Simultaneous Water And Gas Research Articles

Investigation on immiscible N2 WAG and SWAG after water flooding in the paleo-subterranean river of fractured-vuggy reservoirs

The complex spatial distribution of caves and fractures results in the low oil recovery after water flooding in paleo-subterranean river of fractured-vuggy reservoirs. This paper tries to solve the problem of how to adopt water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) to enhance oil recovery in paleo-subterranean river reservoirs. Aiming at this objective, we constructed one physical experimental and numerical model according to the geological section in Tahe Oilfield. The research on water flooding, WAG, and SWAG were carried out through experiments and simulations. The results show that there were four kinds of remaining oil after water flooding in the paleo-subterranean river karst reservoirs, i.e., blind end remaining oil, shielded remaining oil, attic remaining oil, and corner remaining oil. WAG can extract the shielded remaining oil, attic remaining oil, and part of the corner remaining oil efficiently, while SWAG can only work on the attic remaining oil. In addition, too low injection rate lacked driving force support and restricted the expansion of the swept zone. Too small gas-water ratio and slug size can’t play a good role in gas displacement. This paper is the first systematic study of the paleo-subterranean river reservoirs, and the results can provide a basis for production practice.

A Laboratory Study of Coinjection of Water and CO2 to Improve Oil Recovery and CO2 Storage: Effect of Fraction of CO2 Injected

Summary To determine the effect on oil recovery and carbon dioxide (CO2) storage, laboratory experiments are run with various fractions of CO2 injected (FCI): pure CO2 injection (FCI = 1), water-saturated CO2 (wsCO2) injection (FCI = 0.993), simultaneous water and gas (SWAG) (CO2) injection (FCI = 0.75), carbonated water injection (CWI) (FCI = 0.007), and water injection (FCI = 0). All experiments are performed on Bentheimer sandstone cores at 70°C and 11.7 MPa (1,700 psia). The oil phase is composed of 65% hexane and 35% decane by molar fraction. Before any fluid is injected, the core is filled with oil and irreducible water. Pressure difference across the core and production rate of gas are measured during the experiment. The collected produced fluids are analyzed in a gas chromatograph to determine their composition. Cumulative oil recovery after injection is found to be 78 to 83% for wsCO2, 78% for SWAG, 74% for pure CO2, 53% for CWI, and 35% for water. Net CO2 stored is also found to be the highest for wsCO2 (59 to 65% of the pore volume), followed by that for CO2 injection (56%) and that for SWAG (42%). These results suggest that wsCO2 injection might outperform pure CO2 injection at both oil recovery and net CO2 stored.

Selection of an Optimal Hybrid Water/Gas Injection Scenario for Maximization of Oil Recovery Using Genetic Algorithm

Production strategy from a hydrocarbon reservoir plays an important role in optimal field development in the sense of maximizing oil recovery and economic profits. To this end, self-adapting optimization algorithms are necessary due to the great number of variables and the excessive time required for exhaustive simulation runs. Thus, this paper utilizes genetic algorithm (GA), and the objective function is defined as net present value (NPV). After developing a suitable program code and coupling it with a commercial simulator, the accuracy of the code was ensured using a synthetic reservoir. Afterward, the program was applied to an Iranian southwest oil reservoir in order to attain the optimum scenario for primary and secondary production. Different hybrid water/gas injection scenarios were studied, and the type of wells, the number of wells, well coordination/location, and the flow rate (production/injection) of each well were optimized. The results from these scenarios were compared, and simultaneous water and gas (SWAG) injection was found to have the highest overall profit representing an NPV of about 28.1 billion dollars. The application of automated optimization procedures gives rise to the possibility of including additional decision variables with less time consumption, and thus pushing the scopes of optimization projects even further.

Identifiability of parameters of three-phase oil relative permeability models under simultaneous water and gas (SWAG) injection

We assess the relative performance of a suite of selected models to interpret three-phase oil relative permeability data and provide a procedure to determine identifiability of the model parameters. We ground our analysis on observations of Steady-State two- and three-phase relative permeabilities we collect on a water-wet Sand-Pack sample through series of core-flooding experiments. Three-phase experiments are characterized by simultaneous injection of water and gas into the core sample initiated at irreducible water saturation, a scenario which is relevant for modern enhanced oil recovery techniques. The selected oil relative permeability models include classical and recent formulations and we consider their performance when (i) solely two-phase data are employed and/or (ii) two- and three-phase data are jointly used to render predictions of three-phase oil relative permeability, kro. We assess identifiability of model parameters through the Profile Likelihood (PL) technique. We rely on formal model discrimination criteria for a quantitative evaluation of the interpretive skill of each of the candidate models tested. We also evaluate the relative degree of likelihood associated with the competing models through a posterior probability weight and use Maximum Likelihood Bayesian model averaging to provide model-averaged estimate of kro and the associated uncertainty bounds. Results show that assessing identifiability of uncertain model parameters on the basis of the available dataset can provide valuable information about the quality of the parameter estimates and can reduce computational costs by selecting solely identifiable models among available candidates.

