The high CO2 content of Brazil’s pre-salt fields, which may reach values from 20% to 44% molar, presents both a challenge as well as an opportunity. CO2 stripped from the produced gas cannot be released into the atmosphere due to environmental restrictions. Therefore, the whole amount of CO2 produced should be continuously reinjected into the reservoir. This work investigates the effect of CO2 content on the low salinity water alternating CO2 injection technique (CO2LSWAG) using a commercial compositional reservoir simulator. In these field-scale simulations, CO2 is stripped from the produced gas and reinjected into the reservoir. Primary oil recovery methods such as CO2 flooding and LSW flooding are also simulated. Chemical reactions between CO2 and the minerals present in the reservoir are modeled. Wettability change is assumed to be the main mechanism for improved oil recovery due to low salinity water injection. Compositional simulations of CO2 injection usually assume a constant injected gas rate. In this case, CO2 is supposed to come from an external source. In many petroleum reservoirs this assumption is true. Three factors are assessed in the present work. The first one is the natural reservoir pressure, which is the main driving force in primary production. The second factor is the amount of CO2 available for injection. The third one is the wettability change promoted by the reaction involving CO2. It is shown that in primary production, higher CO2 content leads to quicker depletion of the natural energy of the reservoir, leading to lower oil recovery. Nevertheless, higher CO2 content also means that more gas is available for reinjection, potentially leading to increased oil production. Finally, as CO2 reacts with minerals it promotes a change in wettability from an oil-wet to a water-wet state. It is shown that the CO2 content is an important variable to be assessed in a high CO2 content reservoir. Optimal injection practices must take these three aspects into consideration.
As means of primary and secondary recovery, the fractured reservoirs with strong aquifer can be developed either by water injection or by utilizing the natural energy of the aquifer itself. High permeability contrast between fracture and matrix blocks and preferably mixed to oil-wet nature of the naturally fractured reservoirs makes waterflooding and primary methods of production mostly inefficient leaving vast amount of oil unrecovered in the oil-bearing matrix blocks. Due to the absence of a sufficient pressure gradient, wettability of the reservoir rock determines the rate of the displacing fluid invasion into the matrix blocks by capillary and gravity forces. Chemical Enhanced Oil Recovery (cEOR) mechanisms are aimed to intensify oil recovery by affecting these forces. Laboratory and field pilot tests showed the application of surfactant to be a promising cEOR agent for increasing oil recovery from the matrix blocks, both in water-wet and oil-wet fractured reservoirs. For the case studied in this paper, analysis of the surfactant application in the fractured reservoir required the solution of the following challenges: Interpretation and reproduction of the EOR mechanisms by mathematical modelling Adaptation and integration of the EOR effects into the full field model Development of the proper technology for surfactant injection under the given reservoir conditions
Interpretation and reproduction of the EOR mechanisms by mathematical modelling
Adaptation and integration of the EOR effects into the full field model
Development of the proper technology for surfactant injection under the given reservoir conditions
The aim of the paper is to present the discussions and the workflow for analyzing and identification of the surfactant application in the fractured reservoir with strong bottom driven aquifer.
Introduction of the trapping number (accounting the capillary and Bond numbers) as a scaling parameter enabled to evaluate the combined effect of capillary, viscous and gravity forces on oil desaturation. To integrate the trapping number into commercial simulator, a special interface was developed within the scope of this work. The EOR effects of surfactant were evaluated on the single porosity numerical models representing a discretized matrix block.
To upscale the specific recovery mechanism as a mass exchange term into full field dual porosity model a special coupling solution was introduced. A pseudo-capillary pressure is suggested as an intermediate function to translate the recovery mechanism from single to dual porosity model.
The developed innovative technology proposes a special injection and production strategy for more effective areal sweep efficiency as well as alteration of injection water chemistry to drive the surfactant into target areas without high losses into the aquifer.
This technology and the described workflow, both were employed for advanced estimation of surfactant EOR potential in a naturally fractured carbonate reservoir. The surfactant aided recovery mechanism based on transition from capillary to gravity dominated displacement showed enhanced effect on ultimate oil recovery from this reservoir.
