Pressure Volume Temperature Research Articles

An experimental and theoretical investigation of asphaltene precipitation in a crude oil from the Brazilian pre-salt layer under CO2 injection

The asphaltene onset pressure (AOP) is a key parameter to determine the flow assurance of oils. In this work we performed an experimental study of the PVT (pressure–volume-temperature) properties of a crude oil from the Brazilian pre-salt layer. First, dead-oil was recombined with natural gas at the reservoir gas-oil ratio (GOR). Then, different techniques (volumetric, visual, light-scattering and filtration) were used to measure the AOP and bubble pressure (BP) at temperatures in the range of (293.15 to 348.15) K. The effect of CO2 injection on both properties was also evaluated at reservoir temperature. Additional data of mass density was measured at reservoir pressure and temperature. The experimental data were used to fit the adjustable parameters of the Peng–Robinson equation of state (PR-EoS) and the calculated results are compatible with the experimental data. The PR-EoS calculates a decrease in the AOP and an increase in the BP as temperature rises. PR-EoS correctly predicts the qualitative effect of gas injection on the studied properties: all evaluated properties increase as CO2 is injected in the recombined oil.

Prediction of Joule-Thomson coefficient and inversion curve for natural gas and its components using CFD modeling

In this study, three equations of state (EOS) in conjunction with computational fluid dynamics (CFD) modeling were used to predict the Joule – Thomson (JT) process behavior for natural gas and various pure gases. The JT effect is encountered in several industrial applications. The experimental determination of the JT coefficient (JTC) is complicated, and there is little gas pressure-volume-temperature (PVT) data available for estimating these JTC. Thus, the development of an efficient model to predict the JT effect in industrial processes is necessary. This study was carried out to attain a clear view of the single phase-flow of hydrocarbons and nitrogen in the JT process with CFD modeling. The JT valve was modeled in a pipe so as to predict the JTC, inversion curve (IC) and the isenthalpic curve of nitrogen, methane, ethane, propane and their mixtures in a wide range of temperature and pressure. Generally, the low-temperature branch of IC was predicted accurately by most of EOSs. Among the considered EOSs, Soave-Redlich-Kwong (SRK) EOS is able to predict more accurately the Joule – Thomson inversion curve (JTIC) in comparison with the other EOS. The validation of this CFD modeling was conducted using the experimental data from the literature and the industrial data of natural gas from an Iranian Gas Dehydration unit. The outlet temperature obtained from the CFD model agreed well with the industrial data of the JT process. The proposed CFD model accurately predicts the experimental and the industrial data of the JT process.

Modeling and experiment for effective diffusion coefficient of gas in water-saturated coal

The diffusion of gas in water-saturated porous media plays a significant role in CO2 geological sequestration and mine gas prevention and control. However, it is lack of an accurate model to calculate the effective diffusion coefficient of gas in a water-saturated coal core. In this work, an improved model was constructed to calculate the effective diffusion coefficient of gas in a water-saturated coal core by considering both the gas adsorption in residual pore and the gas dissolution in pore water. By using a PVT (Pressure-Volume-Temperature) test method, the calculation results of improved model are in the range of 1.03 × 10−12 ~ 30.40 × 10−12m2/s, which are 5 ~ 6 orders of magnitude lower than those calculated by traditional model, because the traditional model only considers the gas dissolution in pore water. Therefore, the results of improved model are more in line with the actual situation. Furthermore, the saturated moisture, equilibrium moisture and NMR experiments were carried out. Results shows that, the saturated moisture and equilibrium moisture decreases with the rising coal rank. The pore size changes from micropore/mesopore-dominated to micropores-dominated as the coal rank rise. In addition, the proportion of open porosity gradually reduces with the rising coal rank, while the closed porosity increases, indicating that the pore connectivity decreases with the growing coal rank. Finally, the influences of adsorbability, pore structure, pressure and liquid properties on the effective diffusion coefficient were analyzed.

