Carbonate Oil Reservoirs Research Articles

Pore matrix dissolution in carbonates: An in-situ experimental investigation of carbonated water injection

Carbonate rock dissolution during the reactive transport of carbon dioxide (CO2)-enriched brine has been studied extensively in the context of carbon storage in saline aquifers. However, there is limited knowledge of CO2-induced reactive transport in multiphase systems (containing oil and brine), which is more relevant to carbon sequestration in depleted oil reservoirs. In this work, we uncover the pore-scale dynamics of fluid flow and rock dissolution during carbonated water injection (CWI) in hydrophilic porous media containing two fluid phases (oil and brine). We combine novel core flooding and high-resolution imaging techniques to visualize and characterize changes in fluid occupancy and pore morphology. It is observed that the sequence of flow and transport in two-phase systems involves a pre-dissolution period, where CWI induces the displacement of waterflood-trapped oil, and a dissolution period typified by channel flow. Improved oil recovery during pre-dissolution emanates from an oil swelling mechanism that drives reconnection and mobilization of trapped oil globules. Additionally, CO2 is stored in both oil and carbonated water. Channel flow during dissolution results in the formation of wormholes with two distinct dissolution patterns. The first is a conical wormhole at lower injection rates where diffusion rates are significant. The second is a dominant wormhole at higher injection rates where advection dominates the transport of reactive species to the flow boundaries. We find that the oil displacement efficiency during dissolution is significantly lower than pre-dissolution levels and is dependent on the wormhole pattern, with dominant wormholes providing a high-permeability and high-velocity flow path for trapped oil movement. Therefore, unlike the injectivity losses that originate from salt precipitation during direct CO2 injection, CWI in depleted carbonate oil reservoirs enhances the injectivity of injection wells allowing for an energy efficient CO2 storage.

Salt precipitation in carbonates during supercritical CO2 injection: A pore-scale experimental investigation of the effects of wettability and heterogeneity

Salt precipitation in near-wellbore regions of subsurface reservoirs is a significant phenomenon that may occur during carbon dioxide (CO2) injection for carbon sequestration and enhanced oil recovery. It induces pore plugging, which causes reductions in porosity and permeability and hence well injectivity. Previous research in this area focused predominantly on salt precipitation in fully brine-saturated media, such as those found in deep saline aquifers. However, studies on salt precipitation in hydrocarbon reservoirs where brine and oil coexist are rare, particularly at the pore scale. In this study, we elucidate the occurrence and dynamics of salt precipitation at the pore-scale during supercritical CO2 injection into depleted carbonate and sandstone oil reservoirs at elevated temperature and pressure conditions. Specifically, we examine the influence of wettability and morphological heterogeneity on salt precipitation evolution and dynamics. Investigations on the influence of wettability reveal that the time required for the initiation of precipitation is shorter for an intermediate-wet carbonate compared to that for a weakly oil-wet carbonate. Relatively higher amounts of salt deposits are formed in the more hydrophilic (intermediate-wet) carbonate, leading to an intensification of porosity reduction in this rock. In addition, the presence of oil within the pore space does not hinder the precipitation process but suppresses the reverse flow of solutes toward the evaporation front, thereby creating localized precipitation at the front. The level of heterogeneity affects the precipitation initiation and its duration as well as the amount of precipitates formed, with lower salt saturations encountered in the less heterogeneous sandstone compared to the more heterogeneous carbonate. Heterogeneity also influences the salt cluster size distribution within pore elements such that, for the same wettability state, medium-sized clusters dominate in sandstone, while large clusters are the main contributors to the total salt volume in the more heterogeneous carbonate. This study forms a fundamental basis for the prediction of salt precipitation during three-phase flow processes induced by supercritical CO2 injection into porous media containing high-salinity brine and oil.

