gas injection can help deliver gas uniformly to a reservoir, regardless of reservoir conditions. This technology has played a key role in enhanced oil recovery (EOR) and in particular, thermal enhanced oil recovery operations. Most previous studies have focused on single phase gas injection whereas in most field applications, multiphase and multicomponent situations occur. In the research documented in this paper, we report on results of evaluations of compressible multiphase supersonic gas flows in which gas is the continuous phase is seeded with dispersed liquid droplets or solid particles. Theoretical derivation and numerical simulations with and without relative motions between continuous and disperse phases are examined first. The results illustrate that the shock wave structures and flow properties associated with the multiphase gas flows are different than that of single-phase isentropic flows. The existence and importance of relaxation zones after the normal shock wave in multiphase flow is described. Numerical computational fluid dynamics (CFD) simulations are conducted to show how the multiphase multicomponent flow affects gas phase injection under different conditions. The impact of solid/liquid mass loading on flow performance is discussed. Finally, the practical application of the findings is discussed.

Minimum Miscibility Pressure of CO2/Hydrocarbon Systems Within Nanopores

2021 ◽  
Author(s):  
Gang Yang ◽  
Xiaoli Li
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Unconventional Reservoirs ◽  
Minimum Miscibility Pressure ◽  
Theoretical Approaches ◽  
Fluid Systems ◽  
Confined Fluid ◽  
Miscible Gas Injection ◽  
Fluid Characterization ◽  
The Impact

Abstract Minimum miscibility pressure (MMP), as a key parameter for the miscible gas injection enhanced oil recovery (EOR) in unconventional reservoirs, is affected by the dominance of nanoscale pores. The objective of this work is to investigate the impact of nanoscale confinement on MMP of CO2/hydrocarbon systems and to compare the accuracy of different theoretical approaches in calculating MMP of confined fluid systems. A modified PR EOS applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of multiple CO2/hydrocarbon systems at different pore sizes are obtained via the VIT simulations. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the same modified PR EOS is applied to compute the MMP for the same fluid systems. Comparison of these results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, nanoscale confinement results in the drastic suppression of MMP and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

scholarly journals Prediction of asphaltene precipitation upon injection of various gases at near-wellbore conditions: A simulation study using PC-SAFT EoS

2019 ◽  
Vol 74 ◽  
pp. 63 ◽  
Author(s):  
Saba Mahmoudvand ◽  
Behnam Shahsavani ◽  
Rafat Parsaei ◽  
Mohammad Reza Malayeri
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Gas Injection ◽  
Drop Out ◽  
Maximum Point ◽  
Asphaltene Precipitation ◽  
Wide Range ◽  
Tertiary Oil Recovery ◽  
The Impact ◽  
Oil Type

The depletion of oil reservoirs and increased global oil demand have given impetus to employ various secondary and tertiary oil recovery methods. Gas injection is widely used in both secondary and tertiary modes, though the major problem associated with this process is the precipitation and deposition of asphaltene, particularly at near-wellbore conditions. In-depth knowledge of asphaltene phase behavior is therefore essential for the prediction of asphaltene precipitation. Previous studies reported the impact of gas injection on asphaltene phase behavior, but the knowledge of precipitation of asphaltene as a function of different mole fractions of injected gas is also imperative. In this study, the thermodynamic model of PC-SAFT EoS is used to discern the phase equilibrium of asphaltene by analyzing the asphaltene drop-out curve during gas injection. Asphaltene drop-out curves of two different live oil samples are analyzed by injecting CO2, CH4, and N2 gases at different mole percentages and temperatures. The results revealed that PC-SAFT EoS can serve as a reliable tool for estimating bubble pressure and asphaltene onset pressure for a wide range of temperatures, pressures, and compositions. The simulation results for the injection of CO2, CH4, and N2 also showed that CO2 gas gives minimum asphaltene precipitation. It reduces the size of the drop-out curve or moves it toward higher pressures. CH4 and N2 expand the drop-out curve by raising the upper onset point. CH4 increases the maximum point of the drop-out curve for two types of oil studied (A and B) at two different temperatures. N2 raises the maximum point of oil type “A” by approximately 57% at 395 K, while it has no effect on the maximum point of oil type “B”. In addition, reducing the temperature resulted in either decrease or increase of asphaltene solubility, demonstrating that the impact of temperature on asphaltene precipitation is closely related to the composition of the crude.

