Vertical Sweep Efficiency Research Articles

Linear and radial flow modelling of a waterflooded, stratified, non-communicating reservoir developed with downhole, flow control completions

Forecasts of the performance of waterflooded oil-field have been prepared for many years using fractional flow models, such as those by (Buckley-Leverett, 1942) (BL), (Welge, 1952) and (Dykstra-Parsons, 1950) (DP), to estimate the vertical sweep efficiency between wells. These methods, and their later modifications, formed the theoretical basis for designing a water-flooded oil-field. Advanced Well Completions (AWC) incorporating downhole flow control device (FCD) technology have become a proven method for modifying a production well's inflow profile, delaying water breakthrough, improving sweep efficiency and enhancing recovery.This manuscript extends the fractional flow model describing the performance of a waterflooded, stratified-reservoir with an AWC installed in the production well. The piston-like behaviour of the water-front described by previous, semi-analytical models is extended here to the linear and radial flow modelling of more realistic displacement profiles.This paper describes the theoretical basis and application workflow along with several case studies illustrating their performance and value. The accuracy of the new, semi-analytical models are verified by comparison against the results from a numerical reservoir simulator. Model limitations and possible future extension are also discussed.The workflow can be implemented as either a production forecast or a diagnostic tool for an AWC well in a waterflooded oil-field. It provides one missing link between today's AWC design workflows and the long-term value evaluation of a specific AWC design when a commercial numerical simulation software is either not available or too time consuming.

Experimental study on lateral flooding for enhanced oil recovery in bottom-water reservoir with high water cut

The regular enhanced oil recovery (EOR) methods in bottom-water reservoir aim to increase the vertical sweep efficiency. After multicycle chemical injection, the injected slug cannot effectively control the bottom water coning in the presence of fully developed water channel, decreasing the sweep efficiency and lowering economic efficiency. To improve the development effect of bottom-water reservoir, lateral flooding is proposed as a more cost-effective EOR technique by displacing the oil formation horizontally. In this study, three lateral flooding tests were performed in a three-dimensional physical model based on the geometric similarity criterion. Bottom-water reservoirs were simulated by sandpacking oil and water formations according to the parameters of the target oil reservoir. The bottom-water energy was supplied by an ISCO constant pressure, and the lateral flooding was conducted by an ISCO constant rate pumps. The oil recovery, water cut, pressure drop, and saturation variation maps obtained from these tests were recorded and analyzed. A comparison of these results between different crosslinked polymer slug tests shows that the improved oil recovery by lateral waterflooding can be mainly attributed to a significant increase in horizontal sweep efficiency. After 0.3 PV crosslinked polymer injection, about two-thirds of that was used to shut off the main water channels; the chemical packer, formed by the surplus polymer spreading along the oil/water interface under the drive of lateral injection, can inhibit bottom water from coning into the oil formation and prevent the crossflow. The 0.2, 0.3, and 0.4 PV crosslinked polymer injection can increase oil recovery by as much as 11.35, 36.23, and 39.74% of the original oil-in-place (OOIP), respectively. This confirms that lateral flooding is an efficient EOR method in bottom-water reservoir.

Effects of relative permeability change resulting from interfacial tension reduction on vertical sweep efficiency during the CO2-LPG hybrid EOR process

ABSTRACTThe addition of liquefied petroleum gas (LPG) to the CO2 stream reduces interfacial tension (IFT) between the injected gas and the reservoir oil, and it changes the gas-liquid relative permeability by making it more water-wet, which affects not only the oil mobility, but also the vertical sweep efficiency. The reduction of the IFT decreases vertical sweep efficiency because it enhances the relative permeability of the solvent, resulting in an increase in the viscous gravity number. For CO2-LPG enhanced oil recovery (EOR), oil recovery is enhanced by up to 47%, as compared to CO2 flooding, when the relative permeability change caused by the IFT is not considered. By taking the vertical sweep-out caused by IFT and relative permeability change into consideration, this increase is reduced to 40%. These results indicate the importance of considering the relative permeability and IFT change when predicting the performance of the CO2-LPG EOR process.