Applicability of methane foam stabilized via Nanoparticles for enhanced oil recovery from carbonate porous media at various temperatures

Over the 60 years of primary production from carbonate oil reservoirs in the middle east, approximately 30 % of initial oil in place has been recovered in this area and the rest requires appropriate enhanced oil recovery (EOR) methods for production. Since there are huge gas resources in this area, applications of gas-based EOR methods especially those with methane gas should be the top priority. Therefore, the objective of this study is to experimentally determine and compare the influences of stabled methane foams via aluminum oxide (Al2O3), titanium dioxide (TiO2), zinc oxide (ZnO), and silica (SiO2) nanoparticles (NPs) for EOR from a limestone porous medium at 25, 50 and 85 °C. For this goal, 0.1 wt% Sodium dodecyl sulfate (SDS) was dissolved in NaCl solution 0.5 wt% and then the above-mentioned nanopowders at concentrations from 0.005 to 0.1 wt% were added. Methane at a flow rate of 250 ml/min was injected into the suspensions and the stability of produced foams was defined by measuring the half-life time. Once an optimum concentration of each NP type was found, that foam was chosen to be flooded to the limestone porous medium for EOR purposes. The optimum NP content in terms of foam stability at all temperatures was achieved at 0.01 wt% for SiO2 and ZnO NPs and 0.05 wt% for TiO2 and Al2O3 NPs. Half-life time values of methane foams in the presence of NPs were averagely found to be 16 and 3 times higher than those of the base foam at 25 and 85 °C, respectively. TiO2, Al2O3, ZnO, and SiO2 NPs in order were the best additives for foam stability at all temperatures. In addition, at 85 °C, the incremental oil recovery amounts from the limestone porous medium by TiO2, Al2O3, ZnO, and SiO2 NPs-methane foams were achieved 20.4, 18.9, 17.6, and 16.1 %, respectively, which were 6 to 10 % higher than foam flood tests without NPs. Overall, it can be concluded that NPs methane foam flooding is a promising method for EOR from carbonate porous media in the middle east area.

Characteristics and main controlling factors of dolomite reservoirs in the Upper Cambrian Sanshanzi Formation, eastern Ordos Basin, China

The Cambrian system in the Ordos Basin has a similar development degree of carbonate strata to that in the Sichuan and the Tarim Basins; however, no significant oil and gas breakthroughs similar to those in the latter two basins have been made in the Ordos Basin yet, and the characteristics, genesis, and differences in the reservoir need to be explored. Field outcrop observations reveal that the oil and gas shows are common in the Upper Cambrian Sanshanzi Formation in the eastern Ordos Basin, indicating important oil and gas exploration potential. Analysis of the characteristics and genesis of dolomite reservoirs can greatly support the exploration and development of the Cambrian carbonate oil reservoirs in the Ordos Basin. Based on the field outcrop observations and comprehensive laboratory tests and analyses, the reservoir characteristics and main control factors are systematically discussed. This study reveals that the reservoir lithology mainly comprises crystalline dolomite, from fine crystalline dolomite to coarse crystalline dolomite; this results in reservoirs with low porosity, extreme-low porosity, and ultralow permeability dominated by intergranular denudation, caves, and microfractures. They can be further divided into two types of reservoirs: type I reservoirs that have low porosity, ultralow permeability, and medium pore-throat radii, and type II reservoirs that have extreme-low porosity, ultralow permeability, and small pore-throat radii. The physical properties of fine-medium crystalline and medium crystalline dolomite reservoirs are slightly better, and the throats tend to be larger with increasing grain size. The reservoirs have not experienced deep burial processes; dolomitization mainly occurs in the marine-sourced fluid environment with weak oxidation and weak reduction, influenced by the atmospheric fresh water and thermal fluid transformation during the late period to some extent, whereas the hydrocarbons mainly charged during the late period. The crystalline dolomite in residual grains superimposes the denudation and cataclasis in the epigenetic karst stage that are the main controlling factors of the reservoirs. The crystalline cataclasis of dolomite can aid in the formation and reconstruction of the reservoirs. The spatial and temporal distribution laws of the reservoirs and key formation periods need to be studied further.

