Predicting Reservoir Fluid Phase and Volumetric Behavior From Samples Contaminated With Oil-Based Mud

2002 ◽  
Vol 5 (03) ◽  
pp. 197-205 ◽  
Author(s):  
F. Gozalpour ◽  
A. Danesh ◽  
D.-H. Tehrani ◽  
A.C. Todd ◽  
B. Tohidi
Keyword(s):  
Phase Equilibrium ◽  
Phase Behavior ◽  
Volatile Oil ◽  
Fluid Composition ◽  
Fluid Analysis ◽  
Reservoir Fluid ◽  
Different Types ◽  
The Impact ◽  
Mud Filtrate ◽  
Equilibrium Calculations

Summary The impact of sample contamination with oil-based mud filtrate on phase behavior and properties of different types of reservoir fluids, including gas condensate and volatile oil, has been investigated. Two simple methods are used to determine the uncontaminated fluid composition from contaminated samples. The capability of the methods is demonstrated against highly contaminated samples. An equation-of-state (EOS)-based method also has been developed to predict the phase and volumetric properties of the retrieved composition. The method determines the required parameters of the EOS for the uncontaminated fluid using the developed phase-behavior models from contaminated-sample data. The method has been examined against experimental data of different types of reservoir fluids with successful results. Introduction Accurate reservoir fluid composition and properties are essential for reservoir management and development. Reliable reservoir fluid samples are therefore required; however, major challenges can render the fluid analysis limited in value. The reservoir fluid samples for pressure/volume/temperature (PVT) tests can be collected by bottomhole and/or surface sampling techniques as appropriate. During the drilling process, owing to overbalance pressure in the mud column, mud filtrate invades the formation. If an oil-based mud is used in the drilling, it can cause major difficulties in collecting high-quality formation fluid samples. Because the filtrate of oil-based drilling mud is miscible with the formation fluid, it could significantly alter the composition and phase behavior of the reservoir fluid. Even the presence of a small amount of oil-based filtrate in the collected sample could significantly affect the PVT properties of the formation fluid. Oil-based mud is used widely in the petroleum industry. Contamination with oil-based mud filtrate could affect reservoir fluid properties such as saturation pressure, formation volume factor, gas/liquid ratio, and stock-tank liquid density. Because collecting a reservoir fluid sample is expensive, and accurate reservoir fluid properties are needed in reservoir development, it is highly desirable to determine accurate composition and phase behavior for the reservoir fluid from contaminated samples. This study investigates the impact of sample contamination with oil-based mud filtrates on composition and phase behavior properties of different types of reservoir fluids, including volatile oil and gas condensate samples. The samples were purposely contaminated with a known amount of oil-based mud filtrates in the laboratory. The methods developed in this study were then applied to determine the original composition of the reservoir fluid from contaminated samples. The phase behavior of the contaminated samples was also investigated by performing constant composition expansion (CCE) tests at reservoir and surface conditions. The measured experimental data were used to tune EOSs by adjusting their parameters. The determined parameters of EOS tuned to the contaminated samples were used to calculate the parameters of EOS for the uncontaminated sample. EOS EOSs are used extensively to simulate the volumetric behavior and phase equilibrium of petroleum reservoir fluids. Among different types of EOSs, cubic EOSs have enjoyed considerable success in modeling because they are simple and give reliable results in phase equilibrium calculations. Two EOSs, the Valderrama1 modification of the Patel-Teja (VPT) EOS and a modified Peng-Robinson2 (mPR) EOS, were used in this study to perform phase equilibrium calculations. All binary interaction parameters (BIP) in the mixing rule were set to zero, and the temperature dependency of the attractive term was used as the tuning parameter to fit the measured data.3 Extended compositional analyses (up to C20+) of fluids were used in phase equilibrium calculations. The required critical properties of petroleum fractions to calculate parameters of EOS were determined by perturbation expansion correlations.4 The required boiling-point temperatures were calculated from the Riazi- Daubert5 correlation using the molecular weight and specific gravity of petroleum fractions. The Lee-Kesler6 correlation was used to calculate the accentric factor of compounds. Contaminated Reservoir Fluids Hydrocarbon-based fluids (natural or synthetic oils) are generally used in oil-based drilling muds. Because these fluids are soluble in the reservoir fluid, they can render the fluid analysis limited in value. Determination of the original fluid composition from the analysis of a contaminated sample is feasible, but isolating the properties of the reservoir fluid free from contamination is not easily accomplished. Despite the recent improvements in sampling reservoir fluids,7,8 obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Therefore, modeling techniques are required, along with the laboratory studies, to determine the composition and PVT properties of the uncontaminated fluid. We have demonstrated, as have other investigators,9,10 that an exponential relationship exists between the concentration of components in the C8+ portion of real reservoir fluids and the corresponding molecular weights. For example, if the molar concentration of single carbon number groups is plotted against their molecular weights, it will give a straight line on a semilogarithmic scale. Based on this feature of natural fluids, two methods have been developed in this study to retrieve the original composition of reservoir fluid from contaminated samples. The composition of the C8+ portion of contaminated sample is plotted against molecular weight on a semilogarithmic scale. The plotted data will show a departure from the line over the range affected by the contaminants (see Fig. 1). The concentrations of the contaminants are then skimmed from the semilog straight line, presumed to be valid for the uncontaminated reservoir fluid. The fitted line is used to determine the composition of the uncontaminated fluid. The above method, referred to as the Skimming method, gives a reliable composition of the uncontaminated fluid if the contaminant comprises a limited hydrocarbon range. MacMillan et al.11 developed a similar method. They fitted a gamma distribution function to the composition of the C7+ portion of contaminated oil samples, excluding the composition of contaminants from the datafitting procedure.

Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Centrifuge Data

2009 ◽  
Vol 12 (05) ◽  
pp. 793-802 ◽  
Author(s):  
P. David Ting ◽  
Birol Dindoruk ◽  
John Ratulowski
Keyword(s):  
Experimental Data ◽  
Phase Behavior ◽  
Rock Properties ◽  
Model Parameters ◽  
Fluid Composition ◽  
Bulk Fluid ◽  
Reservoir Fluid ◽  
Fluid Systems ◽  
Fluid Properties ◽  
The Impact

Summary Fluid properties descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and subsea production systems and high-temperature/high-pressure (HTHP) reservoir fluids have elevated the importance of fluid properties in which well-count and initial rate estimates are quite crucial for development decisions. Similar to rock properties, fluid properties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper, we have studied the effects of gravitational fluid segregation using experimental data available for five live-oil and condensate systems (at pressures between 6,000 and 9,000 psi and temperatures from 68 to 200°F) considering the impact of fluid composition and phase behavior. Under isothermal conditions and in the absence of recharge, gravitational segregation will dominate. However, gravitational effects are not always significant for practical purposes. Since the predictive modeling of gravitational grading is sensitive to characterization methodology (i.e., how component properties are assigned and adjusted to match the available data and component grouping) for some reservoir-fluid systems, experimental data from a specially designed centrifuge system and analysis of such data are essential for calibration and quantification of these forces. Generally, we expect a higher degree of gravitational grading for volatile and/or near-saturated reservoir-fluid systems. Numerical studies were performed using a calibrated equation-of-state (EOS) description on the basis of fluid samples taken at selected points from each reservoir. Comparisons of measured data and calibrated model show that the EOS model qualitatively and, in many cases, quantitatively described the observed equilibrium fluid grading behavior of the fluids tested. First, equipment was calibrated using synthetic fluid systems as shown in Ratulowski et al. (2003). Then real reservoir fluids were used ranging from black oils to condensates [properties ranging from 27°API and 1,000 scf/stb gas/oil ratio (GOR) to 57°API and 27,000 scf/stb GOR]. Diagnostic plots on the basis of bulk fluid properties for reservoir fluid equilibrium grading tendencies have been constructed on the basis of interpreted results, and sensitivities to model parameters estimated. The use of centrifuge data was investigated as an additional fluid characterization tool (in addition to composition and bulk phase behavior properties) to construct more realistic reservoir fluid models for graded reservoirs (or reservoirs with high grading potential) have also been investigated.