A numerical simulation model was designed to evaluate the technical viability of in-situ upgrading using dispersed nanocatalysts in heavy oil reservoirs. Aquathermolysis reactions are represented by a practical kinetic model based on SARA analysis, being consistent with the thermodynamic characterization. With this simplified model, the API gravity enhancement in core-flooding tests was reproduced. The mathematical formulation couples mass and energy transport equations along with a rigorous three-phase equilibrium equation of state. Also, a nanoparticle transport equation was coupled to account for reversible and irreversible non-equilibrium retention, and water-oil partitioning. PVT data were matched successfully, including API gravities and oil viscosities. Reaction rates were adjusted by means of batch-reactor information, while nanoparticle retention was validated using reported single-phase core-flooding tests. Different core-flooding experiments from the literature were reproduced to calibrate the phases transport parameters, and further up-scaled to reservoir conditions. Validation of the model with experimental data suggests that the lumping scheme based on SARA analysis and the modeling of nanoparticle transport and retention, capture the most important phenomena occurring during in-situ upgrading processes. Field-scale simulations, of a sector model from an oil reservoir in the Magdalena Medio Valley basin in Colombia, showed that the in-situ upgrading with nanoparticles can increase the recovery factor up to 5% compared with typical steam injection. However, the oil upgrading achieved in the continuous injection was lower than the one obtained in the core-flooding tests. The numerical model presented in this work, which includes a dynamic nanoparticle retention model, changes on relative permeability alteration due to nanoparticle surface deposition, and a suited kinetic-thermodynamic representation, is able to describe correctly the most relevant phenomena observed during nanocatalysts in-situ upgrading process.
This paper discusses a method for optimizing production and operation for onshore/offshore wells. Optimizing the production of oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to serious operational problems caused by asphaltene deposition. It involves the use of a dynamic flow simulator for modeling oil and gas production systems and reservoir management to determine the feasibility of its economic development. Many studies have focused on relating asphaltene precipitation flocculation and deposition in oil reservoirs and flow assurance in the wellbores. Experimental techniques and theoretical models have been developed trying to understand and predict asphaltene behavior. Nevertheless, some ambiguities still remain with regard to the characterization asphaltene in crude oil and its stability during the primary, secondary, and tertiary recovery stages within the near-wellbore regions.
A synthetic onshore full-field scale that is based on a heterogeneous three-dimensional Cartesian single-well model is considered in this paper. Two wells (a producer and an injector) and one reservoirs are considered to evaluate the dynamic properties under the influence of asphaltene. The size of the reservoir is 25 ft × 25ft × 20 ft and is represented by grid numbers of 50 columns × 50 rows × 5 layers with 12 hydrocarbon components constituting the constant crude composition of this model. The model comprised a total of 12,500 grid blocks. The three-dimensional simulation employed 5-layers, incorporating all relevant production and reservoir data. Different production scenarios were investigated to define the most appropriate and efficient production strategy. This paper provides a method to assess the effect of asphaltene precipitation, flocculation, and deposition in the well productivity and the economic impacts related to it and investigating prevention techniques and other related in-situ pore level flow assurance parameters.
The results will include a comparison of production rates with and without asphaltene precipitation, flocculation, and deposition. In addition, it provides a comparison of asphaltene precipitation, flocculation, and deposition at different times using varying bottomhole and production rate constraints. Several cases (i.e., WAG cycles, completion, target layers of injection, etc.) are tested to help in selection of the optimum completion and operating strategy in the presences asphaltene. The paper will provide insight into factors affecting the flow assurance of oil and gas reservoirs.
Development of oil rim reservoirs is challenging and could lead to low oil recovery, if multiple determining factors are not well understood, that influences successful field development concept. It requires detailed analysis and development of specific procedures to optimize the oil production from a thin oil rim underlaying gas cap. Few IOR/EOR applications for oil rim development have been reported in the literature so far. This study presents a concept for the optimization of oil production from an oil rim reservoir by numerical simulation.
As a starting point, a representative sector of the field was selected for the initial analysis. It was decided to perform IOR/EOR methods including water/gas flooding/injection and surfactant flooding using inverted five-spot horizontal well pattern, for the application in the selected sector. Upon execution of the detailed sensitivity analysis, the pattern was optimized by its characteristic geometric variables including the length of the vertical/horizontal section of the well, the location of the wells, lateral well distances and the orientation of the pattern. The optimization was performed by setting an objective function to improve recovery factor and reduce water/gas cut by using the differential evolution algorithm. The latter was run until converging, and the optimal solution was used to perform further IOR/EOR studies.
Finally, after selection of a base-case scenario and best well pattern, IOR/EOR options were evaluated, and the comparative results were reported. The generated results show that the application of 5-spot horizontal well pattern in the oil rim reservoir could increase the oil recovery by water flooding, but with low sweep efficiency. The losses of injected water into the underlaying aquifer and up laying gas gap are large. Immiscible gas injection into the gas cap can support the pressure but massively increases the gas cut. In addition, displacement efficiency by gas flooding is poor.