Oil pyrolysis with carbonate minerals: Implications for the thermal stability of deep crude oil

Gold-tube experiments on oil, oil and dolomite, and oil and calcite were conducted to analyse the thermal stability of liquid hydrocarbons in carbonate reservoirs. The pyrolysates were geochemically characterized by gas chromatography and gas chromatography-isotope ratio mass spectrometer. The experimental results show that temperature is the main controlling factor; however, the influence of inorganic minerals cannot be ignored during oil cracking. Dolomite and calcite have been observed to inhibit the generation of methane to some extent, wherein the methane yields were reduced by 42.73 and 33.86 ml/g, respectively. Moreover, carbonate minerals increase the average activation energy of C1-5 generation, leading to an increase in the thermal stability of crude oil. Carbon isotope fractionation of gaseous hydrocarbons during crude oil cracking showed that carbonate minerals promoted methane carbon isotope rollover at EasyRo <1.75%. The extrapolation of kinetic parameters at a constant heating rate of 2 °C/Ma indicated that carbonate minerals will increase the liquid hydrocarbon preservation threshold temperature by 2–10 °C at the same conversion of C1-5. The calculated maximum depth corresponding to crude oil in carbonate reservoirs maintaining the liquid phase (51% oil cracking) can reach 10,000 m. Therefore, the presence of carbonate minerals needs to be considered during the geochemical evaluation indicators to analyse the potential of gas generation during crude oil cracking, the evolution of carbon isotope composition, and the prediction of hydrocarbon phase behaviour.

Artificial neural network, support vector machine, decision tree, random forest, and committee machine intelligent system help to improve performance prediction of low salinity water injection in carbonate oil reservoirs

A large body of experimental research supports the effectiveness of Low Salinity Water Injection (LSWI) for enhanced oil recovery from carbonate reservoirs in laboratory scale. Development of robust predictive smart models connecting effective parameters controlling this complex process to Final Recovery Factor (RFf), as the target parameter, is of a paramount importance. The main objective of this research work is to develop intelligent models using Artificial Neural Network (ANN), Support Vector Machine (SVM), Decision Tree (DT), Random Forest (RF), and Committee Machine Intelligent System (CMIS) to forecast performance of LSWI in carbonates using experimental data reported in the literature. Random Search (RS) and Anneal (AL) algorithms were used for optimization of hyperparameters. After data collection from 47 reliable coreflooding studies (582 data points), a rigorous data preprocessing was conducted to ensure quality of the database. Features selection process was used to determine the main parameters controlling LSWI performance in carbonates: brine permeability (Kb), core diameter (d), porosity (Φ), and residual water saturation (Swi) of the core, HCO3− concentration, and salinity (S) of the connate brine, the salinity (S) of the injected brine, and initial recovery factor (RFi) which were used for development of the models. We considered initial oil recovery (RFi) in this research work, which was not considered in previous works reported in the literature. The applicability domain analysis showed that training and testing response outliers were zero and 9, respectively, indicating acceptable quality of the database. Performance of the developed smart models was analyzed and compared using statistical and graphical error analysis methods. The best performance was obtained for the RF model with Root Mean Square Error (RMSE) of 2.497 and 5.757 for training and testing datasets, respectively, which exhibits a very good agreement with the experimental data.

Reservoir Properties Alteration in Carbonate Rocks after In-Situ Combustion

Summary This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.

Microbial Enhanced Oil Recovery (MEOR) Surfactant from Pseudomonas aeruginosa isolated from Automobile Garage soil.

Abstract: Microbial enhanced oil recovery (MEOR), is gaining attention today for being environmentally friendly, economically attractive, demonstrating improvement in recovery of oil entrapped in porous media. It is considered to be more efficient than other EOR methods when applied to carbonate oil reservoirs. In the current study oil degrading bacteria was isolated from soil of automobile garage. The biosurfactant producing organism was screened and characterized. 16SrRNA sequence of the most potent bacterial strain suggests it to be belonging to the genus Pseudomonas and species aeruginosa. The biosurfactant produced by the bacteria was detected as rhamnolipid with emulsification index of 69%, foaming of 57.69% and interfacial surface tension of 0.6 mN/m. The MEOR column assay revealed that the additional oil recovery for sand1 and sand2 was 62.142% and 52.173 respectively.

