Chapter 3 - Research on laboratory combination flooding experiment digitization

Laboratory core flooding experiments in reservoir sandstone under different sequestration pressures using multichannel fiber Bragg grating sensor arrays

With the maturityof waterflooded reservoirs, owing to seriousheterogeneity, the fluid will channel through the thief zone, leadingto considerable remaining oil unrecovered in the upswept area. Tofurther enhance oil recovery (EOR) after waterflooding, the heterogeneousphase combination flooding (HPCF) was composed of a polymer, branched-preformedparticle gel (B-PPG), and surfactant. For the sake of improving theeconomic efficiency, the influence of the injection scheme on theEOR of HPCF with an equal chemical agent cost was investigated bysand-pack flooding experiments. Then, visual plate sand-pack modelflooding experiments were performed to study the swept area of HPCFunder different injection schemes. Results demonstrated that the totalEOR of HPCF under different injection schemes ranged from 33.5 to39.3%. Moreover, the EOR of HPCF under the alternation injection (AI)scheme was the highest, followed by the concentration step changeinjection (CI) scheme, and that of the simultaneous injection (SI)scheme was the least. The visual flooding experimental results showedthat the swept area of HPCF after waterflooding under the AI schemewas higher than that of the SI. Moreover, in view of qualitative analysisof remaining oil distribution, the EOR of AI of HPCF was higher thanthat of SI, which was consistent with the parallel sand-pack floodingresults.

The growing need for energy and the depletion of oil wells necessitate advanced Enhanced Oil Recovery (EOR) techniques, particularly water and polymer flooding, which play a crucial role in augmenting hydrocarbon recovery rates. However, water flooding in high-permeability layers often leads to water breakthroughs, reduced sweep efficiency, and the formation of preferential channels, posing significant challenges to oil recovery and reservoir management. Conformance control treatments, including the use of polymer microspheres, offer a promising solution by sealing high-permeability zones and enhancing sweep efficiency. This study focuses on the application of fluorescent polymer microspheres based on polyacrylamide, which is extensively employed in the oil sector as an oil displacement agent. Fluorescent polymers called Poly 400, Poly 200, and Poly 600, incorporating cationic methacrylamide monomers, were synthesized through copolymerization to create amphiphilic polymers with enhanced stability and functionality. These fluorescent polymers were evaluated through flooding tests using a quarter-five-spot model of transparent quartz glass under UV light, allowing for instantaneous measurement and observation of fluorescence intensity. At reservoir conditions, the oil displacement experiments confirm that the incremental oil after water flooding by Poly 400, Poly 200, and Poly 600, is 13.1%, 9.1%, and 6.1% of OOIP respectively. The findings showed that fluorescent polymer microspheres could efficiently target high-permeability layers, adapt to varying pore throat sizes, and improve the plugging rate of high-permeability channels, thereby optimizing oil recovery. A subsequent simulation study using the CMG simulator provided further insights into the efficacy of these fluorescent polymers as EOR agents, revealing their potential to enhance sweep efficiency and enhance oil recovery. Simulation results showed that oil saturation decreased from 68% (initial) to 13.5%, 16.1%, and 18.3% after Poly 400, Poly 200, and Poly 600 flooding respectively. This work highlights the potential of fluorescent polymer microspheres as a valuable tool for EOR applications, offering significant advancements in reservoir management and oil recovery optimization.

The release of CO2 into the atmosphere has been verified as a significant reason for global warming and climate change. To prevent a large amount of CO2 from being emitted into the atmosphere, its utilization and storage become very important for human survival. Regarding the utilization of CO2 in oil reservoir engineering practice, CO2 enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs, such as sandstone, carbonate, and shale gas/oil reservoirs, and scientists and reservoir engineers aim to improve displacement efficiency with different injection modes and study its influencing factors over the past few decades. However, related to the experimental evaluation of storage capacity potential with the CO2EOR displacement mode and the long-term storage of CO2 in situ in the formation experienced by CO2 flooding is rarely studied experimentally. In this study, we investigated the effect of injection mode and reservoir heterogeneity on CO2EOR and its storage potential. Several core flooding experiments on displacing remaining oil and water by scCO2 after water flooding have been performed, including injection modes, which are horizontal, vertical, and tapered WAG injections, using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. The dual-core core flooding experiment was used to study the effect of reservoir heterogeneity on scCO2 storage capacity. As a result of this study, the previously proposed experimental methodology was used to calculate the scCO2 storage capacity, which involved that the scCO2 dissolves into residual water and oil after scCO2 injection, and evaluate the CO2 storage capacity efficiency for different injection modes. The vertical-continuous injection mode of scCO2 flooding can maximize the process of its storage advantage. This study found that the main scCO2 storage mechanism is mainly pore storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is related permeability of rocks, which expresses the logarithmic relation and increases with an increase in air permeability. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 decreased somewhat after the scCO2EOR process. In addition, the effect of rock heterogeneity on scCO2 storage efficiency is also discussed. The highlights of this study are that the comparison of the scCO2 storage potential was made based on experimental results of different injection modes, and improving the displacement efficiency in the low permeable zone also increases scCO2 storage efficiency. Furthermore, the experimental results can be applied directly to be helpful for the evaluation and strategy of scCO2 storage and can be used to simulate the performance during the injection process of scCO2 storage.

