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Collaborating Authors
Precipitates (paraffin, asphaltenes, etc.)
Asphaltene Flow Assurance Pre-Risk Evaluation Case Study to Establish Guidelines for CCUS in Arabian Gulf Carbonate Oil Field
Tange, Masaaki (INPEX CORPORATION) | Hiraiwa, Takeshi (Japan Oil Development Co., Ltd.) | Khlaifi, Khuloud Tareq (ADNOC Offshore) | Sakurai, Risa (ADNOC Offshore) | Bahri, Sami (ADNOC Offshore) | Abed, Abdalla Abdelfattah (ADNOC Offshore) | Uematsu, Hiroshi (ADNOC Offshore) | Makishima, Ken (ADNOC Offshore) | Inokuma, Yuto (ADNOC Offshore) | Sawata, Masaru (INPEX CORPORATION) | Alkaabi, Sultan Hamdan (ADNOC Offshore) | Yonebayashi, Hideharu (Japan Oil Development Co., Ltd.)
Abstract Carbon dioxide capture, utilization and storage (CCUS) has been recognized as a key technology to reduce CO2 emission. Among various CCUS technologies, CO2 enhanced oil recovery (EOR) has been widely implemented at an industrial scale in the E&P sector. However, it is well-known that CO2-mixed oil would cause asphaltene precipitation resulting in flow assurance troubles. Therefore, more advanced asphaltene-risk-managing technology can be an enabler to improve robustness of CCUS projects. This paper presents a case study for a comprehensive series of asphaltene flow assurance pre-risk evaluation in Arabian Gulf Carbonate Oil Field at where the CO2 EOR is recognized as one of the highest potential technologies for full-field implementation. At first, sampling location was carefully selected considering the target reservoir's feature because the reliability of asphaltene study highly depends on sample representativeness. After the QA/QC of collected sample, asphaltene onset pressures (AOP) were measured at multiple temperatures under the CO2 mixing conditions in a straightforward experimental-design optimizing manner so that not only the evaluation accuracy could be improved but also the experimental cost could be minimized. The AOP measurements showed clear potential risks associated with CO2 injection. Subsequently, the numerical model analysis was conducted with Cubic-Plus-Association (CPA) EoS model to identify the risk area during CO2 injection. The analysis suggested that a risk would be caused at not only near-wellbore region at the sampling location but also tubing section / surface facility, furthermore, more seriously at the deeper location of target reservoir. Finally, CO2-induced asphaltene formation damage risk was investigated from the viewpoints of precipitated asphaltene particle size and pore throat size in the porous media. As a result, the clogging risks by CO2-induced asphaltene were estimated high in the target reservoir. By virtue of the above comprehensive series of pre-risk evaluation, the asphaltene flow assurance risk associated with CO2 injection was identified field-widely. The evaluation findings suggested moving on to future actions such as more detailed formation damage risk evaluation and mitigation plan development. The phased approach for evaluating asphaltene flow assurance risk and the reverse engineering of sampling operational design from the experimental design made a worthy demonstration to reduce unnecessary cost and time while obtaining the key information to drive the project. The procedure in this work can contribute to establish a subsurface part of guideline for CCUS from viewpoints of asphaltene flow assurance risk evaluation.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Asphaltene precipitation can sometimes pose operational problems in medium-light oils because of the low asphaltene solubility. The purpose of this work is to develop a methodology to predict the asphaltene envelope for all fluid systems in ADNOCโs reservoir portfolio based on existing laboratory experiments. Such a model would then be able to predict potential precipitation risks for current and future field development projects, especially the ones involving gas injection. The starting point for development of the predictive model for asphaltene onset pressure (AOP) is the 100+ lab measurements carried out over several decades, of which 65% involve a number of injection gases such as CO2, lean and rich hydrocarbon gas, as well as sour gas. We then matched each data set with an equation of state (EOS) to generate the entire onset pressure envelope. Based on the envelope data points, we applied a data-driven method to reproduce the key trends, and used this trained model as a novel predictive tool for new production scenarios without experimental AOP data. We first tested the PC-SAFT model for our phase behavior calculations but found that the method, as implemented in the software package, often experienced convergence problems. The PR-78 cubic EOS was found to be more reliable with the ability to match the experimental data despite limited predictive power. We find that availability of AOP data for reservoir fluids swollen with injection gas makes the thermodynamic model much more robust compared to tuning to a few AOP data on the original reservoir fluid alone. A single AOP point is generally not sufficient to fully constrain the EOS model unless model parameters from other studies are brought into use. SARA analysis is not mandatory for the EOS tuning itself and was found not to be required for training any of the data-driven methods. We limited the predicted data sets to temperatures below 350 ยฐF, since all our reservoirs have temperatures below this threshold. From the calculated envelopes, we saw a clear impact of fluid composition on the shape of the AOP curve relative to the saturation pressure curve, as expected. We now have a tool, which can accurately predict the AOP curve for a combination of reservoir fluids and injection gases, as the long as the injection gas composition remains within the range tested experimentally.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.62)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- (2 more...)
