The matrix blocks in fractured reservoirs are the primary storage of hydrocarbons, so matrix-fracture transfer mechanisms are of crucial importance in recovery from fractured reservoirs. During gas injection into fractured reservoirs, fractures are filled with injected gas while matrix blocks contain the reservoir fluid. In this condition due to compositional difference between the gas in fractures and the fluid in matrix, diffusive exchanges of components between matrix and fracture may have significant contribution on matrix oil recovery in addition to gravity drainage or other transfer mechanisms.
In this work, to evaluate the significance of molecular diffusion, the laboratory experiment of "Gas Injection into Fractured cores?? is simulated using a compositional model and this model is used to run several experiments which help in understanding the way that each recovery mechanism acts. The advantage of running simulation in core scale is that in this way there is the possibility of using small grid size which significantly reduces the issues of numerical dispersion. And more over the existing experimental data can be used for model adjustment. In the experimental works the procedure is to place a core sample into a core holder in such a way that the annulus space between the core boundary and the core holder is very small. This annulus space is representative of the fracture surrounding the matrix blocks in the reservoir. Then after using special techniques the core is saturated with the representative reservoir oil, and after this primary core initialization, gas is injected into the annulus and the amount of recovered oil is measured versus time.
This study reveals that, molecular diffusion acts like a catalyst and improves the recovery mechanism by enhancing the gas movement within matrix. At the prevalent conditions of this work, the main recovery mechanisms are the miscibility effects (Condensing or Vaporizing gas drives) that are enhanced by molecular diffusion. Sensitivity analysis done in this work reveals that significance and contribution of molecular diffusion in recovery changes with different parameters such as matrix permeability and porosity, gas composition, etc.
Fractured reservoirs contain a significant portion of the world's reserves, and Gas injection is a common recovery practice in these reservoirs and understanding the recovery mechanisms is of crucial importance for correct simulation of this process. This study shows, although significance of molecular diffusion changes with reservoir parameters, any way neglecting it in simulation studies will result in underestimation of gas injection efficiency.
The oil-water interfacial tension (IFT) is by all means important in capillary pressure estimation and fluid-fluid and fluid-rock interactions analysis. Observations from experimental data indicate that oil-water IFT is a function of pressure, temperature, and compositions of oil and water. A reliable correlation to estimate oil-water IFT is highly desire. Unfortunately to our best knowledge no correlation that uses the compositions of oil and water as inputs is available. Our work is to fill this gap.
In this research, we collected data from former studies and investigations and developed a correlation for oil-water IFT. In the proposed correlation oil-water IFT is a function of system pressure, temperature, and compositions of oil and water. Error analysis was conducted to check the accuracy of the equation by comparing the calculated values with the experimental data. The results indicated that the new correlation predicts reliable oil-water IFTs. Our correlation calculates the oil-water IFT from system pressure, temperature, and compositions of oil and water. It addresses the effect of composition of oil on IFT, which is not presented in existing correlations. Therefore it can not only be applied in the calculation of capillary pressure in the compositional simulation, but also be used in daily petroleum engineering calculation such as waterflooding analysis.
Significant advances have been made in formation testing since the introduction of wireline pumpout testers (WLPT), particularly with respect to downhole fluid compositional measurements. Optical sensors and the use of spectroscopic methods have been developed to improve sample quality and minimize sampling time in downhole environments. As a laboratory technique, spectroscopy is a ubiquitous and powerful technology that has been used worldwide for decades to measure the physical and chemical properties of many materials, including petroleum, geological, and hydrological samples. However, laboratory-grade, high-resolution spectrometers are incompatible with the hostile environments encountered downhole, at wellheads, and on pipelines. Only limited resolution techniques are available for the rugged conditions of the oil field. This paper introduces a new optical technology that can provide high-resolution, laboratory-quality analyses in harsh oilfield environments.
A new technology for optical sensing, multivariate optical computing (MOC), has been developed and is a non-spectroscopic technique. This new sensing method uses an integrated computation element (ICE) to combine the power and accuracy of high-resolution, laboratory-quality spectrometers with the ruggedness and simplicity of photometers. Many modern sensors typically merge the sensor with the electronics on an integrated computing chip to perform complex computations, resulting in an elegant yet simplistic design. Now, optical sensing using ICE features an analogue optical computation device to provide a direct, simple, and powerful mathematical computation on the optical information, completely within the optical domain. Because the entire optical range of interest is used without dispersing the light spectrum, the measurements are obtained instantly and rival laboratory-quality results.