Field-scale simulation of CO2 enhanced oil recovery and storage through SWAG injection using laboratory estimated relative permeabilities

Numerical simulations are widely used to investigate the performance of simultaneous water and gas (SWAG) injection in an oil field. However, they usually use two-phase water and gas relative permeability functions (krg) and one of the known correlations (e.g., Stone, Baker) to calculate oil relative permeability in a three-phase displacement. Moreover, the same krg is used for all SWAG injections, irrespective of miscibility conditions or fraction of gas injected (FGI).Recent experiments have shown that gas relative permeability functions in three-phase SWAG are significantly different from the conventionally used two-phase functions. This paper investigates the impact of using experimentally estimated three-phase gas relative permeability functions on co-optimization study of CO2 storage and enhanced oil recovery (EOR). A three-dimensional, layered reservoir model initially saturated with oil and connate water is used to examine different injection schemes for co-optimizing oil recovery and CO2 storage efficiency. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane by molar fraction. Numerical simulations are run at 70 °C and at three pressures (1300, 1700, and 2100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. SWAG displacements are run at an FGI of 0.5 for immiscible, near-miscible and miscible conditions. Then the effect of FGI dependent relative permeability on co-optimization of CO2 storage and EOR is investigated in the near-miscible condition for FGI values 0.25, 0.5, 0.75 and 1.0.Experimentally estimated three-phase gas relative permeability results in lower CO2 mobility. This leads to higher CO2 saturation and lower water saturation at the end of simulation. The significant increase in CO2 storage efficiency and hence the co-optimization function are more prominent in near-miscible and miscible displacements than in immiscible. Although, for the homogeneous model, ultimate oil recovery is the same when two-phase or experimentally estimated three-phase relative permeabilities are used, ultimate recovery value is significantly affected in the heterogeneous reservoir model.

An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage

Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.

Co-Optimizing Enhanced Oil Recovery and CO2 Storage by Simultaneous Water and CO2 Injection

This paper presents a numerical simulation study to investigate whether simultaneous water and gas (SWAG) injection can co-optimize CO2 storage and enhanced oil recovery. Compositional displacements in a three-dimensional, layered reservoir model are modeled to examine different injection scenarios for maximizing oil recovery and CO2 storage capacity. The effects of various CO2-water ratios and different miscibility conditions on sweep efficiency, incremental oil recovery and CO2 storage capacity are investigated. Compositional changes of oil and gas phases, in the presence of mobile water in immiscible, near miscible or miscible SWAG injection are examined. Simulation results show that SWAG injection can enhance oil recovery compared to waterflooding and continuous CO2 injection by 6 to 21% the original oil in place. The optimum gas fraction in injection fluid increases as miscibility develops. When CO2 is injected simultaneously with water, 30–60% of injected CO2 can be stored with optimum injection ratios depending on the miscibility condition. On the contrary, in continuous gas injection, both oil recovery and CO2 storage capacity increase with miscibility. The simulation results also reveal that, for the reservoir studied, near miscible SWAG injection yields the highest oil recovery and storage efficiency in shortest operating duration.

Applying Fractional-Flow Theory Under the Loss of Miscibility

Summary This paper examines the limits of the Walsh and Lake (WL) method for predicting the displacement performance of solvent flood when miscibility is not achieved. Despite extensive research on the applications of fractional-flow theory, the prediction of flow performance under the loss of miscibility has not been investigated thoroughly. We introduce the idea of an analogous first-contact miscible (FCM) flood to study miscibly degraded simultaneous water and gas (SWAG) displacements using the WL method. Furthermore, numerical simulation is used to validate the WL solution on one oil/solvent pair. In the simulations, the loss of miscibility (degradation) is attributed to either flow-associated dispersion or insufficient pressure to develop the miscibility. 1D SWAG injection simulations suggest that results of the WL method and the simulations are consistent when dispersion is limited. For the 2D displacements, the predicted optimal water-alternating-gas (WAG) ratio is accurate when the permeable medium is fairly homogeneous with a limited crossflow or is heterogeneous with a large lateral correlation length (the same size or greater than the interwell spacing). The results suggest that the accuracy of the WL method improves as crossflow is reduced. In addition, linear growth of the mixing zone with time is observed in cases for which the predicted optimal WAG ratio is consistent with the simulation results. Hence, we conclude that the WL solution is accurate when the mixing zone grows linearly with time.