Distribution Mechanism of Asphaltene Deposits in CO2 Flooding Path: Interpretation by Numerical Model Based on Experimental Observation
Yonebayashi, Hideharu (INPEX CORPORATION) | Iwama, Hiroki (INPEX CORPORATION) | Takabayashi, Katsumo (INPEX CORPORATION) | Miyagawa, Yoshihiro (INPEX CORPORATION) | Watanabe, Takumi (INPEX CORPORATION)
Abstract 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 ร1.5" ร 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.
- Asia > Middle East > UAE (0.29)
- North America > United States > Oklahoma (0.28)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract 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 ร 25ft ร 20 ft and is represented by grid numbers of 50 columns ร 50 rows ร 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.
- Asia > Middle East (0.46)
- North America > United States (0.28)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Reevaluation of Asphaltene Precipitation Risk Depending on Field Operational Condition Change/Variation: Case Study Comparing Risks in Past 2008 and Present 2016 for Future Prediction
Takabayashi, Katsumo (INPEX) | Shibayama, Akira (ZADCO) | Yamada, Tatsuya (INPEX) | Kai, Hiroki (INPEX) | Al Hamami, Mohamed Tariq (ZADCO) | Al Jasmi, Sami (ZADCO) | Alrougha, Hamad Bu (ZADCO) | Yonebayashi, Hideharu (INPEX)
Abstract The objective of this paper is to overcome the asphaltene risk evaluation usually conducted snapshot basis. We evaluate the temporal change in the asphaltene risks as gas injection proceeds. In reservoirs under gas injection, in-situ fluid component gradually changes by multiple contacting with the injection gas. Those compositional changes affect asphaltene stability and bring difficulty into the risk predictions by asphaltene models. This study aims to reduce the risk uncertainty depending on operational condition changes. Periodical upgrading of asphaltene model is essential for understanding the time-depending changes of asphaltene risks. In the previous study (Yonebayashi et al. 2011), the asphaltene risk was evaluated for an offshore oil field in the Arabian Gulf in 2008 by use of cubic-plus-association equation of state (CPA-EoS) models on the basis of all available date at the time. After the previous study, additional experimental data was accumulated forthe future gas injection plan. Then, the update study was performed by incorporating those newly collected data. Subsequently, both findings in the past and the present were compared with each other. According to the previous study recommendation, additional asphaltene laboratory studies were conducted on the basis of newly collected samples. All Asphaltene On-set Pressure (AOP) detected from the new samples were higher than those of the previous study. Especially, a large difference was observed from the past/present results of the lower reservoir's AOPs even though samples collected from the identical well. Asphaltene precipitation risk was observed to increase largely because the new AOP was detected at the reservoir temperature while no AOPs detected in the previous study. The difference might be occurred by saturation pressure increase. Then, the numerical asphaltene models were revised, and accordingly, the asphaltene risk estimation were updated higher in the lower reservoir. For the upper reservoir, the past/present AOPs were slightly changed to become higher. The reference sample fluids were collected from two different wells showing minor difference of asphaltene contents. Those variations might be caused by geological heterogeneity that could affect on fluid maturity. Then, the risk rating was updated to be slight higher, too. In this paper, through the comparison between the previous and current studies, it was pointed out the importance of regular monitoring asphaltene risks. This study provides the valuable findings of time-lapse evaluation of asphaltene precipitation risks for reservoir under gas injection. The evaluations currently conducted in the industry are snapshots of instantaneous risks. Through entire field life, the risks have varied depending on operating conditions. This study argued the risk-change in the unique field by the identical workflow but using each representative data collected at different times. Finally, this study demonstrated the importance of time-depending fluid dynamics.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Production and processing operations of crude oil require a thorough understanding of phase behavior. To model asphaltenes, we need to know more about their phase behavior. The model has to incorporate the interaction of asphaltene and oil in terms of solubility in oil and the suspension characteristics attributed to resin. This paper reports a comprehensive phase behavior study for five wells from the Middle East was performed as part of an asphaltene precipitation study. The study outlined several important concepts and detailed procedures for modeling asphaltene phase behavior using WinProp, which uses the Nghiem model for asphaltene precipitation
- Europe (1.00)
- Asia > Middle East (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Integrated Numerical Simulation for a Giant, Asphaltene Riched, Carbonate Reservoir
Bingyu, Ji (Sinopec Petroleum Exploration and Production Research Institute) | Peiqing, Lian (Sinopec Petroleum Exploration and Production Research Institute) | Xuequn, Tan (Sinopec Petroleum Exploration and Production Research Institute) | Taizhong, Duan (Sinopec Petroleum Exploration and Production Research Institute)
