The Effect of Relative Permeability Hysteresis on the Design of an Optimal Water-Alternating-Gas (WAG) Process

2021 ◽  
pp. 1-21
Author(s):  
M. Kowsari ◽  
L. A. James ◽  
R. D. Haynes
Keyword(s):  
Relative Permeability ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Latin Hypercube Sampling ◽  
Recovery Factor ◽  
Rock Properties ◽  
Operating Parameters ◽  
Recovery Method ◽  
Water Alternating Gas ◽  
Hysteresis Modeling

Summary Water-alternating gas (WAG) as a tertiary recovery method is applied to oil reservoirs at a later stage of reservoir life to more or less success depending on field and operation. Uncertainty in WAG optimization has been shown to be dependent on several factors including reservoir characterization, WAG timing, and its operation. In this paper, we comprehensively explore WAG optimization in the context of WAG operating parameters and hysteresis, the first paper to explore both simultaneously. WAG operating parameters have been analyzed and optimized at both the core and field scale with a general conclusion that the timing, miscibility, WAG ratio, cycle time, and number of cycles play a varying role in the WAG optimization. Reservoir characterization has considered well configuration, oil type, rock properties, and hysteresis in relative permeability. Due to the cyclic nature of WAG and the dependency of the relative permeability on the saturation history, the relative permeability hysteresis modeling plays a key role in WAG performance whereby different hysteresis models will predict different results, as shown in literature. In this paper, we consider the choice of the hysteresis model and WAG operating parameters on WAG optimization. First, a sensitivity analysis is performed to evaluate the effect of hysteresis models (no hysteresis, Carlson, and Killough) on a large number of WAG development scenarios sampled by the Latin hypercube sampling method. Next, optimizations were conducted to compare and analyze the optimum recovery factor and corresponding optimal WAG operating parameters for various combinations of hysteresis models. The results of the study indicate that excluding hysteresis modeling from simulations would likely lead to a higher predicted produced volume of the nonwetting phases, that is, oil and gas, and a lower predicted produced volume of the wetting phase, that is, water. Also, the optimal recovery factor as well as the optimal WAG operating parameters can be significantly affected by the choice of the hysteresis models.

scholarly journals Ocena efektywności ekonomicznej procesu WAG na podstawie danych eksperymentalnych dla jednego z krajowych złóż ropy naftowej

Nafta-Gaz ◽  
2021 ◽  
Vol 77 (2) ◽  
pp. 75-81
Author(s):  
Mirosław Wojnicki ◽  
◽  
Jerzy Kuśnierczyk ◽  
Sławomir Szuflita ◽  
Marcin Warnecki ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Recovery Factor ◽  
Recovery Method ◽  
Waste Gas ◽  
Natural Gases ◽  
Acidic Gases ◽  
Water Alternating Gas ◽  
Dolomite Formation ◽  
Carbonate Formations

The challenge related to the need for an increase of the recovery factor concerns numerous mature, also domestic oilfields, including the most important ones – located in Main Dolomite formation. Satisfactory recovery factor can be ensured only through applying an effective enhanced oil recovery method (EOR). Water Alternating Gas (WAG), as one of the most effective EOR methods, has been tested in conditions characteristic for domestic deposits in carbonate formations. The results of experimental and simulation works carried out at the Oil and Gas Institute (INiG – PIB) indicate significant potential for the application of the WAG method in domestic conditions. An unquestionable advantage of the WAG method is the opportunity to utilize various types of gases, including flue/waste gas or low-energy natural gas. This issue deserves special attention because, as we know, the reduction in the emissions of gases involved in global warming is critical for the future of our planet. Their utilization in EOR methods, coupled with their safe storage in geological structures, constitute measures that reduce the environmental footprint of produced oil. In the article, based on the of experimental results, a simplified economic analysis of the utilization of four gas types in the form of acidic gases (carbon dioxide and its mixture with hydrogen sulfide) and natural gases (high and very high nitrogen content) in the WAG method was carried out. That allowed to identify the most economically optimal variants of the WAG method. The results showed that despite significantly lower effectiveness of nitrogen-rich natural gases in enhancing oil recovery (in the context of recovery factor), their application might be justified in economic terms. The selection of the optimal variant for enhancing recovery is strongly influenced by the assumed (current) cost of acquiring the injected media, and of course by the current (and forecasted) crude oil price.