High-Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen

2014 ◽  
Vol 17 (03) ◽  
pp. 384-395 ◽  
Author(s):  
Odd Steve Hustad ◽  
Na Jia ◽  
Karen Schou Pedersen ◽  
Afzal Memon ◽  
Sukit Leekumjorn
Keyword(s):  
High Pressure ◽  
Gulf Of Mexico ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Positive Impact ◽  
Viscosity Reduction ◽  
Fluid Composition ◽  
Viscosity Data ◽  
Oil Viscosity ◽  
Reservoir Fluid

Summary This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include: Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations. The data were modeled with the volume-corrected Soave-Redlich-Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen. Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.

Application of Tracers in Oil-Based Mud for Obtaining High-Quality Fluid Composition in Lean Gas/Condensate Reservoirs

2007 ◽  
Vol 10 (01) ◽  
pp. 5-11 ◽  
Author(s):  
Fathollah Gozalpour ◽  
Ali Danesh ◽  
Adrian Christopher Todd ◽  
Bahman Tohidi
Keyword(s):  
Drilling Fluid ◽  
Gas Condensate ◽  
Fluid Composition ◽  
Drilling Process ◽  
Two Fluids ◽  
The North ◽  
Reservoir Fluid ◽  
Partially Miscible ◽  
The North Sea ◽  
Mud Filtrate

Summary Oil-based drilling fluids are used extensively in drilling activities worldwide. During the drilling process, because of overbalance pressure in the mud column, the filtrate of oil-based mud invades the formation. This hydrocarbon-based filtrate mixes with the formation hydrocarbon, which can cause major difficulties in obtaining a representative reservoir-fluid sample. Despite the recent improvements in sampling, obtaining a contamination-free formation fluid is a major challenge, particularly in openhole wells. Depending on the type and conditions of the reservoir, the oil-based-mud filtrate is totally or partially miscible with the formation fluid. Oil-based-mud filtrate dissolves completely in reservoir oil; therefore, the captured sample contains the true reservoir oil with added filtrate. Gas condensate (lean gas condensate in particular) is often not fully miscible with mud filtrate. In this case, the mass exchange between gas condensate and mud filtrate makes the sample unrepresentative of the reservoir fluid. In this study, the impact of sample contamination with oil-based-mud filtrate on different types of reservoir fluids, including gas condensate and volatile-oil samples, is investigated. Two simple methods are suggested to retrieve the uncontaminated composition from a contaminated sample in which mud filtrate is totally dissolved in the formation fluid (i.e., reservoir-oil samples). A tracer-based technique is also developed to determine the composition of an uncontaminated reservoir-fluid sample from a sample contaminated with oil-based-mud filtrate, particularly for those cases in which the two fluids are partially miscible. The tracers are added to the drilling fluid, with the additional cost to the drilling-mud preparation being negligible. The capability of the developed techniques has been examined against deliberately contaminated reservoir-fluid samples under controlled conditions in the laboratory. The results indicate the reliability of the proposed methods. Introduction Historically, most drilling in the North Sea has used water-based muds; however, drilling certain formations with water-based muds can be difficult, primarily because of the hole instability caused by the swelling of water-absorbing rock. Problems of this type can be greatly alleviated by using mud suspended in an oil (rather than water) base. These oil-based muds also provide better lubrication and achieve significant increases in drilling progress (Davies et al. 1984). In recent years, oil-based drilling fluid has been used extensively in drilling activities in the North Sea. During the drilling process, because of overbalance pressure in the mud column, the mud filtrate invades the reservoir formation. Using an oil-based mud in the drilling, the mud filtrate can mix with the formation fluid. This can cause major difficulties in obtaining high-quality formation-fluid samples. Depending on the type and conditions of the reservoir, the mud filtrate can be totally or partially miscible with the formation fluid. This can alter the composition and phase behavior of the reservoir fluid significantly. Hence, the measured data using the collected formation-fluid samples need to be corrected for the contamination. In this study, contamination of different types of reservoir fluids with oil-based-mud filtrate, where the two fluids are partially or totally miscible, is discussed. Practical decontamination techniques are proposed to retrieve the original fluid composition from contaminated samples.