Abstract Fah reservoir in Y oilfield is a giant, pore-typed, carbonate reservoir, which have high heterogeneity and asphaltene deposition during production process. In order to describe the heterogeneity of Fah reservoir, fomulas of pore throat radius, porosity and permeability under different mercury injection saturation was fitted. It shows 30% is the best percentile, and R30 method was presented for rock typing. Six rock types were divided according to pore throat radius, the porosity-permeability relationship was established for each rock type. The rock types of the non-cored wells are predicted by KNN (K nearest Neighbor) method. After the rock types of all wells have been obtained, 3D rock type model was built by sequential indicator simulation, and the 3D porosity could be established on the basis of the rock type model, logging interpretation and sesmic data. 3D permeability model was calculated according the relationship between porosity and permeability. Comparing core permeability and calculated permeability obtained by the rock types, it shown very good coincidency. During the oilfield development process of Fah reservoir, the asphaltene deposition is very serious, which cause the production decline. Therefore, it is quite necessary to carry out the asphaltene deposition study. Based on the experiment research, the phase behavior of the asphaltene was studied, and the asphaltene precipitation envelope diagram was drawn on the basis of the gas-liquid-solid three-phase equilibrium theory. A fine numerical simulation model to simulate asphaltene precipitation, flocculation, deposition and damage processes was established, the impact of asphaltene on recovery was studied and the recovery of 10 years was declined by 2.3% in considering asphaltenes. By controlling the bottomhole pressure, the asphaltene precipitation in the formation could be prevented. In order to study the asphaltene depostion in the wellbore and the surface pipeline, a reservoir, wellbore and surface pipeline integrated model was built by coupling the Eclipse and IPM software together, and the pressure and temperature from reservoir to separator can be predicted, then compared with precipitation envelope diagram, the location of asphaltene precipitation could be determined accurately.
- North America > United States > Texas (0.46)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- South America > Colombia > Tolima Department > Magdalena Upper Valley Basin > Abanico Block > Abanico Field (0.99)
- North America > United States > Colorado > Spindle Field (0.99)
- Asia > Middle East > Iraq > Zagros Basin (0.99)
- Asia > Middle East > Iran > Zagros Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (2 more...)
Abstract Reservoir simulation is an integrated tool for predicting reservoir performance and proposing development plans. However, in the master development plan (MDP) proposed based on the simulation results, there is always an associated risk that must be minimized. This risk arises from many different sources, one of which is the complexity in petroleum reservoir fluid. On the other hand, asphaltene precipitation and deposition can dramatically affect the reservoir rock and fluid properties. Asphaltene deposition may cause severe problems during different stages of oil recovery and can affect the reservoir performance through porosity and permeability reduction and wettability alteration. These effects can be modeled in compositional simulation using parameters that are usually estimated from precipitation tests and core flooding deposition experiments. Through a series of experiments, the asphaltene stability envelope and permeability impairment are established for several bottomhole live crude oil and reservoir core samples during pressure depletion and gas injection processes. Using the parameters obtained from the experiments, precipitation and deposition of asphaltene are investigated at field scale by a compositional simulator, and a comprehensive development plan is suggested for the reservoir. Also, the effect of asphaltene deposition on fracture parameters is investigated. The results show that dynamic and static parameters of asphaltene precipitation and deposition play an important role in the prediction of formation damage and field performance during natural depletion, gas injection and water flooding. Moreover, the results confirm that the permeability reduction due to asphaltene deposition is more considerable in the fractures than in the matrix media.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.87)
Abstract Asphaltene precipitation and deposition problems are one of the severe problems which some reservoirs may face with them during their production life. Asphaltene deposition can affect on reservoir performance such as porosity and permeability reduction, wettability alteration, moreover it may lead to plugging of wellbore and production surface facilities. These effects can be modeled by consideration some asphaltene control parameters by activation asphaltene option in compositional simulation package. These parameters are usually estimated from core flooding experiments. This paper mentions the concept of asphaltene modeling and its related parameters and also describes the numerical study results of the effect of asphaltene precipitation and deposition control parameters on reservoir performance, by using a compositional simulation model with asphaltene modeling options. For this purpose, the real reservoir geology model and fluid data are used. After tuning the equation of state (EOS) by analyzing the oil properties data and setting the asphaltene control parameters, the simulation model is built by incorporation of the EOS for asphaltic oil properties and the asphaltene parameters into the compositional simulation model. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment. Also, it can show the resulting reduction in porosity and permeability and changes in oil viscosity and rock wettability according some range of asphaltene control parameters. The model is used to investigate the effects of these parameters selection on reservoir performance, including oil production, recovery factor and average reservoir pressure, also, asphaltene behavior including precipitation, flocculation, adsorption, plugging and entrainment, moreover, formation damage and its effect of rock wettablity changes. The results show the effect of the asphaltene precipitation and deposition parameters selection on reservoir performance clearly, so it should correctly calibrate and carefully use them for modeling. Also, for reservoir that does not have any asphaltene core flooding experiment, they will be useful for estimating the asphaltene model input parameters and its effect on simulation results.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.48)
- Reservoir Description and Dynamics > Fluid Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)