Fluid Characterization for Miscible EOR Projects and CO2 Sequestration

2007 ◽  
Vol 10 (05) ◽  
pp. 482-488 ◽  
Author(s):  
Kristian Jessen ◽  
Erling Halfdan Stenby
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Reservoir Simulation ◽  
Co2 Sequestration ◽  
Gas Injection ◽  
Numerical Diffusion ◽  
Injection Process ◽  
Wide Range ◽  
Multicomponent Gas ◽  
The Impact

Summary Accurate performance prediction of miscible enhanced-oil-recovery (EOR) projects or CO2 sequestration in depleted oil and gas reservoirs relies in part on the ability of an equation-of-state (EOS) model to adequately represent the properties of a wide range of mixtures of the resident fluid and the injected fluid(s). The mixtures that form when gas displaces oil in a porous medium will, in many cases, differ significantly from compositions created in swelling tests and other standard pressure/volume/temperature (PVT) experiments. Multicontact experiments (e.g., slimtube displacements) are often used to condition an EOS model before application in performance evaluation of miscible displacements. However, no clear understanding exists of the impact on the resultant accuracy of the selected characterization procedure when the fluid description is subsequently included in reservoir simulation. In this paper, we present a detailed analysis of the quality of two different characterization procedures over a broad range of reservoir fluids (13 samples) for which experimental swelling-test and slimtube-displacement data are available. We explore the impact of including swelling-test and slimtube experiments in the data reduction and demonstrate that for some gas/oil systems, swelling tests do not contribute to a more accurate prediction of multicontact miscibility. Finally, we report on the impact that use of EOS models based on different characterization procedures can have on recovery predictions from dynamic 1D displacement calculations. Introduction During the past few decades, a significant effort has been invested in the studies and development of improved-oil-recovery processes. From a technical point of view, gas injection can be a very efficient method for improving the oil production, particularly in the case when miscibility develops during the displacement process. The lowest pressure at which a gas should be injected into the reservoir to obtain the multicontact miscible displacement—the minimum miscibility pressure (MMP)—has consequently attained a very important status in EOR studies. Various methods for measuring and calculating the MMP have been proposed in the literature. Many of these are based on simplifications such as the ternary representation of the compositional space. This method fails to honor the existence of a combined mechanism controlling the development of miscibility in real reservoir fluids. Zick (1986) and Stalkup (1987) described the existence of the condensing/vaporizing mechanism. They showed that the development of miscibility (MMP) in multicomponent gas-displacement processes could, independent of the mechanism controlling the development of miscibility, be predicted accurately by 1D compositional simulations. A semianalytical method for predicting the MMP was later presented by Wang and Orr (1997), who played an important role in the development and application of the analytical theory of gas-injection processes. Jessen et al. (1998) subsequently developed an efficient algorithm for performing these calculations, reducing the MMP calculation time to a few seconds even for fluid descriptions of 10 components or more. Later, Jessen et al. (2001) used this approach to generate approximate solutions to the dispersion-free, 1D-displacement problem for multicomponent gas-injection processes. Analytical and numerical methods for predicting the performance of a gas-injection process depend on an EOS to predict the phase behavior of the mixtures that form in the course of a displacement process. The role of the phase behavior in relation to numerical diffusion in compositional reservoir simulation has been pointed out previously by Stalkup (1990) and by Stalkup et al. (1990). Recently, Jessen et al. (2004) proposed a method to quantify the interplay of the phase behavior and numerical diffusion in a finite-difference simulation of a gas-injection process. By analyzing the phase behavior of the injection-gas/reservoir-fluid system, a measure of the impact, referred to as the dispersive distance, can be calculated. The dispersive distance is useful when designing and interpreting large-scale compositional reservoir simulations.

scholarly journals Influence of well management in the development of multiple reservoir sharing production facilities

2020 ◽  
Vol 75 ◽  
pp. 70
Author(s):  
João Carlos von Hohendorff Filho ◽  
Denis José Schiozer
Keyword(s):  
Oil Recovery ◽  
Development Project ◽  
Gas Production ◽  
Oil Field ◽  
The Other ◽  
Dynamic Flow ◽  
Field Development ◽  
Light Oil ◽  
Multiple Reservoir ◽  
The Impact

Well prioritization rules on integrated production models are required for the interaction between reservoirs and restricted production systems, thus predicting the behavior of multiple reservoir sharing facilities. This study verified the impact of well management with an economic evaluation based on the distinct prioritizations by reservoir with different fluids. We described the impact of the well management method in a field development project using a consolidated methodology for production strategy optimization. We used a benchmark case based on two offshore fields, a light oil carbonate and a black-oil sandstone, with gas production constraint in the platform. The independent reservoir models were tested on three different approaches for platform production sharing: (Approach 1) fixed apportionment of platform production and injection, (Approach 2) dynamic flow-based apportionment, and (Approach 3) dynamic flow-based apportionment, including economic differences using weights for each reservoir. Approach 1 provided the intermediate NPV compared with the other approaches. On the other hand, it provided the lowest oil recovery. We observed that the exclusion of several wells in the light oil field led to a good valuation of the project, despite these wells producing a fluid with higher value. Approach 2 provided the lower NPV performance and intermediate oil recovery. We found that the well prioritization based on flow failed to capture the effects related to the different valuation of the fluids produced by the two reservoirs. Approach 3, which handled the type of fluids similarly to Approach 1, provided a greater NPV and oil recovery than the other approaches. The weight for each reservoir applied to well prioritization better captured the gains related to different valuation of the fluids produced by the two reservoirs. Dynamic prioritization with weights performed better results than fixed apportionment to shared platform capacities. We obtained different improvements in the project development optimization due to the anticipation of financial returns and CAPEX changes, due mainly from adequate well apportionment by different management algorithm. Well management algorithms implemented in traditional simulators are not developed to prioritize different reservoir wells separately, especially if there are different economic conditions exemplified here by a different valuation of produced fluids. This valuation should be taken into account in the short term optimization for wells.