Applied Process Simulation-Driven Oil and Gas Separation Plant Optimization using Surrogate Modeling and Evolutionary Algorithms

2019 ◽  
Author(s):  
Anders Andreasen
Keyword(s):  
Evolutionary Algorithms ◽  
Gas Separation ◽  
Oil And Gas ◽  
Optimal Solution ◽  
Computer Experiment ◽  
Latin Hypercube Sampling ◽  
Surrogate Models ◽  
Inlet Temperature ◽  
Separation Plant ◽  
Separation Stage

In this article the optimization of a realistic oil and gas separation plant has been studied. Two different fluids are investigated and compared in terms of the optimization potential. Using Design of Computer Experiment (DACE) via Latin Hypercube Sampling (LHS) and rigorous process simulations, surrogate models using Kriging have been established for selected model responses. The surrogate models are used in combination with a variety of different evolutionary algorithms for optimizing the operating profit, mainly by maximizing the recoverable oil production. A total of 10 variables representing pressure and temperature various key places in the separation plant are optimized to maximize the operational profit. The optimization is bounded in the variables and a constraint function is included to ensure that the optimal solution allows export of oil with an RVP < 12 psia. The main finding is that, while a high pressure is preferred in the first separation stage, apparently a single optimal setting for the pressure in downstream separators does not appear to exist. In the second stage separator apparently two different, yet equally optimal, settings are revealed. In the third and final separation stage a correlation between the separator pressure and the applied inlet temperature exists, where different combinations of pressure and temperature yields equally optimal results.<br>

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

A Novel Pore-Scale Thermal-Fracture-Acidizing Model With Heterogeneous Rock Properties

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 280-292 ◽  
Author(s):  
John Lyons ◽  
Hadi Nasrabadi ◽  
Hisham A. Nasr-El-Din
Keyword(s):  
Mass Transfer ◽  
Reactive Transport ◽  
Reaction Rate ◽  
Oil And Gas ◽  
Injection Rate ◽  
Rock Properties ◽  
Thermal Fracture ◽  
Pore Scale ◽  
Heterogeneous Rock ◽  
Acid Reaction

Summary Fracture acidizing is a well-stimulation technique used to improve the productivity of low-permeability reservoirs and to bypass deep formation damage. The reaction of injected acid with the rock matrix forms etched channels through which oil and gas can then flow upon production. The properties of these etched channels depend on the acid-injection rate, temperature, reaction chemistry, mass-transport properties, and formation mineralogy. As the acid enters the formation, it increases in temperature by heat exchange with the formation and the heat generated by acid reaction with the rock. Thus, the reaction rate, viscosity, and mass transfer of acid inside the fracture also increase. In this study, a new thermal-fracture-acidizing model is presented that uses the lattice Boltzmann method to simulate reactive transport. This method incorporates both accurate hydrodynamics and reaction kinetics at the solid/liquid interface. The temperature update is performed by use of a finite-difference technique. Furthermore, heterogeneity in rock properties (e.g., porosity, permeability, and reaction rate) is included. The result is a model that can accurately simulate realistic fracture geometries and rock properties at the pore scale and that can predict the geometry of the fracture after acidizing. Three thermal-fracture-acidizing simulations are presented here, involving injection of 15 and 28 wt% of hydrochloric acid into a calcite fracture. The results clearly show an increase in the overall fracture dissolution because of the addition of temperature effects (increasing the acid-reaction and mass-transfer rates). It has also been found that by introducing mineral heterogeneity, preferential dissolution leads to the creation of uneven etching across the fracture surfaces, indicating channel formation.

scholarly journals Reservoir characterization and by-passed pay analysis of philus field in Niger delta, Nigeria

2016 ◽  
Vol 4 (2) ◽  
pp. 28 ◽  
Author(s):  
Sunmonu Ayobami ◽  
Adabanija Adedapo ◽  
Adagunodo Aanuoluwa ◽  
Adeniji Ayokunnu
Keyword(s):  
Niger Delta ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Petroleum Industry ◽  
Volumetric Analysis ◽  
Vital Role ◽  
Oil And Gas Exploration ◽  
The Past ◽  
Stock Tank ◽  
Original Oil In Place

Hydrocarbon resources have become the most essential commodity contributing to any nation’s growth and development in the recent years. For the past decades now, the quest for hydrocarbon resources has been increasing in an arithmetic rate that its supply can no longer meets the demand for its consumption today. In petroleum industry, seismic and well log analyses play a vital role in oil and gas exploration and formation evaluation. This study is aimed to effectively characterize the reservoirs and analyze the by-passed pay in Philus Field, Niger-Delta, Nigeria in order to look into the economic viability and profitability of the volume of oil in the identified reservoir(s). The faults in the study area trend in NW-SE direction and dip towards the south. Seven reservoirs were mapped on Philus field. A discovery trap and a by-passed (new prospect) trap were mapped out on the field. The petrophysical analysis showed that porosity of Philus field was 0.24. The volumetric analysis showed that the Stock Tank Original Oil in Place of discovery trap (Philus field) ranged from 1.6 to 43.1 Mbbl while that of new prospect trap ranged from 18.1 to 211.3 Mbbl. It is recommended that the oil reserve of Philus field needs to be recalculated.

scholarly journals Predictive Modelling of Wellhead Corrosion due to Operating Conditions: A Field Data Approach