Effects of magnesium and potassium sulfates on oil recovery by water flooding

Publication Rights Reserved Abstract Directional movement of injected water has been found to exist in many oil reservoirs in which water floods are being conducted. This paper discusses many of the ramifications of natural fractures and directional permeability in oil reservoirs being water flooded. Suggested steps to be taken in installing water floods in suspected areas are presented, and the importance of proper pattern selection after establishing the directional orientation of the fracture system or directional permeability is discussed. Presented in this paper is the case history of the W. A. Moncrief, Trousdale Unit Water Flood Project in Pottawatomie County, Okla., in which a directional fracture system was discovered in the 4,260-ft Calvin sand soon after the waterflood program had been installed. The adverse effects of the fracture system during the initial phase of the program and the results obtained by revising the injection pattern are shown graphically and are discussed in detail. Introduction Water flooding, in its simplest definition, is the displacement by water of the mobile or movable oil from an oil reservoir. A waterflood program should be installed only after sufficient study of an oil reservoir has been made to determine that an economically feasible amount of recoverable oil exists in the reservoir. The actual waterflood operation involves the injection of water into properly selected wells at a sufficient rate of injection to insure proper displacement of the oil from the reservoir in a reasonable length of time so that the optimum profit will be obtained. There are many natural and artificial conditions in an oil reservoir which can affect this displacement mechanism. If an oil sand were simply a homogeneous uniform sand matrix, it would be an easy task to fill the oil sand with water and to displace the mobile or movable oil to the producing wells. However, nearly all oil reservoirs are heterogeneous in nature. Within a single oil reservoir there is usually a wide variation in porosity, permeability, water saturation, and gas saturation, and also there may be a wide variation in composition throughout the sand section such as shale inclusions, lime streaks, gradations in lithology, etc. In addition to this, the oil sand may be overlain by a gas cap; it may be uderlain by a water zone; it may be faulted; it may contain natural fractures; it may be composed of a series of lenses which may or may not be in communication with one another; it may contain weak zones or there may be weak formations immediately above or below the sand; and a multitude of other adverse natural environmental factors may exist. In addition, artificial conditions such as very large sand frac treatments, poor cement bond between casing and formation, poor completions, mud invasion, and others may be present which could adversely affect the successful displacement by water of oil in the desired reservoir interval. The possible presence of these adverse conditions must be recognized from the start, and a program should be installed which will eliminate or at least minimize as many of these adverse conditions as possible so that a successful water injection program can be accomplished. DIRECTIONAL MOVEMENT OF INJECTED WATER This paper deals with one of the many possible adverse phenomena which can affect the success of the water injection program.

Although waterflooding treatment assisted by traditional viscosity reducer yields additional oil recovery, this increments in production sometimes cannot meet the production requirements. To solve this problem, it is necessary to analyze and understand the flow mechanism of heavy oils in the waterflooding process assisted by the viscosity reducer. This study employed an etched glass micro-model to visualize the flow behavior of heavy oils under assistance of a novel multi-functional viscosity reducer with the condition of high temperature and ultra-heavy oil. The water flooding and novel viscosity reducer flooding experiments were carried out, and the state and shape of the remaining oil phase were observed from the global perspective and the microscopic local perspective in the etching micro-glass. Results show that the viscosity reducer solution can not only greatly reduce viscosity of heavy oil but also decrease oil-water interface tension. In the waterflooding process, the continuous oil group and long oil slug are the main characteristics of remaining heavy oil in the reservoir. By waterflooding with the new viscosity-reducer, the remaining oils exist as short slug and droplet, and 3 times wider flooding area for fluid-flow was observed than conventional waterfloodings.