Substantiation of In Situ Water Shut-Off Technology in Carbonate Oil Reservoirs

The efficient development of carbonate oil deposits with excessive fissuring is a current challenge. Uneven and rapid well stream watering is considered as one of the factors that make the process of the development of carbon deposits more complicated. The purpose of the research is to diagnose and evaluate the mechanisms of well stream watering for carbon deposits and find applicable technology to prevent it. An overview of in situ water shut-off technologies was carried out. A description of the main materials used for water shut-off is presented, and selective methods are studied in more detail. A carbonate basin of an oil field is selected as the object of investigation. The geological and physical characteristics of this deposit are given. Analysis of possible causes and sources of water cut of the fluid is made according to the technique of K.S. Chan, under which the main reason for the watering of the well production is the breakthrough of formation and injection water through a system of highly permeable natural fractures and channels. Matrixes of applicability of in situ water shut-off technologies and polymer compositions are made. The composition based on carboxymethyl cellulose for in situ water shut-off is selected for the chosen deposit.

New insights into permeability determination by coupling Stoneley wave propagation and conventional petrophysical logs in carbonate oil reservoirs

The need to determine permeability at different stages of evaluation, completion, optimization of Enhanced Oil Recovery (EOR) operations, and reservoir modeling and management is reflected. Therefore, various methods with distinct efficiency for the evaluation of permeability have been proposed by engineers and petroleum geologists. The oil industry uses acoustic and Nuclear Magnetic Resonance (NMR) loggings extensively to determine permeability quantitatively. However, because the number of available NMR logs is not enough and there is a significant difficulty in their interpreting and evaluation, the use of acoustic logs to determine the permeability has become very important. Direct, continuous, and in-reservoir condition estimation of permeability is a unique feature of the Stoneley waves analysis as an acoustic technique. In this study, five intelligent mathematical methods, including Adaptive Network-Based Fuzzy Inference System (ANFIS), Least-Square Support Vector Machine (LSSVM), Radial Basis Function Neural Network (RBFNN), Multi-Layer Perceptron Neural Network (MLPNN), and Committee Machine Intelligent System (CMIS), have been performed for calculating permeability in terms of Stoneley and shear waves travel-time, effective porosity, bulk density and lithological data in one of the naturally-fractured and low-porosity carbonate reservoirs located in the Southwest of Iran. Intelligent models have been improved with three popular optimization algorithms, including Coupled Simulated Annealing (CSA), Particle Swarm Optimization (PSO), and Genetic Algorithm (GA). Among the developed models, the CMIS is the most accurate intelligent model for permeability forecast as compared to the core permeability data with a determination coefficient (R2) of 0.87 and an average absolute deviation (AAD) of 3.7. Comparing the CMIS method with the NMR techniques (i.e., Timur-Coates and Schlumberger-Doll-Research (SDR)), the superiority of the Stoneley method is demonstrated. With this model, diverse types of fractures in carbonate formations can be easily identified. As a result, it can be claimed that the models presented in this study are of great value to petrophysicists and petroleum engineers working on reservoir simulation and well completion.

Data-driven physics-informed interpolation evolution combining historical-predicted knowledge for remaining oil distribution prediction

The remaining oil distribution plays an important role in enhanced oil recovery (EOR), which directly guides the development of an oil reservoir in the middle and later stages. However, it is still challenging to accurately and efficiently characterize the distribution of remaining oil due to the complex reservoir geology. We propose a data-driven physics-informed interpolation evolution algorithm combining historical-predicted knowledge (DPIE-HPK) for the prediction of remaining oil distribution totally based on reservoir monitoring data. As a key step towards the remaining oil distribution, the production rates can be predicted as well. A physics-informed data supplement (PIDS) process is also presented to assist the DPIE-HPK algorithm. Both historical physics information and future information are used in the DPIE-HPK framework. The historical physical information is preprocessed by the PIDS, and future information is predicted by Long Short-Term Memory (LSTM) deep learning models. As a crucial interpolation evolution method, the Kriging method is also integrated into the framework to evolve the unknown spatial information. We test the DPIE-HPK framework for the prediction of the remaining oil distribution of a typical tight carbonate oil reservoir located in the Middle East. It is concluded that the DPIE-HPK framework is a fast, accurate and efficient intelligence tool for predicting the remaining oil distribution.