An Experimental Study Investigating the Impact of Miscible and Immiscible Nitrogen Injection on Asphaltene Instability in Nano Shale Pore Structure

2021 ◽  
Author(s):  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Pore Size ◽  
Oil Recovery ◽  
Gas Injection ◽  
Production Costs ◽  
Microscopy Imaging ◽  
Heterogeneous Distribution ◽  
Weight Percentage ◽  
Pore Sizes ◽  
Asphaltene Deposition ◽  
The Impact

Abstract Miscible gas injection has become the most used enhanced oil recovery (EOR) method in the oil and gas industry. The deposition and precipitation of aspahltene during the gas injection process is one of the problems during the oil production process. The asphaltene can deposit and plug the pores, which reduces the permeability in a reservoir; thus, decreasing the oil recovery and increasing the production costs. This research investigates the nitrogen (N2) miscible and immiscible pressure injections on asphaltene instability in shale pore structures . First, a slim-tube was used to determine the minimum miscibility pressure (MMP) of N2to ensure that the effect of both miscible and immiscible gas injection was achievable. Second, filtration experiments were conducted using a specially designed filtration apparatus to investigate the effect of nano pore sizes on asphaltene deposition. Heterogeneous distribution of the filter paper membranes was used in all experiments. The factors studied include miscible/immiscible N2injection and pore size distribution. Visualization tests were conducted to highlight the asphaltene precipitation process over time. The results showed that increasing the pressure increased the asphaltene weight percentage. The miscible N2injection pressure had a significant effect on asphaltene instability. However, the immiscible N2injection pressure had a lower effect on the asphaltene deposition, which resulted in less asphaltene weight percentage. For both miscible/immiscible N2injection pressures, the asphaltene weight percentage increased as the pore size of the filter membranes decreased. Visualization tests showed that after one hour the asphaltene clusters were clearly noticed and suspended in the solvent of heptane, and the asphaltene was fully deposited after 12 hours. Microscopy imaging of filter membranes indicated significant pore plugging from asphaltene, especially for smaller pore sizes.

Analysis of Nitrogen Minimum Miscibility Pressure MMP and Its Impact on Instability of Asphaltene Aggregates - An Experimental Study

2021 ◽  
Author(s):  
Mukhtar Elturki ◽  
Abdulmohsin Imqam
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Size Structure ◽  
Gas Injection ◽  
Injection Pressure ◽  
Oil Composition ◽  
Oil Viscosity ◽  
Weight Percentage ◽  
Minimum Miscibility Pressure ◽  
The Impact

Abstract Minimum miscibility pressure (MMP) is a critical parameter when undergoing miscible gas injection operations for enhanced oil recovery (EOR). Miscibility has become a major term in designing the gas injection process. When the miscible gas contacts the reservoir oil, it causes changes in the basic oil properties, affecting reservoir oil composition and equilibrium conditions. Changes in conditions may also favor flocculation and deposition of organic solids, mainly asphaltene, which were previously in thermodynamic equilibrium. The main purpose of this study is to investigate how the most important parameters, such as oil temperature and oil viscosity, could affect the nitrogen (N2) MMP and the instability of asphaltene aggregation. Three sets of experiments were conducted: first, the determination of MMP was performed using a slim-tube packed with sand. The impact of crude oil viscosity using 32, 19, and 5.7 cp; and temperature using 32, 45, and 70 °C, were investigated. The results showed that the N2 MMP decreased when crude oil temperature increased. The temperature is inversely proportional to the N2 MMP due to the N2 remaining in a gaseous phase at the same conditions. In terms of viscosity, the MMP for N2 was found to decrease with the reduction in oil viscosity. Second, the effect of miscibility N2 injection pressure on asphaltene aggregation using 750 psi (below miscible pressure) and 1500 psi (at miscible pressure) was investigated using a specially designed filtration vessel. Various filter membrane pores sizes were placed inside the vessel to highlight the effect of asphaltene molecules on plugging the unconventional pore structure. The results demonstrated that increasing the pressure increased asphaltene weight percentage. The asphaltene weight percent was higher when using miscible injection pressure compared to immiscible injection pressure. Also, the asphaltene weight percentage increased when the pore size structure decreased. Finally, the visualization of asphaltene deposition over time was conducted, and the results showed that asphaltene particles started to precipitate after 2 hours. After 12 hours, the colloidal asphaltenes were fully precipitated.

The Effects of Interfacial Tension Dependent Relative Permeability on Sweep Efficiency and Oil Recovery Under Different Gas Injection Composition

2021 ◽  
Author(s):  
Mohd Ghazali Abd Karim ◽  
Wahyu Hidayat ◽  
Alzahrani Abdulelah
Keyword(s):  
Interfacial Tension ◽  
Simulation Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Sweep Efficiency ◽  
Reservoir Properties ◽  
Relative Permeability Curve ◽  
Compositional Model ◽  
The Impact

Abstract The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.

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