Al-Shammari, Asrar (Kuwait Oil Company) | Gonzalez, Fabio A (BP Kuwait) | Gonzalez, Doris L (BP America) | Jassim, Sara (Kuwait Oil Company) | Sinha, Satyendra (Kuwait Oil Company) | Al-Nasheet, Anwar (Kuwait Oil Company) | Datta, Kalyanbrat (Kuwait Oil Company) | Younger, Robert (BP Kuwait) | Almahmeed, Fatma (Kuwait Oil Company)
Magwa-Marrat reservoir fluid is an asphaltenic hydrocarbon, exhibiting precipitation and deposition of asphaltene in the production system including the reservoir rock near wellbore and the tubing. The main objective of this work was to optimize production in Magwa-Marrat wells by remediation of tubing plugging and formation damage. Well interventions were prioritized based on potential production benefit resulting from the removal of productivity impairment. It was required to understand current formation damage in all wells, including those without recent pressure transient analysis (PTA).
All PTA tests since 1983 for Magwa-Marrat reservoir were analyzed to determine the different reservoir parameters such as flow capacity (KH), Skin (S), reservoir boundaries, and the extrapolated reservoir pressure (P*). PTA derived permeability was compared to log derived permeability to quality control skin determination. Independently formation damage was estimated using the radial form of the solution of the diffusivity equation for pseudo steady state flow. Once a skin correlation for both PTA vs. Darcy's law equation was derived using out of date well performance, the formation damage for all wells was accessed using current productivity index to identify production optimization opportunities in wells without recent PTA. This work was combined with nodal analysis to separate vertical lifting performance and inflow performance relationship impact on total productivity detriment.
Cross plot of PTA derived flow capacity (Kh) vs. Log derived Kh correlates very well with a slope and a coefficient of correlation close to 1.0. This was observed for wells located in the reservoir where there are not heterogeneities near wellbore such as boundaries or natural fractures. For these cases the higher than normally observed estimated skin explained poorer well productivity. After skin values were accessed for all wells, a production gain was estimated, and the wells were ranked based on potential benefit. A stimulation campaign was put in place based on the type of rock, formation damage and vertical lifting performance. Eight (8) wells were stimulated and they delivered approximately an additional 20% production for the field.
This work was innovative in the sense that there was not pressure build up tests run prior to the interventions and such, there was not any production deferral. This was achieved by building the well performance understanding on a correlation that required petrophysical description, production rates and estimates of drainage area reservoir pressure.
Reservoir fluid properties play a crucial role in the upstream field development cycle. Petroleum engineers extensively utilize Pressure-Volume-Temperature (PVT) studies in applications such as calculations of pipelines’ pressure drop, and assessment of Enhanced Oil Recovery (EOR) strategies. These studies are generated from a series of lab experiments conducted on reservoir fluid samples in high pressure-high temperature (HPHT) lab environments, and commonly matched using Equation of State (EOS) software.
Feeding and characterizing the composition of a reservoir fluid in a PVT software play a central role towards understanding its behavior. These steps are heavily affected by the last carbon number measured and the lumping scheme used in the simulator. This paper investigates the application of splitting the plus fraction, and utilizing Saturates, Asphaltenes, Resins and Aromatics (SARA) analysis in enhancing viscosity prediction at atmospheric conditions.
In this study, three oil samples from fields with suspected flow assurance issues were selected. A fingerprint study was first conducted on all samples to ensure that they are representative of the original reservoir fluid, and free of any drilling fluid contaminants. The methodology used in this study is based on conducting compositional analysis and viscosity test on the selected samples. Furthermore, SARA analysis was conducted to enhance the characterization of reservoir fluid, and confirm asphaltene presence. Lastly, splitting technique and SARA-based lumping scheme were used to predict viscosity values at atmospheric pressure and were compared to experimental data.
The results of this work demonstrated the effectiveness of SARA-based lumping scheme on atmospheric viscosity prediction, which captured the plus fraction concentrated in the dead oil without compromising the computational time. Furthermore, the EOS software used studied the sensitivity of the simulation results to different compositions.
Carbon dioxide (CO2) injection has recently been applied as an enhanced oil recovery (EOR) method to increase oil recovery from unconventional shale reservoirs. Many interactions will impact the success or failure of this EOR method. This research experimentally investigates the impact of two of these interactions, including asphaltene pore plugging and CO2 adsorption, on the success of CO2 EOR in unconventional shale reservoirs. Two sets of experiments were designed to study the asphaltene pore plugging and CO2 adsorption. The impact of varying CO2 injection pressure, temperature, oil viscosity, and filter membrane pore size on asphaltene pore plugging was investigated. Pertaining to the adsorption experiments, the impact of varying CO2 injection pressure, temperature, and shale particle size was investigated. Asphaltene pore plugging was found to be extremely severe especially in the smaller pore sizes, which indicates that asphaltene poses a serious problem when producing from unconventional nanopores. As the oil viscosity decreased, the asphaltene concentration in the oil decreased as well which made the asphaltene pore plugging less severe in the lower viscosity oils. The thermodynamic conditions, including pressure and temperature, also had a strong impact on asphaltene stability and pore plugging. When undergoing the CO2 adsorption experiments, it was found that increasing the CO2 injection pressure resulted in an increase in adsorption capacity to a certain limit beyond which no further adsorption will be possible. Increasing the temperature resulted in the CO2 molecules becoming highly active which in turn resulted in a decrease in the adsorption capacity significantly. Since experiments were conducted using shale particles, as opposed to an actual shale core, it was important to investigate the accuracy of the results by varying the shale particle size. It was found that as long as the void space volume was measured accurately using helium, the shale particle size had a negligible effect on the adsorption values. This research systematically investigates the impact of two significant interactions on the success of CO2 injection in unconventional shale reservoirs, and studies the impact of several factors within these interactions to determine the extent to which they may influence the success of this EOR method.