Stochastic modeling of fluid flow in the simulation and quantification of fracture initiation and propagation in the oil carbonate reservoirs during water injection

Water injection into oil carbonate reserves can lead to fracture initiation and propagation, which can be modeled using a stochastic fluid flow model. Crack initiation and propagation due to water injection are investigated using numerical simulations in a carbonate oil reservoir. An accurate, comprehensive 2D model of fracture propagation can be created using stochastic Brinkman optimal control with uncertain inputs. Because fluid movement determines the spread of the oil front, we observed that fracturing was distinct from the spread of oil. Fracture tip oil saturation correlates strongly with saturation early on, showing that pressured oil is mostly filling up the fractures. An oil-filled gap has formed between the crack’s oil front and the crack’s top, which is later filled by reservoir gas. Additionally, a substantial volume of oil is seeping from the reservoir. Because of the discrepancy between the fracture volume and the volume of water injected into the fracture, a simple assumption that the fracture is saturated with pressured oil in the reservoir cannot accurately calculate the fracture length. Water injection is a set of many failure processes in which pressure consistently drops when the failure occurs, but the fluctuation decreases as the fracture length increases, so we identify pressure fluctuation under constant water injection (for pushing oil in Enhanced Oil Recovery methods) to illustrate flow-geomechanical responses.

Scale, origin, and predictability of reservoir heterogeneities in shallow-marine carbonate sequences: A case from Cretaceous of Zagros, Iran

This study presents an integrated reservoir heterogeneity analysis of an Iranian carbonate oil reservoir (Sarvak Formation) in the Zagros region. Both static and dynamic aspects of reservoir heterogeneities are considered by integration of routine–special core data and geological attributes (i.e., depositional facies and textures, diagenetic alterations, pore types, and sequence stratigraphic positions). Core porosity and permeability, mercury injection capillary pressure, and scanning electron microscopy data are used along with the results of petrographic studies to define petrographic rock types, pore types, hydraulic flow units, and reservoir to non-reservoir (baffle or barrier) zones in the studied reservoir. Spatial facies distribution (facies variability) and development of disconformable surfaces (sequence boundaries) controlled the large-scale reservoir heterogeneities. On the other hand, variations in microscopic characteristics of depositional facies (i.e., textures and structures) and diagenetic features (e.g., intensity of dissolution, cementation and compaction) formed the small-scale reservoir heterogeneities. The best productive zones of this reservoir are meteorically-dissolved reef-talus and shoal facies, accumulated within the regressive systems tracts of third-order sequences. Intensively compacted and cemented facies formed the effective vertical barrier/baffle zones in this reservoir, especially within the transgressive systems tracts and around the maximum flooding surfaces. Results of this study revealed that the stratigraphic modified Lorenz plot (SMLP) is a useful tool for the discrimination of large-scale reservoir heterogeneities, while hydraulic flow units and Winland rock typing approaches are applicable for the identification of small-scale heterogeneities. This study indicated that the large-scale heterogeneities of carbonate reservoirs are predictable in a sequence stratigraphic framework, especially in the third-order scale. Such a heterogeneity model calibrated in the sequence stratigraphic framework provides a reliable basis for reservoir modeling of heterogeneous carbonate reservoirs in the field-to regional scales.