scholarly journals The effect of impurity on miscible CO2 displacement mechanism

2019 ◽  
Vol 74 ◽  
pp. 86
Author(s):  
Erhui Luo ◽  
Yongle Hu ◽  
Jianjun Wang ◽  
Zifei Fan ◽  
Qingying Hou ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Maximum Level ◽  
Volatile Oil ◽  
Real Field ◽  
Displacement Mechanism ◽  
Black Oil ◽  
Different Types ◽  
Reservoir Conditions ◽  
Simulation Results

The CO2 displacement is one of the gasflooding Enhanced Oil Recovery (EOR) methods. The application from volatile oil to black oil is popular mainly because CO2 requires a relatively low miscibility pressure, which is suitable to most reservoir conditions. However, CO2 always contains some impurity, such as CH4, H2S and N2, leading to the change of phase behavior and flooding efficiency. Whether the gasflooding achieves successfully miscible displacement depends on the reservoir pressure and temperature, injected solvent and crude oil compositions. So three different types of oil samples from the real field are selected and mixtures of CH4, H2S and N2 with various CO2 concentrations as the solvent are considered. After a series of experimental data are excellently matched, three nine-pseudocomponent models are generated based on the thermodynamic Equation-of-State (EoS), which are capable of accurately predicting the complicated phase behavior. Three common tools of pressure–temperature (P–T), pressure–composition (P–X) and pseudoternary diagrams are used to display and analyze the alteration of phase behavior and types of displacement mechanism. Simulation results show that H2S is favorable to attain miscibility while CH4 and N2 are adverse, and the former can reduce the Multiple Contact Miscibility (MCM) pressure by the maximum level of 1.675 MPa per 0.1 mol. In addition, the phase envelope of the mixtures CO2/H2S displacing the reservoir oil on the pseudoternary diagram behaves a triangle shape, indicating the condensing-dominated process. While most phase envelopes of CO2/CH4 and CO2/N2 exhibit the trump and bell shapes, revealing the MCM of vaporization.

Accuracy and Precision of Reservoir Fluid Characterization Tests Through Blind Round-Robin Testing

2021 ◽  
Author(s):  
Arwa Mawlod ◽  
Afzal Memon ◽  
John Nighswander
Keyword(s):  
Molar Mass ◽  
Sensitivity Study ◽  
Round Robin ◽  
Fluid Composition ◽  
Mass Measurements ◽  
Reservoir Fluid ◽  
Stock Tank ◽  
Fluid Characterization ◽  
Plus Fraction ◽  
The Impact