Water-cut rising mechanism and optimized water injection technology for deepwater turbidite sandstone oilfield: A case study of AKPO Oilfield in Niger Delta Basin, West Africa

Through the analysis of the reservoir connection relationship and the water-cut rising rules after water breakthrough in the highly volatile oil AKPO oilfield, a new model of water-cut rising was established, and the timing and strategy of water injection were put forward. The water-cut rising shapes of producers after water breakthrough can be divided into three types, and their water-cut rising mechanism is mainly controlled by reservoir connectivity. For the producers which directly connect with injectors in the single-phase sand body of the single-phase channel or lobe with good reservoir connectivity, the water-cut rising curve is “sub-convex”. For the producers which connect with injectors through sand bodies developed in multi-phases with good inner sand connectivity but poorer physical property and connectivity at the overlapping parts of sands, the response to water injection is slow and the water-cut rising curve is “sub-concave”. For the producers which connect with injectors through multi-phase sand bodies with reservoir physical properties, connectivity in between the former two and characteristics of both direct connection and overlapping connection, the response to water injection is slightly slower and the water-cut rising curve is “sub-S”. Based on ratio relationship of oil and water relative permeability, a new model of water cut rising was established. Through the fitting analysis of actual production data, the optimal timing and corresponding technology for water injection after water breakthrough were put forward. Composite channel and lobe reservoirs can adopt water injection strategies concentrating on improving the vertical sweep efficiency and areal sweep efficiency respectively. This technology has worked well in the AKPO oilfield and can guide the development of similar oilfields.

STOIIP validation for a heterogeneous multi-layered reservoir of a mature field using an integrated 3D geo-cellular dynamic model

The intersecting lobes of bars and channels of Nezzazat group, one of the most complex reservoirs in the Gulf of Suez, concealing underneath a thick salt succession are very difficult to interpret and therefore impose a profound integrated geological and petrophysical study. Such a study encompasses petrophysical characterization of Nezzazat group into seven hydraulic flow units honoring the important developed lithostratigraphic units. To enhance the field development plan, the Big Loop simulation approach is applied to cover all the existing geological and engineering uncertainty. The 3D dynamic simulation model achieved history match to the seven reservoir intervals using RFT pressure data and production logs on layer basis, showing a wide range of permeability and production contribution. The history matched model has proved calculated dynamic STOIIP significantly higher than volumetric STOIIP with additional ±7 MMBO. Such a result encourages drilling a new well to increase the current recovery for the field and achieve a new ultimate recovery. The proposed methodology not only highlights the importance of volumetric STOIIP verifications but also helps understanding the vertical sweep efficiency for different hydraulic flow units that increase the ultimate recovery of the field.

Technology Focus: Mature Fields and Well Revitalization (January 2018)