Carbon Dioxide (CO2) has been recognized as a preferred miscible solvent for Enhanced Oil Recovery (EOR) methods. Miscible flooding by CO2 has proven its positive effectiveness through numerous laboratory and field projects. The main goals of this study are to provide microscopic reservoir rock characterization, and optimize the selection and the effect of CO2 slug size to be applied for carbonate oil field, U. A. E., on oil recovery by CO2 miscible flooding.Scanning Electron Microscope (SEM) is used to provide accurate description of the reservoir rock surface topography. The SEM is used to attain the pore size distribution of the rock. Energy Dispersive X-Ray Spectrometer (EDS) and Inductively Coupled Plasma (ICP) are applied for detailed accurate analysis of elements constituting the rock.Five flood experiments were performed to achieve the goals of this study. The first experiment was carried out using continuous CO2 flooding. Other three experiments used different CO2 slug sizes of 0.15, 0.30, and 0.45 hydrocarbon pore volume and chased by actual reservoir brine. The fourth experiment was carried out to evaluate the performance of waterflooding. All experiments were performed using actual crude oil injected into actual reservoir rock samples of almost 23 cm length and 10 cm diameter. These samples were saturated at initial-oil-in-place condition and then subjected to water and/or CO2 floodings. The minimum miscibility pressure (MMP) was calculated to be 3,700 psia using current correlations from literature. To secure good miscibility condition, all experiments were conducted under injection pressure of 4,200 psia and at 250 °F similar to the reservoir condition.The results indicated that water flooding recovered 66 % IOIP and a continuous CO2 miscible flood produced 96 % IOIP. Furthermore, the increase of slug size increases oil recovery by CO2 miscible flooding, but the slug size of 0.15 HCPV is recommended since the increment in oil recovery using larger slugs does not represent significant addition to the oil recovery in comparison to applied smaller slug sizes.

Laboratory Measurements of Acoustic Velocities in Dry and Fluid-Saturated Sandstones

An insight into core flooding experiment via NMR imaging and numerical simulation

Multi-fractured horizontal wells (MFHWs) completed in low-permeability (‘tight’) oil reservoirs recover only a small fraction of the oil in place using the primary recovery scheme. The main objective of this study is to investigate various continuous injection techniques for enhanced oil recovery (EOR), including water and CO2 flooding schemes, as well as water-alternating-gas (WAG) injection, to increase production from a MFHW completed in a tight oil reservoir in Alberta, Canada. This study employs numerical compositional simulation using two model types: a single porosity (SP) model with an enhanced fracture region (EFR), and a local dual-permeability, dual-porosity (L-DP-DK) model with a limited enhanced fracture region (LEFR). The SP and L-DP-DK models incorporate laboratory-derived rock and fluid data and are utilized to history-match production data from a MFHW operated under primary depletion. Multiple history-matched models are obtained to account for variability in the core- measured matrix permeability (ranging from 30 to 300 μd). The calibrated models are then utilized to predict incremental oil recovery using continuous injection and WAG EOR schemes over a 30-year period. Finally, a sensitivity analysis is conducted to study the impact of matrix permeability, fracture half-length, and fracture geometry (i.e., tip-to-tip and parallel overlapping fractures) on the simulated incremental oil recovery. The results demonstrate that the L-DP-DK model predicts a greater oil recovery (79% higher on average) than the SP model. This increase is attributed to an improved mixing and extraction process predicted by the L-DP-DK model due to more effective communication between the fracture network and the matrix. Simulation results using the L-DP-DK reveal that the CO2-gas flooding scheme has a higher recovery than WAG and water flooding techniques. CO2-gas flooding provides the greatest incremental recovery factor (i.e., 53%) when the history-matched model includes the largest permeability (300 μd) and the smallest fracture half-length (150 ft). In addition, the L-DP-DK model predicts 24% incremental recovery using the matched model with the smallest matrix permeability (30 μd) and the largest fracture half-length (500 ft). Gas flooding provides a better recovery because the oil viscosity and surface tension are two and ten times lower, respectively, than those calculated from the WAG. Moreover, the water cycle of the WAG scheme incurs blockage, leading to a quicker gas breakthrough for up to four months, and lower sweep efficiency. Finally, the sensitivity analysis reveals that the selected completion method and assumed fracture pattern significantly influence the recovery factor, with the staggered zipper completion (parallel, overlapping fractures) providing 140% greater oil recovery compared to a tip-to-tip geometry. This study provides practical insights into the impact of model uncertainty and completion methods on the design and performance of various continuous injection and WAG EOR schemes in tight oil reservoirs. Wherever possible, customized laboratory data, such as relative permeability collected for low-permeability rock samples, have been utilized.