Committee Machine-Ensemble as a General Paradigm for Accurate Prediction of Bubble Point Pressure of Crude Oil

Abstract Bubble point pressure (BPP) not only is a basic pressure–volume–temperature (PVT) parameter for calculation nearly all of the crude oil characteristics, but also determines phase-type of oil reservoirs, gas-to-oil ratio, oil formation volume factor, inflow performance relationship, and so on. Since the measurement of BPP of crude oil is an expensive and time-consuming experiment, this study develops a committee machine-ensemble (CME) paradigm for accurate estimation of this parameter from solution gas-oil ratio, reservoir temperature, gas specific gravity, and stock-tank oil gravity. Our CME approach is designed using a linear combination of predictions of four different expert systems. Unknown coefficients of this combination are adjusted through minimizing deviation between actual BPPs and their associated predictions using differential evolution and genetic algorithm. Our proposed CME paradigm is developed using 380 PVT datasets for crude oils from different geological regions. This novel intelligent paradigm estimates available experimental databank with excellent accuracy i.e., absolute average relative deviation (AARD) of 6.06% and regression coefficient (R2) of 0.98777. Accurate prediction of BPP using our CME paradigm decreases the risk of producing from a two-phase region of oil reservoirs.

A Semianalytical Approach for Analysis of Wells Exhibiting Multiphase Transient Linear Flow: Application to Field Data

Summary Rate-transient analysis (RTA) is a useful reservoir/hydraulic fracture characterization method that can be applied to multifractured horizontal wells (MFHWs) producing from low-permeability (tight) and shale reservoirs. In this paper, we applied a recently developed three-phase RTA technique to the analysis of production data from an MFHW completed in a low-permeability volatile oil reservoir in the Western Canadian Sedimentary Basin. This RTA technique is used to analyze the transient linear flow regime for wells operated under constant flowing bottomhole pressure (BHP) conditions. With this method, the slope of the square-root-of-time plot applied to any of the producing phases can be used to directly calculate the linear flow parameter xfk without defining pseudovariables. The method requires a set of input pressure/volume/temperature (PVT) data and an estimate of two-phase relative permeability curves. For the field case studied herein, the PVT model is constructed by tuning an equation of state (EOS) from a set of PVT experiments, while the relative permeability curves are estimated from numerical model history-matchingresults. The subject well, an MFHW completed in 15 stages, produces oil, water, and gas at a nearly constant (measured downhole) flowing BHP. This well is completed in a low-permeability,near-critical volatile oil system. For this field case, application of the recently proposed RTA method leads to an estimate of xfk that is in close agreement (within 7%) with the results of a numerical model history match performed in parallel. The RTA method also provides pressure–saturation (P–S) relationships for all three phases that are within 2% of those derived from the numerical model. The derived P–S relationships are central to the use of other RTA methods that require calculation of multiphase pseudovariables. The three-phase RTA technique developed herein is a simple-yet-rigorous and accurate alternative to numerical model history matching for estimating xfk when fluid properties and relative permeability data are available.

Thermodynamics of Model PαMSAN/dPMMA Blend: A Combined Study by SANS, Ellipsometry, and Locally Correlated Lattice (LCL) Theory

We combine experiment and theory to elucidate how small, local, structural changes can impact miscibility in polymer blends. Small-angle neutron scattering (SANS) experiments yield both the phase boundaries and the temperature dependence of the second derivative of the free energy of mixing. We demonstrate here, for the first time, that a fundamental characterization of pure component properties can be achieved through ellipsometry measurements on films of pure polymers (thickness ∼200 nm) to provide key data on the volume (or thickness)–temperature relationships; this development is significant given the scarcity of precise pressure–volume–temperature (PVT) data on pure polymers and blends. The experimental measurements allow us to undertake a detailed thermodynamic analysis of mixing using the locally correlated lattice (LCL) theory, which has been shown to be effective in rationalizing blend miscibility in terms of the pure component properties. We focus here on polymer blends of poly(α-methyl styrene-co-acrylonitrile) (PαMSAN) with deuterated poly(methyl methacrylate) (dPMMA), which differ in the degree of tacticity in the dPMMA component (atactic or syndiotactic), leading to an increase in miscibility for the latter. By combining LCL analysis of pure and mixed systems, we are able to connect tacticity changes to shifts in local nonbonded interactions, in free volume, and in thermal expansion coefficients, which in turn impact the thermodynamic compatibility of the blend components.