Abstract Objectives/Scope: Oil and gas operators use a variety of reservoir engineering workflows in addition to the reservoir, production, and surface facility simulation tools to quantify reserves and complete field development planning activities. Reservoir fluid property data and models are fundamental input to all these workflows. Thus, it is important to understand the propagation of uncertainty in these various workflows arising from laboratory fluid property measured data and corresponding model uncertainty. The first step in understanding the impact of laboratory data uncertainty was to measure it, and as result, ADNOC Onshore undertook a detailed study to assess the performance of four selected reservoir fluid laboratories. The selected laboratories were evaluated using a blind round-robin study on stock tank liquid density and molar mass measurements, reservoir fluid flashed gas and flashed liquid C30+ reservoir composition gas chromatography measurements, and Constant Mass Expansion (CME) Pressure-Volume-Temperature (PVT) measurements using a variety of selected reservoir and pure components test fluids. Upon completion of the analytical study and establishing a range of measurement uncertainty, a sensitivity analysis study was completed using an equation of state (EoS) model to study the impact of reservoir fluid composition and molecular weight measurement uncertainty on EoS model predictions. Methods, Procedures, Process: A blind round test was designed and administered to assess the performance of the four laboratories. Strict confidentiality was maintained to conceal the identity of samples through blind test protocols. The round-robin tests were also witnessed by the researchers. The EoS sensitivity study was completed using the Peng Robinson EoS and a commercially available software package. Results, Observations, Conclusions: The results of the fully blind reservoir fluid laboratory tests along with the statistical analysis of uncertainties will be presented in this paper. One of the laboratories had a systemic deviation in the measured plus fraction composition on black oil reference standard samples. The plus fraction concentration is typically the largest weight percent component in black oil systems and, along with the plus fraction molar mass, plays a crucial role in establishing the mole percent overall reservoir fluid compositions. Another laboratory had systemic issues related to chromatogram component integration errors that resulted in inconsistent carbon number concentration trends for various components. All laboratories failed to produce consistent molecular weight measurements for the reference samples. Finally, one laboratory had a relative deviation for P-V measurements that were significantly outside the acceptable range. The EoS sensitivity study demonstrates that the fluid composition and stock tank oil molar mass measurements have a significant impact on EoS model predictions and hence the reservoir/production models input when all other parameters are fixed. Novel/Additive Information: To the best of our knowledge, this is the first time such an extensive and fully blind round-robin test of commercial reservoir fluid characterization laboratories has been completed and published in the open literature. The industry should greatly benefit from this first-of-its-kind blind round-robin dataset being made available to all. The study provides the basis, protocols, expectations, and recommendations for such independent round-robin testing for fluid characterization laboratories on a broader scale.

New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization

2008 ◽  
Vol 11 (06) ◽  
pp. 1107-1116 ◽  
Author(s):  
Chengli Dong ◽  
Michael D. O'Keefe ◽  
Hani Elshahawi ◽  
Mohamed Hashem ◽  
Stephen M. Williams ◽  
...  
Keyword(s):  
Real Time ◽  
Hydrocarbon Composition ◽  
Fluid Composition ◽  
Fluid Sample ◽  
Fluid Analysis ◽  
Reservoir Fluid ◽  
Reservoir Conditions ◽  
Fluid Properties ◽  
Fluid Characterization ◽  
Compositional Grading