Fluid-rock interaction during low-salinity water flooding of North Sea chalks

The injection of low-salinity water into carbonate oil-reservoirs has been the subject of much interest as a potential method to enhance oil recovery (EOR). Low salinity water injection has been shown to alter the geochemical equilibrium in the reservoir, and consequentially potentially change the surface wettability of the reservoir rocks. Nevertheless, the geochemical reaction pathways during low salinity water flooding in carbonates remain poorly understood.In order to provide a more comprehensive insight into the geochemical reaction pathways, a series of batch and core-flooding experiments have been performed at 70 °C. The experiments made use of analogous and authentic reservoir material from the Danish North Sea oil reservoirs, and brines with chemical composition similar to the formation water and injection water available in offshore flooding operations.Results show that both mineral dissolution and the precipitation of new secondary phases can accurately describe the geochemical changes observed in the experimental effluents during the course of a low-salinity water core-flooding scenario.The dissolution of amorphous silica (SiO2) present in the chalk, and the precipitation of a Mg–Si clay mineral, identified here as sepiolite, are key reactions that take place during low-salinity water core-flooding in chalks. The suggested geochemical pathway was successfully fitted by a simplified geochemical simulation which can accurately describe the experimental observations.Surface reactions which take place during modified-salinity water flooding were put into perspective by quantifying their contribution to the overall effluent composition.

Experimental investigation and simulation for hybrid of nanocomposite and surfactant as EOR process in carbonate oil reservoirs

Numerous studies have been presented in the literature on the effect of the combination of nanoparticles and surfactants on enhanced oil recovery (EOR). In this study, we investigated the synergistic effect of synthesized Nanocomposite (ZnO@PAM) and surfactant on enhanced oil recovery by performing zeta potential (evaluation of chemicals stability in the aqueous phase), adsorption, wettability alteration (evaluation of the quantitative and qualitative wetness), and interfacial tension testes. In addition, to better understand how the fluid moves after chemicals flood in the porous medium, the Cartesian model was developed in CMG-STARS. Besides, this model is valid because of the history match of the oil recovery data, water cut data, and relative permeability curves. The Nanocomposite was physically synthesized from polyacrylamide polymers and zinc oxide nanoparticles under reflux conditions. The CMC surfactant point was obtained by examining various parameters (pH, density, electrical conductivity, and IFT). In the next step, we prepared nano-surfactant solutions (Nanocomposites with different concentrations of 100 ppm, 200 ppm, 500 ppm, and 1000 ppm + Surfactant (CMC)). By investigating the results of the adsorption and zeta potential tests, it was observed that the combinations of Surfactant and NCs have a positive effect on each other (increased nanoparticle stability and decreased surfactant adsorption on the carbonate rock surface). The Surfactant and Nano-Surfactant reduced the IFT from 29.16 to 0.176 (mN/m) and 1.354 (mN/m), respectively. In addition, the Surfactant at CMC and Nano-Surfactant (Surfactant (CMC) + NCs (500 ppm)) improve the contact angle in carbonate rock from 145.86 to 64° and 12.79°, respectively. After the core flooding by Surfactant and hybrid of NCs and Surfactant, we saw an increase of 17.94% and 30% in oil recovery compared to seawater floods, respectively. Furthermore, we observed the effect of mobility control and reduction of the fingering phenomenon after the flooding of chemicals by analyzing the simulated fluid distribution. By constructing the model in the core dimensions, we were able to get a good history matching from the laboratory data. Moreover, the mobility ratio after simultaneous flooding of NCs and surfactant compared to seawater decreased from 13.354 to 1.86, respectively. In addition, according to the fluid distribution pattern (one of the simulator outputs) the fingering phenomenon, was delayed after flooding the hybrid of NCs and surfactant. The positive effect of this type of chemical compound on mobility control and the fingering phenomenon has caused increased oil recovery. This study's findings can help to understand better how hybrid chemicals perform on improved oil recovery.

Impact of Integration of the Production Systems and Reservoir of a Benchmark Based on Carbonate Fields

AbstractIntegrating production system and reservoir is used in several studies of offshore oilfield development and management for improved production forecasts through more realistic boundary conditions. This study evaluates the influence of the parameters in a production strategy of a reference model (carbonate oil reservoir) on financial and production performance. We first considered nonintegrated system (NI) with the reservoir and fixed boundary conditions for well and gathering system. We then considered integrated system (I) with the variable boundary conditions for the wells and gathering system. Finally, we compared both systems. Our analysis involved several steps to define the best production strategy for both systems based on net present value (NPV) and how integrated modeling helps define production strategy. For NI, three stages were considered: number of wells, placement of wells, and platform capacity. For I, five stages were evaluated (all NI parameters) with diameters and gas lift evaluation, and platform placement. The results are similar, but the simplifications (NI) may affect financial performance. The cross analysis indicated (in the hypothesis that the integrated system is closer to reality) that integrating the NI case resulted in considerable financial and production differences and may be useful in simplified systems. Since the main aspects of the object-function financial return were related to reservoir model behavior, one can first apply the nonintegrated optimization cycles, then add the integrated cycles, obtaining an intermediate time of the integrated model optimization in similar cases.