Thermoelasticity and stability of natural epidote at high pressure and high temperature: Implications for water transport during cold slab subduction

Epidote is a typical hydrous mineral in subduction zones. Here, we report a synchrotron-based single-crystal X-ray diffraction (XRD) study of natural epidote [Ca1.97Al2.15Fe0.84(SiO4)(Si2O7)O(OH)] under simultaneously high pressure-temperature (high P-T) conditions to ~17.7 ​GPa and 700 ​K. No phase transition occurs over this P-T range. Using the third-order Birch-Murnaghan equation of state (EoS), we fitted the pressure-volume-temperature (P-V-T) data and obtained the zero-pressure bulk modulus K0 ​= ​138(2) GPa, its pressure derivative K0' ​= ​3.0(3), the temperature derivative of the bulk modulus ((∂K/∂T)P ​= ​−0.004(1) GPa/K), and the thermal expansion coefficient at 300 ​K (α0 ​= ​3.8(5) ​× ​10−5 ​K−1), as the zero-pressure unit-cell volume V0 was fixed at 465.2(2) Å3 (obtained by a single-crystal XRD experiment at ambient conditions). This study reveals that the bulk moduli of epidote show nonlinear compositional dependence. By discussing the stabilization of epidote and comparing its density with those of other hydrous minerals, we find that epidote, as a significant water transporter in subduction zones, may maintain a metastable state to ~14 ​GPa along the coldest subducting slab geotherm and promote slab subduction into the upper mantle while favoring slab stagnation above the 410 ​km discontinuity. Furthermore, the water released from epidote near 410 ​km may potentially affect the properties of the 410 ​km seismic discontinuity.

Formation-Fluid Microsampling While Drilling Enables Complete Reservoir Characterization

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195806, “Formation-Fluid Microsampling While Drilling: A New PVT and Geomechanical Formation-Evaluation Technique,” by Julia Golovko, Christopher Jones, SPE, and Bin Dai, Halliburton, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. Pressure/volume/temperature (PVT) phase behavior characterization and geochemical compositional analysis of petroleum samples play a crucial role in the determination of producible reserves and the best production strategy. Openhole samples are the most-valuable types of samples for PVT and geochemical analysis but are costly and limited to 10 to 20 samples. The complete paper presents a technical discussion of a new microsampling technique for logging while drilling (LWD) and a corresponding wellsite technique to provide compositional interpretation, contamination assessment, reservoir-fluid compositional grading, and reservoir compartmentalization assessment. This microscale approach enables fast analysis by using field or near-field deployment of the analytical tool. The results inform planning for wireline sample retrieval, if necessary. Technique Overview The microsampler used in the downhole tool can collect reservoir fluid in small quantities suitable for compositional analysis. Because of its small size, the microsampler can gather multiple fluids at various reservoir depths, while PVT sampling requires larger volumes and has more constraints. However, when used in combination with conventional PVT-grade samples, the microsamples can provide significant chemical profiling. The 40-ml quantity provides the ability to collect many more samples than the conventional PVT sample size of 200 to 1,000 ml. Additionally, 40 ml provides more than enough of a sample for a complete chemical analysis using a liquid chromatograph or gas chromatograph coupled with either a mass spectrometer for biomarker analysis or a flame-ionization detector (FID) for a complete assay. Isotope analysis is also possible. Recovery to surface of fluid samples collected at reservoir temperature and pressure allows for analysis with an automated gas chromatograph (GC) deployed in the field, providing reduced labor and rapid analysis. The unique injection chamber of the GC is designed with the injection port and valve configured to withstand pressure up to 5,000 psi, a tolerance approximately five times higher than that of standard GC injection valves. This allows for injection of the microsample with a solvent carrier as a single-phase fluid so that analysis can provide composition and fluid properties such as gas/oil ratio without a flash. The GC has two detectors, including an FID for hydrocarbon components and a thermal conductivity detector for inorganic gas components such as carbon dioxide, nitrogen, and hydrogen sulfide. The system can quantify hydrocarbon components from C1 to C36 and perform contamination studies of oil samples with drilling fluids. According to the authors, the technique enables reservoir engineers to characterize a reservoir completely without limit to the number of acquired samples. They write that, in combination with conventional PVT samples, it is possible to extrapolate PVT properties to all pump-out stations and conduct a complete geochemical profile of the reservoir.