Technology Focus Maximizing production from brown-fields and extending the plateau have become utmost priorities for exploration-and-production companies the world over. This calls for a synergistic approach involving close coordination of various disciplines—subsurface, surface, well drilling and completions, and facilities engineering—to achieve the common goal of maximizing production and recovery. There is a growing awareness that maximizing field production involves not only having a clear understanding of subsurface intricacies but also ensuring that existing surface facilities are performing at their best to handle production in an environmentally safe manner. Many papers presented during the past year at SPE conferences and surveyed for this review address these issues. Infill drilling and optimization of ongoing waterflood are two activities planned for revitalization of mature fields. Drilling through differentially depleted, multilayered reservoirs and the untapped deeper zones is a challenging task. Robust knowledge of rock properties, formation pressures, magnitude of in-situ stresses, and their evolution with production and depletion is essential for successful drilling of new wells in the redevelopment of mature fields. It is necessary to apply several tools to identify locations of bypassed oil and corroborate the findings of these tools before making a final decision. This becomes even more challenging when there is low resistivity contrast, such as in freshwater environments or in certain cases where openhole logging is not possible because of poor borehole conditions. Operators have calibrated numerical-simulation models successfully with innovative logging tools to locate and produce new oil from old fields. Rejuvenation of mature assets plays a crucial role in the current low-oil-price scenario, allowing for improved production with limited investments and risks. Nevertheless, brownfield rejuvenation is often very demanding in terms of complex integrated reservoir studies, which typically take several months to complete. The new and emerging technology of applying analytical and data-driven models provides fast solutions to diagnose ongoing waterflooding processes effectively and examine low-cost strategies to improve areal- and vertical-sweep efficiencies. Recommended additional reading at OnePetro: www.onepetro.org. SPE 184902 Effects of Pressure Depletion on Stress-Field and Casing-Load Alteration in Mature Fields: A Case Study by Peng Zhang, Halliburton, et al. SPE 185412 Effective Waterflood Management in Complex Carbonate Reservoir of Mumbai High Field by N.T. Ravi, ONGC, et al. SPE 186004 Developing Infill and EOR Opportunities While Managing Subsurface Uncertainties in a Mature Complex Field Using Probabilistic Dynamic Modeling by R. Abd Karim, Petronas, et al.

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One of the main challenges in developing a process of continuous steam injection is to control the injection profile. Said profile is strongly affected by steam channeling to “thief zones” and the gravitational effect of override, both are characterized by preventing contact of the steam with reservoir zones containing considerable amounts of hydrocarbons thus decreasing the vertical sweep efficiency. These phenomena are favored by some features of the formation such as large thickness and reservoir heterogeneities and may affect the technical and economic feasibility of the project if they are not controlled and / or monitored properly.Several methodologies have been designed to address this problem. Among them are injecting surfactants for the formation of in situ foam, which seeks to reduce the mobility of steam; using thermal gels, for plugging high permeability channels; injection of solvents, used to enhance oil mobility; and water-alternating-steam injection (WASP) for scavenging of both upper and lower zone of the formation. This article collects relevant aspects of the mentioned methods, and a comparison is made in base of the number of applications, incremental production and implementation cost.Keywords: Steamflooding, In Situ Foams, Solvents, High Temperature Gels, Water Alternating Steam.

Simulation of CO2 Migration for the Planning of Well Test Configurations at the South West Hub Project, Western Australia

Containment of injected CO2 at the South West Hub project in Western Australia is dependent on non-structural trapping mechanisms in the 1500 m thick Wonnerup Member of the Lesueur Sandstone due to uncertainties regarding the sealing character of the ∼600 m thick overlying Yalgorup Member. Therefore, vertical migration distance and sweep efficiency and their impact on residual saturation and CO2 dissolution need to be properly assessed through reservoir simulations. We find that conventional Darcy-flow reservoir simulations result in significantly different predictions of plume migration compared to invasion percolation modelling when injecting at the base of the Wonnerup Member. If numerical predictions of the fate of injected CO2 are sensitive to the choice of model, care must be taken when selecting the methodology. One way to validate simulation predictions at a scale appropriate to the modelling is the use of well tests. In the Wonnerup Member a vertical migration test is recommended for consideration to confirm whether conventional reservoir simulations or percolation invasion modelling accurately predict the CO2 migration processes at the site. This test would involve a small injection of CO2 that is allowed to migrate upwards. The migration would be monitored with repeat pulsed neutron logging. This represents a new kind of test unique to the situation for the South West Hub site.