A proof of concept MOC with ICE has been demonstrated, logging more than 7,000 hours, in nearly continuous use for 14 months. Oils with gravities ranging from 14 to 65°API have been measured in downhole environments that range from 3,000 to 20,000 psi, and from 150 to 350°F. Hydrocarbon composition measurements, including saturates, aromatics, resins, asphaltenes, methane, and ethane, have been demonstrated using the MOC configuration. As compositional calculations therein, GOR and density are validated to within 14 scf/bbl and 1%, respectively. The paper discusses the details of the new ICE-based sensor and describes its adaptations to downhole applications.
Arnaout, Arghad (TDE Thonhauser Data Engineering GmbH) | Thonhauser, Gerhard (Montanuniversitat Leoben) | Esmael, Bilal (Montanuniversitat Leoben) | Fruhwirth, Rudolf Konrad (TDE Thonhauser Data Engineering GmbH)
Detection of oilwell drilling operations is an important step for drilling process optimization. If drilling operations are classified accurately, detailed performance reports not only on drilling crews but also on drilling rigs can be produced. Using such reports, the management can evaluate the drilling work more precisely from performance point of view.
Mud-logging systems of modern drilling rigs provide numerous sensors data. Those sensors measurements are considered as indicators to monitor different states of drilling process. Usually real-time measurements of the following sensors data are available as surface measurements: hookload, block position, flow rates, pump pressure, borehole and bit depth, RPM, torque, rate of penetration and weight on bit.
In this work, collected sensors measurements from mud-logging systems are used to detect different drilling operations. Detailed data analysis shows that the surface sensors measurements can be considered as a main source of information about drilling operations. For this purpose, a mathematical model based on polynomials approximation is constructed to interpolate sensors data measurements.
Discrete polynomial moments are used as a tool to extract specific features (moments) from drilling sensors data. Then we use these moments for each drilling operation as pattern descriptor to classify similar operations in drilling time series. The extracted polynomial moments describe trends of sensors data and behavior of rig's sub-systems (Rotation System, Circulation System, and Hoisting System). Furthermore, this paper suggests a method on how to build patterns base and how to recognize and classify drilling operations once sensors data received from mud-logging system. Drilling experts compare the results to manually classified operations and the results show high accuracy.
In work principles of modeling of interaction of sea gravitational oil andgas extraction platforms with the soil basis are presented. The seabed level ispresented by the non-uniform model consisting of seven layers of soils, satedwith a liquid. Approximate calculation of interaction platform Prirazlomnayawith a sea-bottom is resulted.
Efficient and robust phase equilibrium computation has become a prerequisite for successful large-scale compositional reservoir simulation. When knowledge of the number of phases is not available, the ideal strategy for phase-split calculation is the use of stability testing. Stability testing not only establishes whether a given state is stable, but also provides good initial guess for phase-split calculation. In this research, we present a general strategy for two- and three-phase split calculations based on reliable stability testing. Our strategy includes the introduction of systematic initialization of stability testing particularly for liquid/liquid and vapor/liquid/liquid equilibria. Powerful features of the strategy are extensively tested by examples including calculation of complicated phase envelopes of hydrocarbon fluids mixed with CO2 in single-, two-, and three-phase regions.
To satisfy the growing global gas demand more reservoirs with sour contaminants (up to 40% of H2S and significant CO2) will be developed. Worldwide more than 1600 TCF of Sour Gas is anticipated. Shell has more than 60 years of experience in sour gas processing, ranging from the first facilities installed in Jumping Pound, Canada, to recent projects under development in Kazakhstan and Oman. This paper will describe a number of challenges and opportunities associated with development of "sour?? projects.
The fact that H2S is lethal at low concentrations and highly corrosive in the presence of CO2 and/or (salty) water indicates that safety is a main driver in these projects. It is of crucial importance that the H2S is contained and that plant integrity is assured through tightly controlled maintenance programs.
Product specifications for produced gas and hydrocarbon liquids are ever tightening and legislation on emissions are becoming more stringent. Deep removal of H2S and other sulphur components like mercaptans and carbonyl sulphide is required. This increases the complexity and therefore cost of the sour gas processing facilities, which must compete with production from sweet gas in the region/country or alternatives such as LNG import. Technology innovation as well as smart integration of technologies are essential for the cost effective development of sour gas assets ensuring all specifications and emission requirements are met. Several examples of these technology innovations will be presented in this paper.
The paper presents a C7+ characterization procedure for the PC-SAFT equation of state. The characterization procedure was applied to model both routine and EOR PVT for a Middle East reservoir fluid. The injection gas contained 60 mole% of CO2. No other parameter adjustment was needed than to determine the optimum binary interaction parameters for CO2. Among the data matched was a liquid-liquid critical point on a swelling curve for a CO2 mol% of 43. The PC-SAFT simulation results suggest that the fluid for this CO2 concentration has two critical points. The one at the lower temperature agrees with the critical point found in the swelling test. The study shows that the potential of the PC-SAFT equation of state in the oil industry is not limited to modeling of asphaltene precipitation and other specialized applications. Extensive routine and EOR PVT data including a minimum miscibility pressure has been modeled using the PC-SAFT equation. Unlike cubic equations, a volume correction does not have to be applied to match liquid densities.