VARIATION OF SATURATION PRESSURE VALUES IN MISHRIF AND ZUBAIR RESERVOIRS IN RUMAILA OILFIELD, SOUTHERN IRAQ

Reservoir fluid, pressure volume temperature properties such as bubble point pressure, gas solubility, oil and gas formation volume factors, and viscosities are important elements in the reservoir management and field development. Therefore, this study aims to distribute the bubble point pressure on the main oil reservoirs in the Rumaila oilfield, laboratories tests results from 103 pressure volume temperature reports were used, these tests were obtained from the Mishrif, Upper Shale and Main pay reservoirs. Pressure gradient in the study area was defined using Surfer14 software, and in order to avoid the variation of low-pressure areas in the future drilling wells plan, continuous monitoring and focus on these areas, pressure maps were drawn then reading graduation of pressure on these maps to obtain final formula to adopt a specific range of saturation pressures values ​​and distribute them among Rumaila oilfield. The study also compares between the main sub-units of the Main pay reservoir and Mishrif reservoir in the North Rumaila and other reservoirs in the South Rumaila oilfield as well as to define other factors in pressure volume temperature reports such as gas oil ratio, viscosity and formation volume factor that contribute to the saturation pressure variation.

A semi-empirical method for predicting GOC in oil reservoirs with limited PVT dataset

Depending on the type, quality and quantity of available data, different methods exist to determine the hydrocarbon–hydrocarbon contacts in reservoirs. These methods are either direct or indirect. While the direct method involves consciously drilling a well to penetrate potential fluid contacts, the indirect methods include pressure measurements across at least two different fluid types, and/or, the acquisition and subsequent characterization of downhole fluid samples. Recognizing that most petroleum reservoirs are compositionally graded to varying degrees, compositional grading simulation (CGS) is an inexpensive indirect method of evaluating potential gas–oil contact (GOC) in petroleum reservoirs. However, this typically requires detailed pressure–volume–temperature (PVT) data of the hydrocarbon fluids. But, in many cases, PVT data may be limited. To address the challenges in such cases, this paper proposes a new predictive model and practical workflow, hence extending the applicability of CGS. Employing several PVT datasets and rigorous CGS for known black and volatile oil reservoirs, a new semiempirical function is developed for estimating saturation pressure gradient from gas oil ratio (GOR), which is a readily measurable fluid property. Complementing this function, is the identification of a robust empirical model to predict saturation pressure. The associated workflow provides a systematic integration of the predictive saturation gradient and saturation pressure models to estimate the degree of undersaturation, and hence, potential GOC depth in a reservoir characterized by limited PVT dataset. For validation tests, some cases of saturated and undersaturated reservoirs in the Niger Delta are presented. The results confirm the applicability of the new method in the Niger Delta and elsewhere.

Confinement-Mediated Phase Behavior of Hydrocarbon Fluids: Insights from Monte Carlo Simulations.

The phase behavior of hydrocarbon fluids confined in porous media has been reported to deviate significantly from that in the bulk environment due to the existence of sub-10 nm pores. Though experiments and simulations have measured the bubble/dew points and sorption isotherms of hydrocarbons confined in both natural and synthetic nanopores, the confinement effects in terms of the strength of fluid-pore interactions tuned by surface wettability and chemistry have received comparably less discussion. More importantly, the underlying physics of confinement-induced phenomena remain obfuscated. In this work, we studied the phase behavior and capillary condensation of n-hexane to understand the effects of confinement at the molecular level. To systematically investigate the pore effects, we constructed two types of wall confinements; one is a structureless virtual wall described by the Steele potential and the other one is an all-atom amorphous silica structure with surface modified by hydroxyl groups. Our numerical results demonstrated the importance of fluid-pore interaction, pore size, and pore morphology effects in mediating the pressure-volume-temperature (PVT) properties of hydrocarbons. The most remarkable finding of this work was that the saturation pressure predicted from the van der Waals-type adsorption isothermal loop could be elevated or suppressed relative to the bulk phase, as illustrated in the graphical abstract. As the surface energy (i.e., fluid-pore interaction) decreased, the isothermal vapor pressure increased, indicating a greater preference for the fluid to exist in the vapor state. Sufficient reduction of the fluid-pore interactions could even elevate the vapor pressure above that of the bulk fluid.