Revitalizing small offshore oil assets — Field redevelopment feasibility study

During the last two decades, several small size offshore fields in the North Sea have been developed and exploited by tie-in development strategies to existing infrastructure supplied by the nearby large hydrocarbon fields and/or pipeline transportation systems. The field under consideration is such an example. However, achieved oil recoveries lower than expected (~ 18%) led to the abandonment of the asset and removal of the field's supporting fluid transportation lines and cables approximately two years from the onset of oil production. Since then, a change of field ownership and several subsurface studies sparked a new interest of a possible field redevelopment. This work investigates and evaluates the potential standalone field redevelopment of a small North Sea oil field through the deployment of a gas injection process that utilizes the produced gas as the key enhanced oil recovery (EOR) agent. A field-sector, compositional simulation model is constructed to evaluate and compare the most promising gas-based EOR techniques such as continuous gas injection, water alternating gas and simultaneous water and gas injection processes against water injection. Several sensitivity studies are conducted to optimize the conditions/parameters of the selected EOR technique and practical issues that can influence oil recovery factors are evaluated for a potential pilot or field-wide scale implementation. The results indicate that the implementation of a Simultaneous Water and Gas (SWAG) EOR injection process that makes use of the field produced gas and having undergone a thorough and field-wide optimization of operational parameters (produced gas availability, fluids injection rate, injection water–gas ratio, production and injection well BHP, fluids injection scheme, etc.) as well as a careful investigation of potential well interventions to increase oil production (selective re-perforation of existing wells, possible shutoff of excess water, etc.) could be a viable EOR technique for redeveloping this asset.

Injection of Water Above Gas for Improved Sweep in Gas EOR: Nonuniform Injection and Sweep in 3D

Summary In gas-injection enhanced oil recovery (EOR), simultaneous injection of water and gas from parallel horizontal wells with water injected from the upper well [sometimes called modified simultaneous water and gas (SWAG) injection], can give deeper penetration of gas before gravity segregation than SWAG from the same well. Most previous studies of this process were limited to 2D, in which the injection rate is uniform along each well. In 3D, we find that gas injection can be far from uniform, even in homogeneous reservoirs—which are the focus of this study. If gas injection is nonuniform in homogeneous reservoirs, it surely would be so in heterogeneous reservoirs. In some cases, there is an inherent instability in uniform injection along the gas well, even as the water well continues to inject nearly uniformly along its length. In our results, the uniformity of gas injection increases with increasing total injection rate and decreasing vertical distance between gas- and water-injection wells. The instability leading to nonuniform injection depends on the relation between gas saturation and gas relative permeability; we speculate that effects of gas flow on hydrostatic pressure, and therefore on gas-injection pressure, may also play a role. We find that in some cases, lateral movement of gas from the injection point partially mitigates the effects of nonuniform gas injection. Injecting gas from separate, independent segments along the horizontal well improves sweep somewhat by increasing the number of points at which gas exits the well.

A Survey of North Sea Enhanced-Oil-Recovery Projects Initiated During the Years 1975 to 2005

Summary This paper provides a summary and a guide of the enhanced-oil-recovery (EOR) technologies initiated in the North Sea in the period from 1975 until beginning of 2005. The five EOR technologies that have been initiated in this region are hydrocarbon (HC) miscible gas injection, water-alternating-gas (WAG) injection injection, simultaneous water-and-gas (SWAG) injection, foam-assisted WAG (FAWAG) injection, and microbial EOR (MEOR). Each EOR technology that has been initiated in the North Sea was identified with its respective maturity level and/or maturation time frame, technology use restrictions, and process efficiency on the basis of incremental oil. Apart from WAG at Ekofisk and FAWAG at Snorre central fault block (CFB), all technologies have been applied successfully (i.e., positive in economic terms) to the associated fields. HC miscible gas injection and WAG injection can be considered mature technologies in the North Sea. The most commonly used EOR technology in the North Sea has been WAG, and it is recognized as the most successful EOR technology. The main problems experienced were injectivity (WAG, SWAG, and FAWAG projects), injection system monitoring, and reservoir heterogeneities (HC miscible gas injection, WAG, SWAG, and FAWAG projects). Approximately 63% of all the reported EOR field applications have been initiated on the Norwegian continental shelf (NCS), 32% on the UK continental shelf, and the remainder on the Danish continental shelf. Statoil has been the leader in conducting EOR field applications in the North Sea. The majority of future research will concentrate on microbial processes, CO2 injection, and WAG (including SWAG) injection schemes. In this review, laboratory techniques, global statistics, simulation tools, and economical evaluation were not considered and are considered outside of the scope of this paper.

Visualisation of Residual Oil Recovery by Near-miscible Gas and SWAG Injection Using High-pressure Micromodels

We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection. Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous and high-rate gas injection is not possible (e.g. due to supply constraint).