Simulation results of the surfactant flooding case shows better displacement efficiency compared to water flooding. Also, the possibility of reducing residual oil saturation could increase the ultimate oil recovery but at very late time.
As part of enhanced oil recovery (EOR) strategic objectives to boost oil recovery towards 70% aspiration and demonstrate EOR as an attractive viable option for environmental Carbon Capture, Utilization and Storage (CCUS) applications, various conventional and novel EOR technologies and applications are being screened and studied to ensure meeting mandated objectives. Accordingly, number of EOR pilots and projects have grown substantially over recent years to ensure derisking the full field expansion uncertainties and challenges, especially in such carbonate reservoirs with harsh conditions of temperature ( 250 F) and salinity ( 200,000 ppm). Detailed screening study and performance review assessment have been conducted, in which gas and chemical based EOR technologies were identified for targeted reservoirs. The candidate reservoirs have a long history of EOR projects focusing on miscible hydrocarbon gas (HC) as early as 1996, which has supported oil production meeting forecast demand. On the other hand, as part of environmental driven strategy for CCUS and EOR applications, CO2 technology has been successfully progressing as EOR business case full-integrated cycle from pilot to field expansion during 2009-2016. In 2016, Al Reyadah has been launched as a unique commercial-scale CCUS facility in the region, that captures 800,000 tonnes of CO2 annually from Emirate Steel Industries and injects it into oilfields to boost crude recovery. Furthermore, novel EOR technologies have been screened and identified with significant potential added value, that includes SIMGAP, SIWAP, Surfactant, Polymer and others, which are currently under modeling and design phase for implementation within upcoming few years to boost recovery factor towards 70% aspiration. Development and piloting of latest technologies are among the main enablers to ensure fit-for purpose applications, proper planning and optimum design for ultimately maximum revenue economically. This paper presents a big-picture overview of EOR technologies with the focus on some cases, challenges and opportunities for super giant carbonate reservoirs. 2 SPE-196693-MS
Enhanced oil recovery ("EOR") by means of CO2 injection has become a globally-used method of increasing oil recovery. Interest in the UAE has increased in recent years due to the proven effectiveness of the process, and due also to government plans to initiate a world-class CO2 capture campaign.
EOR by means of CO2 injection is associated with many challenges. The majority of EOR projects are conducted in onshore fields since offshore EOR experience is limited by technical and operational challenges, as well as by higher economic hurdles. A larger resource base is required to justify an offshore EOR project than a project that is located onshore. Apart from that, the decision to embark on a CO2 injection project is often complicated by the lack of multidisciplinary integration. Uncertainty analysis should be included in the evaluation since it is critical to understanding pilot objectives, identifying model limitations, proper scaling of results from the pilot area to the field, and managing expectations. The economics of the proposed project are strongly dependent on proper baseline definition – possible only by means of advanced methods of reservoir characterization – and by state-of-the-art methods of dynamic reservoir simulation using a fully-compositional model and robust equations of state to characterize the process physics.
The oilfield discussed in this paper is a digitalmulti-reservoir field being developed by horizontal and highly-deviated wells equipped by inflow control devices (ICD). Primary depletion will be augmented by reservoir-specific water injection and hydrocarbon gas injection. Field characterization is being done based on data from comprehensive open- and cased-hole log suites, seismic data, MDT runs, PTA, and an array of SCAL and PVT tests necessary to fully describe the process physics.
The purpose of this paper is to describe the workflow and methods used to design, and estimate the efficiency of a CO2 injection project for a giant carbonate reservoir complex in the offshore area of the UAE. Recommendations for pilot project and surveillance program designs based on best practices and lessons learned from prior projects, developed to overcome the challenges described above, are discussed.
Micromodels are commonly utilized to investigate the fundamentals of multiphase displacements and oil mobilization. Definitely, the utility of micromodels has been well demonstrated in the literature. Yet, while the generic workflows are mutual, there is no standard protocol. Therefore, the primary objective of this work was to develop reliable protocols for micromodel experimentations. These protocols are developed within the context of investigating flow-rate effects on oil trapping and recovery, which represents a supplementary objective.
The presented experimental work utilized a high pressure and high temperature setup. A metalloid pattern with a pore-volume of 0.08 mL constitutes the porous-media micromodel. The model is positioned vertically, which permits investigation of gravity effects. Displacement experiments were performed to establish the image processing workflow. Those experiments were performed at different injection rates for fixed volumes starting from 10 mL up to 50 mL. All experiments were replicated to assess the associated uncertainties. Initial conditions were established via drainage of connate brine by dead crude oil followed by imbibition of injection brine.