Characterization of post-consumer plastic film waste from mixed MSW in Spain: A key point for the successful implementation of sustainable plastic waste management strategies

The purpose of this paper is to provide a full characterization of post-consumer plastic film recovered from mixed municipal solid waste (MSW) treatment plants in Spain. Currently, this type of plastic waste is not recycled due to technical or economic barriers and is still sent to landfill. Different types of municipal plastic waste (MPW) from manual and automated sorting were studied: i) colour plastic film recovered by ballistic separators and then manual sorting in different seasons; ii) colour plastic film recovered by automated sorting (air suction); and iii) white plastic film from primary manual sorting process. The samples were characterized by different techniques, including the ultimate and proximate analysis, Higher Heating Value (HHV) and Lower Heating Value (LHV), metal content, Thermogravimetric Analysis (TGA) and Derivative Thermogravimetry (DTG), Fourier Transform Infrared (FT-IR) analysis and Differential Scanning Calorimetry (DSC). The results were compared to those obtained for pretreated colour and white plastic film waste and contrasted with industrial recycled film granules of polyethylene (as a reference material for packaging film). Additionally, pretreated plastic film samples were also characterized by analyzing viscosity, Pressure-Volume-Temperature (PVT) diagram, specific heat capacity and halogen and sulphur contents. Characterization data from this study will contribute to identify and develop potential recycling alternatives for a more sustainable municipal plastic waste management, which is recognized as a priority in the European Circular Economy Action Plan to use resources in a more sustainable way.

Timeframe of hydrocarbon migration in the Paleogene Shahejie Formation in the Dongying depression, Bohai Bay Basin (northeastern China) based on fluid inclusions and oil geochemistry

The Dongying depression is an important oil-producing area in northeastern China, where the Paleogene Shahejie Formation is the main oil-bearing feature. Although petroleum migration and accumulation in the Dongying depression have been extensively studied, the charging history is still unclear. This paper defines the timeframe of petroleum migration on the basis of a comprehensive investigation of fluid inclusions coupled with basin modeling. According to the petrography and microthermometry of the fluid inclusions, types of fluid inclusion with low-peak-range distributions of the homogenization temperature (Th) (85–95 °C for the Niuzhuang sag and 90–105 °C for the Lijin sag) and high-peak-range Th distributions (105–120 °C for the Niuzhuang sag and 115–130 °C for the Lijin sag) were identified. By recovering the burial and thermal histories of Niuzhuang and Lijin sags with pressure–volume–temperature–composition simulation and one-dimensional basin modeling, it can be inferred that the trapping pressures of two types of hydrocarbon inclusions were higher than the corresponding paleopressure. (42.4 and 42.0 MPa, respectively), indicating rapid hydrocarbon charging resulting from abnormally high pressure. Two hydrocarbon charging events associated with the regional tectonic evolution of the Dongying depression, namely, continuous deposition and tectonics in the Paleogene Dongying Formation (Ed) and rapid deposition and tectonics in the Paleogene Minghuazhen Formation (Em), were inferred. The direction of oil charging was traced from the center to the margin in the north, and from the center to the central fault in the southeastern part of the depression in general, as indicated by the molecular maturity parameters, which roughly coincided with the abnormal pressure.

Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems and Their Interplay

Summary Acoustic velocity is one of the key thermodynamic properties that can supplement phase behavior or pressure/volume/temperature (PVT) measurements of pure substances and mixtures. Several important fluid properties are relatively difficult to obtain through traditional measurement techniques, correlations, or equation of state (EOS) models. Acoustic measurements offer a simpler method to obtain some of these properties. In this work, we used an experimental method based on ultrasonic pulse-echo measurements in a high-pressure/high-temperature (HP/HT) cell to estimate acoustic velocity in fluid mixtures. We used this technique to estimate related key PVT parameters (such as compressibility), thereby bridging gaps in essential data. In particular, the effect of dilution with methane (CH4) and carbon dioxide (CO2) at pressures from 15 to 62 MPa and temperatures from 313 to 344 K is studied for two reservoir fluid systems to capture the effect of the gas/oil ratio (GOR) and density variations on measured viscosity and acoustic velocity. Correlative analysis of the acoustic velocity and viscosity data were then performed to develop an empirical correlation that is a function of GOR. Such a correlation can be useful for improving the interpretation of the sonic velocity response and the calibration of viscosity changes when areal fluid properties vary with GOR, especially in disequilibrium systems. In addition, under isothermal conditions, the acoustic velocity of a live oil decreases monotonically with decreasing pressure until the saturation point where the trend is reversed. This observation can also be used as a technique to estimate the saturation pressure of a live oil or as a byproduct of the target experiments. It supplements the classical pressure/volume measurements to determine the bubblepoint pressure.