Optimizing the Use of Miscible Injectant at the Greater Prudhoe Bay Fields

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180420, “Optimizing the Use of Miscible Injectant at the Greater Prudhoe Bay Fields,” by S.X. Ning, SPE, B.S. Jhaveri, E.M. Fueg, SPE, G. Stechauner, J.L. Jemison, SPE, and T.A. Hoang, BP Exploration (Alaska), prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed. Miscible injectant (MI) has been used at Prudhoe Bay and its satellite fields for more than 30 years. This paper provides an overview of all enhanced-oil-recovery (EOR) projects in the Greater Prudhoe Bay (GPB) region and presents the process and methodology for MI allocation to these projects and to individual injection patterns. A new approach is used to determine the amount of MI allocated to each project on the basis of predicted marginal MI use per barrel of EOR oil. Introduction The MI-gas EOR process at Prudhoe Bay began in late 1982. In late 1986, the Central Gas Facility (CGF) began operation, enabling the first field-scale EOR project, the Prudhoe Bay Miscible Gas Project (PBMGP), to start in early 1987. Since then, the PBMGP has expanded to more than 170 injection patterns in the main field of Prudhoe Bay. Fig. 1 provides a layout of the oil fields on the North Slope of Alaska. The CGF is a gas-processing plant that makes natural-gas liquids (NGLs) for shipment in the Trans-Alaska Pipeline System and MI for EOR projects. The CGF currently processes an annual aver-age of approximately 7.5 billion scf/D of produced gas to generate approximately 40,000 STB/D of NGL and more than 200 million scf/D of MI. The feed gas comes from three different sources—solution gas from the produced oil, free reservoir gas from the gas cap, and returned MI (RMI) that was previously injected into the reservoir. The total amount of MI produced at the CGF is the sum of the fresh MI (which can be forecast by the GPB full-field simulation model) and the recaptured RMI (which can be forecast by COBRA and process modeling). COBRA is a full-field scale-up tool for predicting MI performance on the basis of type-pattern-simulation-model results. MI gas produced at the Prudhoe Bay CGF is a rich gas composed primarily of carbon dioxide (approximately 21%), methane (approximately 32%), ethane (20%), propane (25%), and a small amount of butane and heavier components (approximately 2–3%). Most of the GPB EOR projects are pattern floods that use a water-alternating-gas (WAG) injection to improve areal and vertical sweep efficiencies.

Polymer Flooding: The Influence of Polymer Chemical Structure and the Porous Medium

SummaryPolymer flooding is one of the chemical processes used to enhance the petroleum recovery. The injection of a polymer dissolved in water into a reservoir aims to increase the water viscosity, leading to an improvement of areal and vertical sweep efficiency of the oil that is located inside the pores of the rock formation. The polysaccharides (mainly xanthan gum) and polyacrylamides have been used extensively for this purpose by the oil industry, and several papers were published. However, it is not clear yet how to choose the best polymer for a specific rock formation. In this paper, four polyacrylamides with different structures were evaluated for polymer flooding and the results were correlated to the permeability of the sandstone's core employed. The polyacrylamides of higher average molar mass and higher radius of gyration were more effective in the enhancement of pressure inside the pore rock, especially with the decrease of rock permeability. Even in this case, no evidence of damage by polymer retention or adsorption on the pore rock was shown, indicating that the high polymers selected are good candidates to EOR.

Coarse-Grained Simulations of Polymer-Grafted Nanoparticles: Structural Stability and Interfacial Behavior.

In the tertiary oil recovery method known as "polymer flooding", the viscosity of the injected water is increased by dissolving partially hydrolyzed polyacrylamide so as to lower the mobility ratio and raise the vertical and areal sweep efficiencies. However, its drawbacks include the degradation of the polymer in the reservoir due to (1) shear while passing through chokes, perforations, and pore throats, (2) morphological changes induced by divalent ions, and (3) complete hydrolysis of the polymer at high temperatures. These factors adversely affect the viscosity of the polymer flood. Past experimental research showed that polymer-grafted nanoparticles (PNPs) could achieve the same viscosity enhancement at lower quantities than traditional linear polymers. The PNPs have the putative advantage of greater stability when confronted with the aforementioned reservoir conditions. In this work, we use dissipative particle dynamics (DPD) to simulate the oil-PNP-water system at the mesoscale and estimate its sensitivity to brine in ways that could serve as guidelines to experiments. We study the effect of salinity on the structure of linear and branched polyelectrolytes before extending the DPD model to PNPs at the oil-water interface. To this end, we parameterize the interactions of the polymer with the oil and water phases, and broadly map out solvent conditions that change the graft's morphology and affect the interfacial behavior of the grafted particle. We find that the equilibrium location of the grafted nanoparticle in an oil-brine system depends on its grafting density and the salinity.