The performed experiments established a preferred workflow for image processing that includes in order: thresholding, despeckling, and binary conversion. Thresholding limits were found to be dependent on the camera including its position and focal length. The final binary images can be used for oil recovery estimation based on areal analyses. High rate experiments demonstrated better repeatability. Prolonged injection helped reduce variations in recovery estimates between replicates. At the investigated macroscopic scale and in light of associated uncertainties, recovery was found to be negligibly dependent on injection rate up to a critical flow-rate of around 1 mL/min above which recovery increases with higher injection rates. A trend that is consistent with capillary desaturation.
This paper demonstrates the procedure to establish a micromodel image processing protocol. It also illustrates the possible uncertainties associated with recovery estimates obtained from such images. Finally, key observations and recommendations with respect to the significance of high throughput and replications were uncovered.
Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. The injected gas composition varies between projects, but is typically hydrocarbon gas, sometimes enriched with intermediate components to ensure miscibility, or carbon dioxide in regions such as the Permian Basin, where supply is available at an attractive price.
Miscible nitrogen injection into oil reservoirs, on the other hand, is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. Unlike other injection gases, the minimum miscibility pressure for nitrogen decreases with increasing temperature. In fact, in deep, hot reservoirs containing volatile oil, nitrogen may develop miscibility at a pressure similar to the MMP for hydrocarbon gas or carbon dioxide. The phase behavior is more complicated than what can be captured by correlations and hence requires equation-of-state calculations.
Results from a recent EOR screening study in ADNOC indicate that a couple of high-temperature oil reservoirs in Abu Dhabi may be potential targets for miscible nitrogen injection. This paper discusses key aspects of the EOS modeling. Advanced gas injection PVT data are available to enable a fair comparison between nitrogen, carbon dioxide and lean hydrocarbon gas. In this work, we have modelled and analyzed the phase behavior of two volatile oil systems with respect to nitrogen, hydrocarbon gas, and carbon dioxide injection, as part of a reservoir simulation study, which will be covered in a subsequent publication; see
Jackson, A. C. (Chevron Corporation) | Dean, R. M. (Chevron Corporation) | Lyon, J. (Chevron Corporation) | Dwarakanath, V. (Chevron Corporation) | Alexis, D. (Chevron Corporation) | Poulsen, A. (Chevron Corporation) | Espinosa, D. (Chevron Corporation)
Reservoir management for an economically successful chemical EOR project involves maintaining high injectivity to improve processing rates. In the Captain Field, horizontal injection wells offshore have been stimulated with surfactant-polymer fluids to reduce surrounding oil saturations and boost water relative permeability. The surfactant-polymer stimulation process described herein enables a step change in injectivity and advances the commercialization of this application. This paper explains the damage mechanism, laboratory chemical design, quality control through offshore field execution and data quantifying the results.
Phase behaviour laboratory experiments and analytical injectivity models are used to design a near wellbore clean-up and relative permeability improvement. Three field trials were conducted in wells that had observed significant injectivity decline over 1-3 years of polymer injection. Surfactant and polymer are blended with injection water and fluid quality is confirmed at the wellheads. Pressure is continuously monitored with injectivity index to determine the chemical efficiency and treatment longevity. Oil saturation changes and outflow profile distributions are analysed from well logs run before and after stimulating. Learnings are applied to refine the process for future well treatments.
The key execution elements include using polymer to provide adequate mobility control at high relative permeability and ensure contact along the entire wellbore. Repeatability of success with surfactant-polymer injection is demonstrated with decreased skin in all the wells. The key results include the oil saturation logs that prove the reduction of oil near the well completion and improves the relative permeability to aqueous phase. The results also prove to be sustainable over months of post-stimulation operation data with high injectivity.
Injectivity enhancement was supported by chemical quality control through the whole process. From laboratory to the field (from core flood experiments to dissolution of trapped oil near wellbore), surveillance measurements prove that the chemical design was maintained and executed successfully. The enhanced injectivity during clean-up allows for higher processing rate during polymer injection and negates the need for additional wells.
The application of surfactant-polymer technology can rejuvenate existing wells and avoid high costs associated with redrilling offshore wells. This improves processing rate for EOR methods and can even be applied to waterflood wells to improve the injectivity, e.g low permeability reservoirs.