Summary Downhole fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy, which can provide estimates of filtrate contamination, gas/oil ratio (GOR), pH of formation water, and a hydrocarbon composition in four groups: methane (C1), ethane to pentane (C2-5), hexane and heavier hydrocarbons (C6+), and carbon dioxide (CO2). For single-phase assurance, it is possible to detect gas liberation (bubblepoint) or liquid dropout (dewpoint) while pumping reservoir fluid to the wellbore, before filling a sample bottle. In this paper, a new DFA tool is introduced that substantially increases the accuracy of these measurements. The tool uses a grating spectrometer in combination with a filter-array spectrometer. The range of compositional information is extended from four groups to five groups: C1, ethane (C2), propane to pentane (C3-5), C6+, and CO2. These spectrometers, together with improved compositional algorithms, now make possible a quantitative analysis of reservoir fluid with greater accuracy and repeatability. This accuracy enables comparison of fluid properties between wells for the first time, thus extending the application of fluid profiling from a single-well to a multiwall basis. Field-based fluid characterization is now possible. In addition, a new measurement is introduced--in-situ density of reservoir fluid. Measuring this property downhole at reservoir conditions of pressure and temperature provides important advantages over surface measurements. The density sensor is combined in a package that includes the optical spectrometers and measurements of fluid resistivity, pressure, temperature, and fluorescence that all play a vital role in determining the exact nature of the reservoir fluid. Extensive tests at a pressure/volume/temperature (PVT) laboratory are presented to illustrate sensor response in a large number of live-fluid samples. These tests of known fluid compositions were conducted under pressurized and heated conditions to simulate reservoir conditions. In addition, several field examples are presented to illustrate applicability in different environments. Introduction Reservoir-fluid samples collected at the early stage of exploration and development provide vital information for reservoir evaluation and management. Reservoir-fluid properties, such as hydrocarbon composition, GOR, CO2 content, pH, density, viscosity, and PVT behavior are key inputs for surface-facility design and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory, and it usually takes a long time (months) before the results become available. Also, miscible contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However, the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduced recently in the next-generation wireline formation testers (O'Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in real time, and fluid composition is derived from the spectra on the basis of C1, C2-5, C6+, and CO2; then, GOR of the fluid is estimated from the derived composition (Betancourt et al. 2004; Fujisawa et al. 2002; Dong et al. 2006; Elshahawi et al. 2004; Fujisawa et al. 2008; Mullins et al. 2001; Smits et al. 1995). Additionally, from the differences in absorption spectrum between reservoir fluid and filtrate of oil-based mud (OBM) or water-based mud (WBM), fluid-sample contamination from the drilling fluid is estimated (Mullins et al. 2000; Fadnes et al. 2001). With the DFA technique, reservoir-fluid samples are analyzed before they are taken, and the quality of fluid samples is improved substantially. The sampling process is optimized in terms of where and when to sample and how many samples to take. Reservoir-fluid characterization from fluid-profiling methods often reveals fluid compositional grading in different zones, and it also helps to identify reservoir compartmentalization (Venkataramanan et al. 2008). A next-generation tool has been developed to improve the DFA technique. This DFA tool includes new hardware that provides more-accurate and -detailed spectra, compared to the current DFA tools, and includes new methods of deriving fluid composition and GOR from optical spectroscopy. Furthermore, the new DFA tool includes a vibrating sensor for direct measurement of fluid density and, in certain environments, viscosity. The new DFA tool provides reservoir-fluid characterization that is significantly more accurate and comprehensive compared to the current DFA technology.

scholarly journals Effects of Diffusion, Adsorption, and Hysteresis on Huff-n-Puff Performance in Ultratight Reservoirs with Different Fluid Types and Injection Gases

Energies ◽  
2021 ◽  
Vol 14 (21) ◽  
pp. 7379
Author(s):  
Khaled Enab ◽  
Hamid Emami-Meybodi
Keyword(s):  
Oil Recovery ◽  
Large Scale ◽  
Volatile Oil ◽  
Production Performance ◽  
Compositional Model ◽  
Reservoir Fluid ◽  
Wide Range ◽  
Black Oil ◽  
Shale Reservoirs ◽  
The Impact

Cyclic solvent injection, known as solvent huff-n-puff, is one of the promising techniques for enhancing oil recovery from shale reservoirs. This study investigates the huff-n-puff performance in ultratight shale reservoirs by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, and black oil) and different injection gases (CO2, C2H6, and C3H8). A dual-porosity compositional model is utilized to comprehensively evaluate the impact of multicomponent diffusion, adsorption, and hysteresis on the production performance of each reservoir fluid and the retention capacity of the injection gases. The results show that the huff-n-puff process improves oil recovery by 4–6% when injected with 10% PV of gas. Huff-n-puff efficiency increases with decreasing gas-oil ratio (GOR). C2H6 provides the highest recovery for the black oil and volatile oil systems, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and adsorption are essential mechanisms to be considered when modeling gas injection in shale reservoirs. However, the relative permeability hysteresis effect is not significant. Diffusion impact increases with GOR, while adsorption impact decreases with increasing GOR. Oil density reduction caused by diffusion is observed more during the soaking period considering that the diffusion of the injected gas caused a low prediction error, while adsorption for the injected gas showed a noticeable error.