Case study: Comparison of enhanced heavy-oil recovery by CGI, WAG, and GAGD

ABSTRACTContinuous gas injection (CGI) in the conventional horizontal flooding patterns leads to severe gravity segregation and poor reservoir contact (sweep) volumes. To improve the sweep efficiency, the Water-Alternating-Gas (WAG) process has been widely practiced in the industry. However, the WAG process has not measured up to expectations, as evidenced by the low recoveries observed in several field cases.The Gas-Assisted Gravity Drainage (GAGD) process is designed and practiced based on gravity drainage idea and uses the advantage of density difference between injected gas and reservoir oil to overcome the drawbacks of the WAG process.In this study, a comparison of enhanced heavy-oil recovery by three methods (CGI, WAG, and GAGD) is conducted by a commercial numerical simulator in a sector model of an Iranian offshore field. For this purpose, different production scenarios are designed. Moreover, the effect of several parameters such as injection fluid (CO2, hydrocarbon gas), in situ oil viscosity (heavy or extremely heavy oil), rate and volume of injection, and also three different WAG ratios are studied.The results show that the GAGD method is not suitable for this field as the thickness of pay zone is low for vertical sweep efficiency and causes early breakthrough of injected gas. Also, CGI leads to lower recoveries compared to the WAG process, due to its unfavorable mobility ratio. Injection of CO2 instead of hydrocarbon gas results in higher sweep efficiency because of its viscosity reduction and swelling effects. In case of extremely heavy-oil recovery, with decreasing well spacing, the oil recovery factor increases as the drainage radius of wells reduces substantially due to high-viscosity oil.

Modeling of Two-Phase Relative Permeability in Cambrian and Early Miocene Sandstone Reservoirs: A Case Study, Egypt

The relative permeability is the ratio of the effective permeability to the absolute permeability. Due to the importance of relative permeability in reservoir simulation, there is a dominant need to upscale it. So, several models were introduced to modeling the relative permeability. Some correlation models were dependent on capillary pressure measurements, while other models did not require such measurements. In this study, four relative permeability correlation models were chosen to apply them on two sandstone reservoir (labeled A and B) data sets. The two reservoirs belong to different ages and depositional environments. Both reservoirs are located in the Southern Gulf of Suez, Egypt. Reservoir A is the Nubian sandstone of Cambrian age. Reservoir B is the Nukhul clastic of Early Miocene age. The data sets include laboratory measurements of unsteady-state gas–oil relative permeability and steady-state water–oil relative permeability tests. The results indicate that the practical and modified Corey models were the most applicable model for the studied reservoirs. Additionally, prediction of relative permeability at saturation end points was carried out based on using routine core porosity and permeability by introducing new empirical equations. The relative permeability was used to identify rock wettability, water cut, water cutoffs and the areal and vertical sweep efficiencies.

Simulation of polymer flooding in one of the Iranian oil fields

Polymer flooding is the most important enhanced oil recovery (EOR) process, improving the water–oil mobility ratio. Polymers act basically increasing the viscosity of the injected water and reducing the swept zone permeability, allowing an increase in the vertical and areal sweep efficiency of the water injection, and, consequently, increasing oil recovery.In this study, initially based on experimental work the polymer properties were enhanced using the amount of Nano clay to fixed concentration of polymer. Then the polymer flooding was simulated and comparisons were made between obtained results of polymer flooding simulated with water natural depletion and water flooding process in different scenarios.This study shows the optimum concentration of Nano clay could improve polymer properties. Results also show that the polymer flooding scenario has higher oil recovery in comparison to other displacement methods such as natural depletion and water flooding.