About 70% of theremaining oil remains underground after waterflooding, and there is a need to better understand the formation anddistribution of this remaining macroscopic oil to enhance oil recovery.In this study, three types of visual plate models were devised withdifferent packing sequences: homogeneous (J), high-permeability layeron top (F), and low-permeability layer on top (Z). Based on thesemodels, several visual flooding experiments were conducted to studythe water flooding physics and the remaining oil distribution patternof an offshore thick heavy oil reservoir under the impact of formationheterogeneity, packing sequence, model length, and permeability contrastduring water flooding. These displacements were monitored photographically,and the effluent production profiles were recorded. The results showedthat layer permeability and gravitational segregation play an importantrole during the water flooding process in layered porous media. Experimentalresults based on the model with different lengths show that the breakthroughoil recovery decreases with the increase of well spacing. Finally,a correction was made to the gravity number by introducing a scalingfactor that characterized the formation heterogeneity and packingsequence in thick formation, compared to a known gravity number; themodified gravity number showed a better correlation with breakthroughoil recovery of water and polymer flooding. The research results provideeffective guidance for the remaining oil distribution and injectionand production parameter optimization in actual reservoirs.

Enhance oil recovery by carbonized water flooding in tight oil reservoirs

Polymer/surfactant combination solutions were easy to suffer chromatographic separation effect when injected into a relatively low permeability reservoir for the poor injection ability. In addition, the long chain polymer molecules are easy to be cracked when passing through the porous media with low pore throat radius. These problems limit the polymer/surfactant combination flooding used in the poor reservoirs for enhanced oil recovery (EOR). The conventional viscoelastic surfactant (VES) is mainly used in fracturing or drilling. In this paper, we present a novel viscoelastic surfactant, VES-JS, which is designed for EOR. It has a unique ability that allows it to have viscoelasticity like the polymer solution and the capacity to deduce the interfacial tension (IFT) value of oil and water to order 10–2 ∼ 10–3mN/m. For the self-assemble ability, it can reform network structure when it stiff in the porous media. Under the reservoir condition, 65 °C, 100 × 10–3 μm2, VES-JS shows good viscoelasticity and ultr...

The Eakring Dukeswood oil field of Nottinghamshire was last produced in 1971. All wells have since been abandoned and the licence ML 1 expired on 22 April 1992. Cumulative production was small by North Sea standards, but during the Battle of the Atlantic the field produced the bulk of the UK’s indigenous crude, peaking at 1600 BOPD in 1941. Cumulative recovery was some 6.5 MMSTB from an estimated 25.6 MMSTB in place in the completed horizons. In 1986 a study was undertaken to evaluate the remaining reserve potential. The primary tool for such work would normally be a detailed geological model, but since less than 25% of the 197 grid drilled wells have any wireline logs or cores only structural models existed. There is very little seismic. A further complication is that there were nine productive horizons and the majority of well completions were unsegregated over four of them. Only 20% of cumulative production can be assigned unequivocally to any one reservoir. Reservoir models, and individual reservoir contributions to production, had to be determined using less conventional techniques. Individual well performance under recycled peripheral water flood has proved to be a powerful tool to determine reservoir connectivity. Mapping decline rate reversal and water breakthrough by month indicates the transmissibility fairways and no-flow barriers in the system. It has also proved in some circumstances a useful discriminator of reservoir contribution. The reservoirs are mainly Westphalian A to Namurian B siliciclastics. All were undersaturated at initial conditions. Porosity is often secondary, rarely above 20% and absolute permeability ranges from less than 1 to several hundred mD. Irreducible water saturation (S wi ) from mercury injection data ranges between 30 and 50% and water flood experiments indicated residual oil saturation (S or ) at 30%. The oil is waxy, up to 16% by weight, and has a high viscosity with correspondingly unfavourable mobility. API gravities range from 31.9–37.6°. Most production was obtained from the Loxley Edge Rock, the Sub Alton and Crawshaw sandstones—all by depletion drive, and from the Ashover Grit—in part water driven. Post-war water flooding was directed mainly at the Sub Alton and Crawshaw units. Regional studies and sedimentological examination of two recent adjacent wells established the likely broad reservoir anatomy. This was then refined for the field from the qualitative transmissibility maps constructed from flood front behaviour. Geological models could then be assembled with some confidence and bypassed oil and secondary accumulations were identified. Relative permeability experiments on the modern core indicate an additional field reservoir/accumulation, previously unrecognized.