Sabet, Nasser (University of Calgary) | Mohammadi, Mohammadjavad (University of Calgary) | Zirahi, Ali (University of Calgary) | Zirrahi, Mohsen (University of Calgary) | Hassanzadeh, Hassan (University of Calgary) | Abedi, Jalal (University of Calgary)
This work focuses on modeling the miscible viscous fingering in porous media accounting for asphaltene precipitation and deposition. The mass balance equations for solvent and asphaltene are defined, and the highly nonlinear system of equations is solved numerically through hybridization of compact finite difference and pseudo-spectral methods. We explain how asphaltene precipitation and the resulting formation damage influence the growth of viscous fingers.
To conduct our analysis, we use the experimental data for the amount of asphaltene precipitation at different solvent mass fractions and also oil viscosity at various asphaltene and solvent contents. This data is measured in our lab and is used as input for the nonlinear numerical simulations. For these simulations, the conventional finite difference schemes cannot be applied as they suffer from the excessive computational time and most importantly, numerical dispersion. Therefore, we employ hybrid techniques to benefit from the high accuracy of spectral methods and capture the nonlinear dynamics of fingerings on very fine grids.
Hydrocarbons such as light n-alkanes are widely used as diluents in the production and upgrading of heavy oils. The addition of a diluent to heavy oil or bitumen alters the chemical forces acting within the mixture, leading to the precipitation of asphaltenes. It is hypothesized that precipitation of asphaltene from oil changes the viscosity behavior of the mixture, influences the dynamics of viscous fingering, and therefore affects the oil recovery. Moreover, asphaltene deposition alters the porosity and permeability of the porous media and might modify the flow paths, leading to possible formation damage. Our results show that asphaltene precipitates are mostly accumulated in the contact interface between the solvent and oil. The major asphaltene deposition occurs along the growing fingers leading to permeability reductions up to 30% in the studied cases.
Yonebayashi, Hideharu (INPEX CORPORATION) | Iwama, Hiroki (INPEX CORPORATION) | Takabayashi, Katsumo (INPEX CORPORATION) | Miyagawa, Yoshihiro (INPEX CORPORATION) | Watanabe, Takumi (INPEX CORPORATION)
CO2 injection is one of widely applied enhanced oil recovery (EOR) techniques, moreover, it is expected to contribute to the climate change from a viewpoint of storing CO2 in reservoir. However, CO2 is well known to accelerate precipitating asphaltenes which often deteriorate production. To understand in-situ asphaltene-depositions, unevenly distributed in composite carbonate core during a CO2 flood test under reservoir conditions, were investigated through numerical modelling study.
Tertiary mode CO2 core flood tests were performed. A core holder was vertically placed in an oven to maintain reservoir temperature and to avoid vertical segregation. A composite core consisting of four Ø1.5" × L2.75" plug cores, which had similar porosity range but slightly varied air permeabilities, was retrieved from a core holder after the flooding test. The remaining hydrocarbon was extracted by Dean-stark method, and heptane insoluble materials were extracted from each plug core via IP-143 method to observe distribution of asphaltene deposits. The variation of asphaltene mass in plug cores was investigated to explain its mechanism thermodynamically.
The core flood test was completed to achieve a certain additional oil recovery by 15 pore volume CO2 injection without any unfavorable differential pressure. The remaining asphaltene mass in each plug core revealed a trend in which more asphaltene collected from the inlet-side core. We assumed a scenario to explain the uneven asphaltene distribution by incorporating the vaporized-gas-drive and CO2 condensing mechanism. Namely, asphaltenes deposited immediately when pure CO2 contacted with oil. The contact between more pure CO2 and oil might be more frequently occurred in inlet-side core. To reproduce the scenario, a cubic-plus-association (CPA) model was generated to estimate asphaltene precipitating behavior as injected gas composition varied. In the first plug core, more pure CO2 gas was considered to contact with fresh reservoir oil compared with the downstream cores which might have less pure CO2 because of its condensation. The light-intermediate hydrocarbon gas vaporized by CO2 was also considered to emphasize the trend of more asphaltene deposits in upstream-side cores. The CPA model revealed consistent phenomenon supporting the scenario.
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.
For many projects, asphaltene management plans are a matter of remediation or prevention. In the past decade, models have been developed to predict how asphaltene particles will behave in oil—the conditions under which precipitation and agglomeration occur. Rice University has been working on effective models of phase behavior and asphaltene deposition as a path to improved design that can reduce this challenge for operators. As the world's supply of crude becomes heavier, many of the world’s oil producers will have to think more carefully about heavy crudes and the challenges they pose for processing, storage, and transportation.
Tar and bitumen deposition can be upstructure, or at the oil-water contact or various locations in-between. Tar can be impermeable and might or might not be a regional seal. In other cases, tar zones can be highly permeable flowing light oil. Tar can have the rheology of coal, or can flow (or ooze). The recent development of the Flory-Huggins-Zuo equation of state (FHZ EoS) for asphaltenes, with its reliance on the Yen-Mullins model of asphaltenes, has led to a simple, concise form of asphaltene thermodynamics, thereby enabling a 1st-principles approach addressing tar deposition and tar mats.