Studying Phase Behavior of Oil/Natural-Gas Systems for Designing Gas-Injection Operations: A Montney Case Study

SummaryAdvances in horizontal drilling and multistage hydraulic fracturing have unlocked tight-oil resources, such as the Montney Formation in the Western Canadian Sedimentary Basin. However, the average oil-recovery factor after primary production is 5 to 10% of the original oil in place. The aims of this study are to investigate phase behavior and to estimate the minimum miscibility pressure (MMP) of the Montney oil/natural-gas systems.First, we measure the MMPs of the oil/gas systems using the vanishing interfacial tension (VIT) technique. The gas samples are methane (C1) and mixtures of methane and ethane (C1/C2). Second, we perform constant-composition-expansion (CCE) tests to study the phase behavior of the oil/gas systems using a pressure/volume/temperature (PVT) cell. To complement the VIT and CCE tests, we perform bulk-phase tests to visualize vaporizing/condensing phenomena at the oil/gas interface using a visualization cell. Finally, we use the measured CCE and MMP data to calibrate the Peng-Robinson (Robinson and Peng 1978) equation of state (PR-EOS) and predict the MMP of the oil/gas systems using ternary diagrams. The results suggest that the dominant mechanism for developing miscibility conditions for oil/C1 and oil/C1/C2 systems is vaporizing and condensing gas drive, respectively. According to the results of the VIT and CCE tests, increasing C2 mole fraction in the gas mixtures significantly reduces MMP of the oil/gas system (from 4,366 psi for oil/C1 to 1,467 psi for oil/C1/C2 with 71.3 mol% C2) and increases the oil-swelling factor (from 1.47 to 1.61 by increasing C2 mol% from 0 to 70 mol%). The results of visualization tests show that the presence of C2 in the injection gas significantly enhances oil swelling compared with the pure-C1 case. We observe vaporizing flows of oil components in all tests and strong condensing flows of C1 and C2 into the oil phase in the C1/C2 test with increasing gas-injection pressure. The MMP values predicted by plotting two-phase equilibrium data on ternary diagrams appear to be in good agreement with the measured ones. The results can be used to optimize the injection-gas composition and operating pressure in the Montney.

Thermodynamic properties of a model hydrocarbon ternary mixture in the vicinity of critical point: Measurements and modeling with crossover equation of state

In the framework of the proposed theoretical model crossover and scaling equations of state for near-critical multicomponent hydrocarbon mixture were obtained. To elaborate the equations of state the experimental data measured on the serial setup intended for comprehensive pressure-volume-temperature (PVT) research of a natural gas-condensate systems were used. The information concerning the mixture composition was not involved. The obtained equations describe the experimental data with the accuracy not exceeding the measurement inaccuracy. It has been shown that in extended range of thermodynamic parameters the crossover equation of state looks more reliable. The crossover model describes the transition from the scaling behavior to the mean-field behavior, which is typical for cubic and multiparameter equations of state. The model was extended for calculation of the volume fractions of gas and liquid phases needed for practical applications. In addition, the expression for isothermal compressibility has been derived. It was demonstrated that the isothermal compressibility has a cusp-like anomaly in the close vicinity of the critical point.

Characterizing hydraulic and natural fractures properties in shale oil well in Permian basin using assisted history matching

We performed assisted history matching (AHM) to an actual shale oil well in Permian basin using Embedded Discrete Fracture Model and neural network Markov chain Monte Carlo algorithm. Three main scenarios were investigated including hydraulic fractures only, hydraulic fractures with one realization of natural fractures, and hydraulic fractures with natural fractures. We integrated data from diagnostic fracture injection test analysis, PVT (Pressure Volume Temperature) report, nearby-well core data and petrophysical interpretation as initial input for AHM workflow. The uncertain parameters consist of fracture geometry, fracture conductivity, matrix permeability, matrix and fracture water saturation, and relative permeability curves. For the case with natural fractures, we included number, length and conductivity of natural fractures as the additional uncertain parameters. From history matching, we obtained the posterior distribution of each fracture parameter and reservoir property for all three scenarios. We found that the presence of natural fractures affects the posterior distribution of matrix permeability and fracture geometry of history match solutions, when comparing to case without natural fractures, by shifting to lower value distributions because natural fractures enhance the flow besides hydraulic fractures. Multiple realizations were then used for a probabilistic production forecast. We might underpredict oil production and overpredict gas production if the actual system was assumed with only hydraulic fractures. Lastly, the benefits from the study are that hydraulic fractures, natural fractures and reservoir properties are characterized in a probabilistic manner from production data. The results from the study can be used to improve future fracturing design and optimize well spacing.