2012 ◽  
Vol 2012 ◽  
pp. 1-8 ◽  
Author(s):  
Chinedu I. Ossai
Keyword(s):  
Corrosion Rate ◽  
Field Data ◽  
Oil And Gas ◽  
Multiple Linear Regression Model ◽  
Predictive Modelling ◽  
Operating Conditions ◽  
Experimental Results ◽  
Operating Parameters ◽  
Oil And Gas Fields ◽  
The Impact

The flow of crude oil, water, and gas from the reservoirs through the wellheads results in its deterioration. This deterioration which is due to the impact of turbulence, corrosion, and erosion significantly reduces the integrity of the wellheads. Effectively managing the wellheads, therefore, requires the knowledge of the extent to which these factors contribute to its degradation. In this paper, the contribution of some operating parameters (temperature, CO2 partial pressure, flow rate, and pH) on the corrosion rate of oil and gas wellheads was studied. Field data from onshore oil and gas fields were analysed with multiple linear regression model to determine the dependency of the corrosion rate on the operating parameters. ANOVA, value test, and multiple regression coefficients were used in the statistical analysis of the results, while in previous experimental results, de Waard-Milliams models and de Waard-Lotz model were used to validate the modelled wellhead corrosion rates. The study shows that the operating parameters contribute to about 26% of the wellhead corrosion rate. The predicted corrosion models also showed a good agreement with the field data and the de Waard-Lotz models but mixed results with the experimental results and the de Waard-Milliams models.

Core Effective and Relative Permeability Measurements for Conventional and Unconventional Reservoirs by Saturation Monitoring in High Frequency 3d Gradient NMR

2021 ◽  
Author(s):  
Brian Chin ◽  
Safdar Ali ◽  
Ashish Mathur ◽  
Colton Barnes ◽  
William Von Gonten
Keyword(s):  
Relative Permeability ◽  
Oil And Gas ◽  
Spontaneous Imbibition ◽  
Tuning Parameter ◽  
Core Flooding ◽  
Hydrocarbon Gases ◽  
Flowing Fluid ◽  
The Core ◽  
Difficult Time ◽  
Saturation Front

Abstract A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (&lt; 10 %) and ultra-low permeabilities (&lt; 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates. Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer. The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon signals in the core plug during the entire process. The scanning times are also reduced by orders of magnitude, thereby allowing for more scans to properly capture the saturation front and changes in saturation. Simultaneously, the fluid flowrates and pressures are recorded in order to compute permeability values. The setup is rated to 10,000 psi confining pressures, 9000 psi of pore pressure and a working temperature of up to 100 C. Flowrates as low as 0.00001 cc/min can be recorded. These tests have been done with brine, dead and live crudes, and hydrocarbon gases. The measured relative permeability values have been used successfully in both simulation and production modelling studies in various reservoirs worldwide.

Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia

2021 ◽  
Author(s):  
Fadzlin Hasani Kasim ◽  
Budi Priyatna Kantaatmadja ◽  
Wan Nur Wan M Zainudin ◽  
Amita Ali ◽  
Hasnol Hady Ismail ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Visual Analysis ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Hydrocarbon Potential ◽  
Lower Grade ◽  
Reservoir Properties ◽  
Reservoir Evaluation ◽  
Porosity And Permeability

Abstract Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

A Revised Gassmann Fluid Replacement Model Based on Neutron-Density Logs in Shaly Sandstone Reservoirs

2021 ◽  
pp. 1-13
Author(s):  
Shantanu Chakraborty ◽  
Samit Mondal ◽  
Rima Chatterjee
Keyword(s):  
Oil And Gas ◽  
Reservoir Characterization ◽  
Rock Physics ◽  
Oil And Gas Industry ◽  
Effective Porosity ◽  
Fluid Replacement ◽  
Neutron Density ◽  
Gas Industry ◽  
Sandstone Reservoirs ◽  
Shaly Sandstone

Summary Fluid-replacement modeling (FRM) is a fundamental step in rock physics scenario modeling. The results help to conduct forward modeling for prediction of seismic signatures. Further, the analysis of the results improves the accuracy of quantitative interpretation and leads to an updated reservoir characterization. While modeling for different possible reservoir pore fluid scenarios, the quality of the results largely depends on the accuracy of the FRM. Gassmann (1951)fluid-replacement modeling (GFRM) is one of the widely adopted methods across the oil and gas industry. However, the Gassmann method assumes the reservoir as clean sandstone with connected pores. This causes Gassmann fluid-replacement results to overestimate the fluid effect in shaly sandstones. This study uses neutron and density logs to correct the overestimated results in shaly sandstone reservoirs. Due to the nature of these recordings, both of these log readings have close dependencies on the presence of shale. When the logs are plotted in a justified scale, the differences between the logs provide an accurate measurement of shaliness within the reservoir. The study has formulated a weight factor using the logs, which has further been used to scale the overestimated Gassmann-modeled fluid effect. The results of the revised method are independent of type of clay presence and associated effective porosity. Moreover, the corrected FRM results from the revised Gassmann method shows good agreement with rock physical interpretation of shaly sandstone reservoirs.

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