A method is proposed for reproducing early gas breakthrough when performing full-field compositional simulation of gas injection in under-saturated oil. It was developed by solving the successive problems encountered on a real heterogeneous field with a gas injection pilot
The first problem was to correctly model transport in this large carbonate field using a coarse grid. It was dealt with by using alpha-factors.
The second difficulty was related to the strong under-saturation of the oil: all injected gas dissolves until saturation pressure reaches actual block pressure. In practice, this means that gas will appear too late in the simulation. This is easily avoidable in black-oil simulation, but compositional simulators will usually not allow to circumvent the equation of state. We found out that correcting the critical transition allowed to speed up the appearance of the gas phase.
A third difficulty was to history match the gas injection pilot without distorting the geological model. We thus wanted to reproduce the inherent instability of gas injection, which had not swept all layers homogeneously, as shown by time-lapse RST data. This problem was solved using an extra-capability of alpha-factors: stating that the transported fluid viscosity is lower than average grid-block viscosity, and integrating this new correction into the oil and gas alpha-factor table, allowed to successfully reproduce quick gas encroachment in permeable layers.
The fourth task of imposing a residual oil saturation Sorm was solved using the end-point of the alpha-factor table.
Thus we propose a method for correcting several effects simultaneously: acceleration of the light components, acceleration of the critical transition from volatile oil to gas condensate, viscosity correction to reproduce gas fingering, and slow-down of the heavy components in order to force residual oil saturation. To our knowledge, documentation of the second and third corrections is new. All four corrections being justified, we used them all in a composite alpha-factor table.
The Microemulsion phase behavior model based on oleic-aqueous-surfactant pseudo-phase equilibrium, commonly used in chemical flooding simulators, is coupled to Gas-Oil-Water phase equilibrium in our new four-fluid-phase, fully implicit In-House Research Reservoir Simulator (IHRRS). The method consists in splitting the equilibrium in two stages, where all the components other than surfactant are equilibrated first (e.g. using a black-oil, K-value or equation of state model), and the resulting Gas, Oil and Water phases are then lumped into pseudo-phases to be equilibrated using the Microemulsion model. This subdivision in stages is conceptual, and at each converged time-step the four phases (Gas, Oil, Water and Microemulsion, when simultaneously present) will be in equilibrium with each other.
The fluid properties (such as densities, viscosities and interfacial tensions) and rock-fluid properties (such as relative permeabilities), required in the transport equations, are evaluated with models from well-known industrial or academic simulators. Surfactant flooding being usually implemented as a tertiary recovery mechanism, on fields for which complete models that we do not wish to modify already exist, particular care is devoted to ensuring continuity of the physics at the onset of surfactant injection.
Our code is validated against a reference academic chemical flooding simulator, on 1D corefloods where the original hydrocarbons in place form a dead-Oil phase, possibly with free dry-Gas. Some numerical aspects of our implementation such as numerical dispersion versus time-step size and nonlinear convergence performance are also discussed. As an application example of our code where it is necessary to account for four phases in equilibrium, we consider a scenario where the chemical flood is preceded by a vaporizing Gas drive.
Surfactant flooding, whose key principle is to improve pore-level sweep efficiency by reducing the interfacial tension between injected Water and reservoir Oil (Lake, 1989), recently received renewed attention due to the perspective of long-lasting high oil prices. Meaningful simulation of surfactant flooding is challenging, in particular because when the surfactant concentration in the Water phase goes above a Critical Micelle Concentration (CMC), Water and Oil become mutually soluble in a proportion mainly determined by water salinity CS. Three different phase environments should be considered (Nelson & Pope, 1978; Lake, 1989). Near the so-called optimal salinity CSOP the surfactant is similarly hydrophilic and lipophilic, and a middle phase called Microemulsion forms, containing the surfactant in excess of the CMC as well as dispersed oil and water (Winsor III environment). This is the best performing regime because interfacial tensions between Water and Microemulsion and between Microemulsion and Oil are then extremely low. At low salinity the surfactant is typically hydrophilic, hence only Oil and a Microemulsion phase containing dispersed oil coexist (Winsor II- environment); on the contrary at high salinity the surfactant is typically lipophilic, hence only Water and a Microemulsion phase containing dispersed water coexist (Winsor II+ environment).