scholarly journals Experiment and Simulation Study on the Special Phase Behavior of Huachang Near-Critical Condensate Gas Reservoir Fluid

2016 ◽  
Vol 2016 ◽  
pp. 1-10 ◽  
Author(s):  
Dali Hou ◽  
Yang Xiao ◽  
Yi Pan ◽  
Lei Sun ◽  
Kai Li
Keyword(s):  
Phase Behavior ◽  
Oil And Gas ◽  
Experimental Studies ◽  
Volatile Oil ◽  
Considerable Change ◽  
Liquid Composition ◽  
Reduced Pressure ◽  
Pressure Drops ◽  
Liquid Saturation ◽  
Reservoir Fluid

Due to the special phase behavior of near-critical fluid, the development approaches of near-critical condensate gas and near-critical volatile oil reservoirs differ from conventional oil and gas reservoirs. In the near-critical region, slightly reduced pressure may result in considerable change in gas and liquid composition since a large amount of gas or retrograde condensate liquid is generated. It is of significance to gain insight into the composition variation of near-critical reservoir during the depletion development. In our study, we performed a series ofPVTexperiments on a real near-critical gas condensate reservoir fluid. In addition to the experimental studies, a commercial simulator combined with the PREOS model was utilized to study retrograde condensate characteristics and reevaporation mechanism of condensate oil with CO2injection based on vapor-liquid phase equilibrium thermodynamic theory. The research shows that when reservoir pressure drops below a certain pressure, the variation of retrograde condensate liquid saturation of the residual reservoir fluid exhibits the phase behavior of volatile oil.

Impact of Reservoir Fluid and Injection Gas on Shales Huff-N-Puff Performance in the Presence of Diffusion, Sorption, and Hysteresis

2021 ◽  
Author(s):  
Khaled Enab ◽  
Hamid Emami-Meybodi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Volatile Oil ◽  
Fluid Type ◽  
Retention Capacity ◽  
Eagle Ford ◽  
Reservoir Fluid ◽  
Black Oil ◽  
The Impact ◽  
And Diffusion

Abstract We assess the huff-n-puff performance in ultratight reservoirs (shales) by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, black oil) and different injection gases (CO2, C2H6, C3H8) by considering relative permeability hysteresis, diffusion, and sorption. A dual-porosity naturally fractured numerical compositional model is used that considers molecular diffusion and sorption to represent the flow mechanisms during the injection process. Killough's method, Langmuir's adsorption model, and Sigmund correlation are utilized to incorporate hysteresis, sorption, and diffusion, respectively. To investigate the impact of the fluid type, we consider three fluid types from Eagle Ford shale representing retrograde condensate, volatile oil, and black oil. We conduct a comprehensive evaluation of the impact of diffusion, sorption, and hysteresis on the production performance and retention of each fluid and injection gas. Eagle Ford formation is selected because it is the most actively developed shale, and it contains a wide span of PVT windows from dry gas to black oil. The simulation results show that the huff-n-puff process improves the oil recovery by 4-6% when 10% PV of gas is injected. The huff-n-puff efficiency increases with reducing gas-oil-ratio (GOR) as oil recovery from low (GOR) reservoirs is doubled, while recovery from retrograde condensate increased by 20%. C2H6 provides the highest recovery for the black and volatile oil, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and sorption are essential mechanisms to be considered when modeling gas injection to any fluid type in shales. However, the relative permeability hysteresis effect is not significant. Neglecting diffusion during the huff-n-puff process underestimates the oil recovery and retention capacity. The diffusion effect on the oil density reduction is observed more during the soaking period. The diffusion impact increases with higher GOR reservoirs, while the sorption impact decreases with higher GOR. The retention capacity of the injected gas decreases with higher GOR. The diffusion impact on the retention capacity increases with higher GOR. Hence sorption and diffusion must be considered when modeling the huff-n-puff process in ultratight reservoirs.

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