Graded Control Technology of Oil Stability and Water Control in Fracture-Pore Carbonate Reservoirs

In view of the prominent problems of extremely strong heterogeneity, fracture development of different scales, and serious rapid water channelling in the process of water injection development in fracture-pore carbonate reservoirs, a comprehensive treatment method of oil stabilizing and water controlling is proposed, which includes fracture classification control, combination of adjustment and plugging, and wettability change. Based on the static and dynamic test data, the characteristics of reservoir fracture development and fracture scales are described in detail. By means of reservoir engineering and numerical simulation, the water flooding rule under different grade fracture reservoir conditions is studied, the influence of different levels of fractures on water injection development is evaluated, and the improvement effect of different control methods on water drive sweep is demonstrated. Research shows that a large amount of remaining oil trapped in pores is affected by fracture water channelling, which makes it difficult to use effectively. The water flooding sweep characteristics of reservoirs with different scales of fractures are quite different, and large-scale fractures are the main reason for ineffective water injection. The hierarchical control techniques of plugging large-scale fractures, intervening and adjusting small- and medium-scale fractures, and changing the wettability of microscale pore media can significantly extend the water flooding spread range and effectively improve oil well production. The research results have been applied in the field and achieved good results. This technology can provide theoretical guidance and a technical basis for the comprehensive treatment of oil stabilization and water control in fractured-porous carbonate oil and gas reservoirs.

Live imaging of micro and macro wettability variations of carbonate oil reservoirs for enhanced oil recovery and CO2 trapping/storage

Carbonate hydrocarbon reservoirs are considered as potential candidates for chemically enhanced oil recovery and for CO2 geological storage. However, investigation of one main controlling parameter—wettability—is usually performed by conventional integral methods at the core-scale. Moreover, literature reports show that wettability distribution may vary at the micro-scale due to the chemical heterogeneity of the reservoir and residing fluids. These differences may profoundly affect the derivation of other reservoir parameters such as relative permeability and capillary pressure, thus rendering subsequent simulations inaccurate. Here we developed an innovative approach by comparing the wettability distribution on carbonates at micro and macro-scale by combining live-imaging of controlled condensation experiments and X-ray mapping with sessile drop technique. The wettability was quantified by measuring the differences in contact angles before and after aging in palmitic, stearic and naphthenic acids. Furthermore, the influence of organic acids on wettability was examined at micro-scale, which revealed wetting heterogeneity of the surface (i.e., mixed wettability), while corresponding macro-scale measurements indicated hydrophobic wetting properties. The thickness of the adsorbed acid layer was determined, and it was correlated with the wetting properties. These findings bring into question the applicability of macro-scale data in reservoir modeling for enhanced oil recovery and geological storage of greenhouse gases.

Experimental investigation of the adsorption process of the surfactant-nanoparticle combination onto the carbonate reservoir rock surface in the enhanced oil recovery (EOR) process