Characterizing the Role of Clay and Silica Nanoparticles in Enhanced Heavy Oil Recovery During Polymer Flooding

Polymer flooding as one of the most effective methods for enhancing oil recovery has a significant effect on tertiary production of reservoirs with poor vertical sweep efficiencies and those which are extremely heterogeneous. Water-soluble polymers are used to both increase the viscosity of water and decrease the mobility ratio of the displaced and displacing fluids. However, due to high amount of polymer adsorption, presence of divalent cations and mechanical degradation, polymer molecules may lose their properties. Hence it is necessary to further improve the displacement effectiveness of polymer flooding. Despite the fact that several ways have been suggested to enhance the performance of polymer flooding, application of nanoparticles in the improvement of rheological properties of the polymer solution used in enhanced oil recovery has not been reported previously and is still an ongoing subject. This paper investigates the effects of nanoparticles on flow behavior of polymer solution in porous media by employing both experimental studies and numerical simulations. The simulation model first is validated against well-controlled laboratory experiment to have reliable predictions of the full-field implementations. The results show that the amount of polymer adsorption and viscosity of polymer solution will improve when the clay or silica nanoparticles is present in the injectant, and accordingly, the cumulative oil recovery and breakthrough time will be bettered. The result of sensitivity analysis demonstrates that polymer molecules are more degradable during polymer flooding compared to nanoparticles-assisted polymer flooding. Based on the validated model, 3D simulations of nanoparticles-assisted polymer field pilot were performed and the results revealed that the cumulative oil recovery, water cut and breakthrough time will improve when the injectant has some dispersed nanoparticles.

Analytical Model of Waterflood Sweep Efficiency in Vertical Heterogeneous Reservoirs under Constant Pressure

An analytical model has been developed for quantitative evaluation of vertical sweep efficiency based on heterogeneous multilayer reservoirs. By applying the Buckley-Leverett displacement mechanism, a theoretical relationship is deduced to describe dynamic changes of the front of water injection, water saturation of producing well, and swept volume during waterflooding under the condition of constant pressure, which substitutes for the condition of constant rate in the traditional way. Then, this method of calculating sweep efficiency is applied from single layer to multilayers, which can be used to accurately calculate the sweep efficiency of heterogeneous reservoirs and evaluate the degree of waterflooding in multilayer reservoirs. In the case study, the water frontal position, water cut, volumetric sweep efficiency, and oil recovery are compared between commingled injection and zonal injection by applying the derived equations. The results are verified by numerical simulators, respectively. It is shown that zonal injection works better than commingled injection in respect of sweep efficiency and oil recovery and has a longer period of water free production.

Application of Lorenz-curve model to stratified water injection evaluation

Abstract To evaluate the effect of stratified water injection accurately during different development stages, a Lorenz-curve model was constructed upon a modified four-parameter Sarabia-Lorenz-curve model with water injectivity test data over years, and the relationship between accumulative perforated sandstone thickness and injected water volume of single wells was described by the model. Three evaluation indexes, dimensionless water injectivity intensity, vertical sweep efficiency and water-injection non-balanced degree, and their calculation were presented. Dimensionless water injectivity intensity is used to evaluate the distribution and balanced degree of water injectivity intensity, vertical sweep efficiency is the proportion of oil layers that produce oil, and water-injection non-balanced degree illustrates the overall water-injection balanced condition, then the model is solved by particle swarm optimization algorithm. Thirty-eight stratified water injection wells were evaluated in the Daqing Xingshugang oilfield. And the factors influencing the effect of water injection in single wells were studied considering segments construction, water allocation projects and reservoir physical properties. Finally, technological limits of stratified water injection were proposed under extreme high water-cut and recovery.