Gas-liquid two-phase flow measurement by combining a Coriolis flowmeter with a flow conditioner and analytical models

Abstract In oil-gas fields, two phase flow measurement of liquid-gas mixture for the whole Gas Void Fraction (GVF) range remains a challenging task. Coriolis flow meter is proven to be one of the most accurate device for single phase flow measurement. However, for two phase flow metering, its accuracy gets altered for liquid continuous phase (respectively gas continuous phase) in case of GVF that exceeds 20% (respectively low GVF that is lower than 80%). This paper presents a new Coriolis-based two phase flow meter (TPFM) that uses an upstream inline flow conditioner which separates liquid (i.e. water in this paper) from gas. Each of the gas dominant phase and liquid dominant phase are carried by two outlets, namely gas and liquid outlets respectively. A Coriolis flow meter and an actuated valve are placed in each outlet to measure and regulate the GVF that passes in each line. A new measurement algorithm based on a multistage artificial neural network (ANN) and which explores the physical model of the Coriolis flow meter is also suggested. This latest combines the pressure-volume-temperature (PVT) and bubble theory models to estimate the amount of gas (respectively liquid) dissolved in the liquid phase (respectively gas phase). Experimental results that were conducted on a multiphase flow loop reveals that for the whole GVF range (i.e. 0 to 100% GVF), the absolute value of the relative error on both the mass flow rate and density does not exceed 2.5%. This suggests that the proposed TPFM can be considered as a new non-hazardous alternative for accurate two phase flow measurement.

Preservation of lateral pressure disequilibrium during the uplift of shale reservoirs

A pressure gradient increase from normal pressure in oil zones to overpressure in dry gas zones indicates a lateral disequilibrium of pore pressure in many shale reservoirs. In this work, conditions for the preservation of the lateral pressure disequilibrium during uplift and erosion are investigated. Numerical simulations were conducted by coupling pressure–volume–temperature (PVT) and fluid dynamic calculations. Results show that temperature decrease and pore volume expansion during erosion tends to increase the pressure gradient in the gas or condensate zone and tends to decrease the pressure gradient in the black oil zone; therefore, the PVT effect tends to enhance lateral pressure disequilibrium during erosion. Low permeability is crucial for the preservation of the lateral pressure disequilibrium. The persistence of disequilibrium over geological time (tens of millions of years) requires extremely small vertical permeability (sub-picodarcy range) and horizontal permeability (10 nd or even lower). The horizontal permeability is 10–100 times smaller than laboratory measurements on shale plugs, indicating a discontinuity of laminations and fractures within a shale formation.

Thermoelastic Properties of K0.7Na0.3AlSi3O8 Hollandite and NaAlSi2O6 Jadeite: Implication for the Fate of the Subducted Continental Crust in the Deep Mantle

The thermoelastic properties of K0.7Na0.3AlSi3O8 hollandite and NaAlSi2O6 jadeite, synthesized from a (K, Na)-felspar (microcline), were investigated by a combination of in situ energy dispersive synchrotron X-ray radiation and multi-anvil techniques at high pressure (P) and temperature (T) up to 21 GPa and 1700 K. The second-order phase transformation was found to occur in hollandite at ~16 GPa from tetragonal I/4m (hollandite-I) to monoclinic I2/m (hollandite-II), which confirms the previous report that the incorporation of Na in the hollandite structure decreases the transformation pressure. Fitting the pressure–volume–temperature data to the Birch–Murnaghan equation of state yielded estimates of the thermoelastic parameters for jadeite as well as the K0.7Na0.3AlSi3O8 hollandite-I and -II phases, which indicate that the incorporation of Na is likely to decrease the bulk moduli of both hollandite phases. The obtained thermoelastic parameters were combined with those of other mantle minerals reported previously to estimate the density of continental materials along an average mantle geotherm. Based on our results, continental crust and sediment become, respectively, 11% and 15% denser than the pyrolitic mantle at pressure >10 GPa, suggesting that once pulled down to the critical depth of ~300 km, the continental portions of the slab can subduct further into the deep mantle, down to the lowermost part of the mantle transition region.