Nowadays, the application of materials, such as surfactants and nanoparticles in enhanced oil recovery (EOR) projects has been widely studied. So, the adsorption process of these substances is one of the important methods to increase the oil recovery factor from carbonate oil reservoirs. However, understanding how the surfactant-nanoparticle combination interacts through the adsorption process onto the carbonate reservoir rocks surface is not well discussed. In this paper, the adsorption process of saponin extracted from the Glycyrrhiza glabra plant as a natural non-ionic surfactant (GG surfactant) with the presence of hydrophilic titanium dioxide nanoparticles (HITNPs) onto the carbonate reservoir rock (adsorbent) surface has been investigated for mobilizing the crude oil remaining to increase the oil recovery factor. Hence, this study highlights the equilibrium adsorption rate and the adsorption kinetics of these materials in aqueous solutions for chemical EOR schemes. Also, analyses of X-ray diffraction (XRD) spectrometry, scanning electron microscopy (SEM), and Fourier transform infrared (FTIR) spectroscopy have been applied to confirm and determine the physicochemical changes and properties of materials. To evaluate the adsorption rate and the relationship between surfactant concentration with the presence of nanoparticles and adsorption density on the adsorbent surface in the aqueous phase, batch adsorption tests under atmospheric conditions at different concentrations and times have been used to comprehend the impact of adsorbate dose on the sorption efficiency. Therefore, the electrical conductivity (EC) technique was used for measuring the adsorption rate of surfactant with the presence of HITNPs in the aqueous phase on the adsorbent surface. The adsorption kinetics process was experimentally investigated at laboratory temperature (25 °C) by monitoring the uptake of solutions on the adsorbent surface as a function of time. The experimental adsorption data were also examined by different equilibrium and kinetic models of adsorption. Hence, the adsorption parameters were determined for each model. Langmuir isotherm was the best model according to the higher values of the correlation coefficient (R2) for GG surfactant and surfactant nanofluid solutions on the adsorbent surface. Furthermore, the pseudo-second-order kinetic model could satisfactorily estimate the adsorption kinetics of GG surfactant and surfactant nanofluid solutions on the adsorbent surface. Results indicated that the adsorption process of GG surfactant and surfactant nanofluid solutions on the adsorbent surface is characterized by a short period of rapid adsorption, followed by a long period of slower adsorption. Moreover, the results of the IFT experiment of these materials showed that GG surfactant and surfactant nanofluid solutions could significantly reduce the IFT value between oil and water system. Finally, the results obtained from this study can help in selecting appropriate surfactants and metal oxide nanoparticles for the design of EOR projects, especially reservoir simulation schemes and chemical flooding processes for carbonate oil reservoirs.

Rate transient analysis of fractured-caved carbonate reservoirs under different cave connecting modes

In fractured-caved carbonate oil reservoirs with well-developed dissolved caves, most of the caves are generally connected by large fractures to form separate and independent fractured-caved systems. The oil well basically intersects some fractures, and fractures connect one or two large-scale dissolved caves in series or parallel model to form an independent fractured-caved unit. Moreover, due to the large size of the dissolved cave in the fractured-caved unit, it no longer follows Darcy's law, but shows features belongs to pipe flow, free flow or a seepage-pipe flow. In this case, the conventional equivalent multiple porous media seepage mathematical model is inaccurate to characterize this kind of fractured-caved reservoir units. This study simplifies the structure of the large bead-shaped fractured-caved reservoir and shows how the well-cave and cave-cave units are connected through fractures. Results show that the connected fracture flow exsits in the periphery of the large cave dissolved caves in the area far from wells. Thus either a linear series or a parallel mathematical model is applied to simulate the connection of the two dissolved caves. The fluid flow in fractures is still considered as seepage flow, while in large dissolved caves it is considered as free flow. Therefore, the dual-cave dual-fracture series mathematical model and dual-cave single-fracture parallel mathematical model considering seepage-free flow coupling are established. Laplace transform is then used to mathematically solve the model, and Stehfest numerical inversion is conducted to draw the typical rate transient analysis curves. Finally, sensitivity analysis is applied to discuss the relationship between controling factors of the flow and actual reservoirs. Based on the rate transient analysis type curves, geometric parameters such as radius of cave, permeability and length of the large-scale fracture and dynamic reserves can be obtained. Finally, a field case in a bead-string fractured-caved reservoir unit of Tarim basin is implemented to verify the effectiveness of the proposed models and methods. The parameters obtained by type curve match support exploitation of fractured-caved reservoirs. • The large bead-shaped fractured-caved reservoirs are simplified based on reservoir static carving. • The fluid flow is considered as free flow in large dissolved caves. • The dual-cave dual-fracture series and dual-cave single-fracture parallel mathematical models are established and solved. • Sensitivity analysis is applied to discuss the relationship of the reservoir parameters. • The specific processes of type curves matching have been given in detail.