Mechanisms behind injecting the combination of nano-clay particles and polymer solution for enhanced oil recovery

Laboratory investigations and field applications have proved injection of polymer solution to be an effective means to improve oil recovery for reservoirs of medium oil viscosity. The incremental oil produced in this case is the result of an increase in areal and vertical sweep efficiencies. Biopolymers and synthetic polymers are the major categories used in the petroleum industry for specific reasons. Biopolymers like xanthan are limited in their application as they are more susceptible to biodegradation. Synthetic polymers like Hydrolyzed PolyAcrylaMide (HPAM) have a much wider application as they are less susceptible to biodegradation. Furthermore, development of nanotechnology has successfully provided technical and economical viable alternatives for present materials. The objective of this study is to investigate the effect of combining clay nanoparticles with polymer solution on oil recovery. This paper includes a history match of both one-dimensional and two-dimensional polymer floods using a three-dimensional numerical model for fluid flow and mass transport. Results indicated that the amount of polymer adsorption decreased when clay nanoparticles were added to the PolyAcrylaMide solution; however, mobility ratio improvement is believed to be the main contributor for the proposed method in order to enhance much oil recovery compared to xanthan flood and HPAM flood.

Magnus Water-Alternating-Gas-Pattern Optimization Through Data Integration

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169167, “Magnus WAG-Pattern Optimization Through Data Integration,” by Demet Erbas, SPE, Matthew Dunning, Timothy M. Nash, David Cox, SPE, John A. Stripe, and Euan Duncan, BP, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12–16 April. The paper has not been peer reviewed. Several studies explored the possibility of improving both areal and vertical sweep efficiency in mature water-alternating-gas (WAG) patterns in the Magnus oil field. Key surveillance data, such as 4D seismic, production-logging-tool (PLT) data, and well performance and openhole saturation logs, have been coupled with simulations to study options for sweep improvement. Optimizing the WAG patterns enables a more efficient use of the available gas, which makes this a more-commercially-viable and –cost-effective tertiary-recovery option. Introduction The Magnus oil field was discovered in 1974 and is on the UK continental shelf of the North Sea. The field started production in 1983 through seven predrilled subsea wells by use of a fixed, steel- jacket platform. The first of the 20 platform well slots was drilled out in 1984, followed by water-injection startup in the same year to provide pressure support and sweep. The plateau production was maintained until 1995 at 150,000 STB/D, and, after 7 years of decline, miscible-gas injection through a WAG scheme started in 2002. In the WAG enhanced-oil-recovery (EOR) scheme, lean hydrocarbon gas is injected. The minimum miscibility pressure is 5,000 psi, which is the current target operating pressure. The average net-gas-use efficiency to date is 3,500 cf/STB. So far, EOR has been implemented in three panels—A3:B3, Central, and South (Fig. 1). This paper focuses on analyzing 10 years of data from running the WAG scheme and on investigating how to improve recovery in mature patterns, specifically in the Central panel.

Plume Migration of Different Carbon Dioxide Phases During Geological Storage in Deep Saline Aquifers

This study estimates the plume migration of mobile supercritical phase (flowing), aqueous phase (dissolved), and ionic phase CO_2 (bicarbonate), and evaluates the spatial distribution of immobile supercritical phase (residual) and mineral phase CO_2 (carbonates) when CO_2 was sequestered. This utilized a simulation, in an anticline structure of a deep saline aquifer in the Tiechenshan (TCS) field, Taiwan. All of the trapping mechanisms and different CO_2 phases were studied using the fully coupled geochemical equation-of-state GEM compositional simulator. The mobile supercritical phase CO_2 moved upward and then accumulated in the up-dip of the structure because of buoyancy. A large amount of immobile supercritical phase CO_2 was formed at the rear of the moving plume where the imbibition process prevailed. Both the aqueous and ionic phase CO_2 finally accumulated in the down-dip of the structure because of convection. The plume volume of aqueous phase CO_2 was larger than that of the supercritical phase CO_2, because the convection process increased vertical sweep efficiency. The up-dip of the structure was not the major location for mineralization, which is different from mobile supercritical phase CO_2 accumulation.