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Collaborating Authors
Flow Assurance
Abstract Carbon dioxide storage in high viscosity and density hydrocarbon reservoirs that have high asphaltenes content is attractive. However, CO2 is an asphaltenes insoluble solvent, hence, CO2 injection into these reservoirs is expected to cause asphaltenes deposition. In pore-scale, how the deposition of asphaltenes would impact the CO2 trapping and consequently CO2 storage is not known. This study proposes highly efficient trapping and storage of CO2 in high-asphaltenes content reservoirs. Our recent experimental studies on CO2 flooding into bitumen reservoirs revealed with Scanning Electron Microscopy (SEM) images that CO2 gets trapped in asphaltenes phase. The CO2 trapping is occurred both in residual and displaced oil due to mainly the presence of clays in the reservoir rock. The CO2-displaced oil interaction promotes the formation of foamy oil. As the size of the CO2 bubbles in the displaced oil increases, the CO2 storage capacity of the displaced oil is enhanced. The bubble size is mainly controlled by the CO2 injection rate and the bigger CO2 bubbles in the displaced oil are obtained at lower CO2 injection rate. Hence, CO2 trapping in high asphaltenes content reservoirs can be more effective if the oil reservoir has high clay content and when CO2 storage is achieved through low injection rates. However, because low injection rates provide more interaction time for asphaltenes and CO2, asphaltenes deposition may occur near injection well and deposition of asphaltenes may inhibit the further propagation of CO2 which may limit the reservoir CO2 storage capacity. It should be also noted that the optimum CO2 injection rate for storage purpose can be different for every reservoir and hence, should be determined experimentally.
- South America (0.94)
- North America > United States > New York (0.31)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.49)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.91)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.70)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.49)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- 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)
- (4 more...)
Onset of the Asphaltene Flocculation and Asphaltene Hydrodynamic Radius Determination Using H-Diffusion- Ordered Spectroscopy DOSY NMR
Sandoval, M. I. (Universidad de Santander, Grupo de Investigación Recobro Mejorado) | Muñoz Navaro, S. F. (Universidad de Santander, Grupo de Investigación Recobro Mejorado) | Molina Velasco, D.. (Universidad Industrial de Santander)
Abstract During EOR recovery processes, asphaltenes macromolecules can flocculate and cause drastic changes in the petrophysical properties of the reservoir, therefore it is very important to determine the time at the flocculation begins and further the size of the aggregates, since ultimately this depends on whether these can be trapped in the porous media. This work aims to evaluate the change in the asphaltene hydrodynamic radius of at different concentrations of n-heptane and to detect the onset asphaltene floculation using a new technique known as 1H Diffusion ordered spectroscopy-NMR (DOSY-NMR). H-DOSY NMR is a method based on the pulsed field gradient spin-echo from nuclear magnetic resonance (PFGSE NMR) and it allows the identification of the molecular components of a mixture sample and at the same time obtain information of their size through the diffusion coefficient. For our specific case, the asphaltene hydrodynamic radius was 16.8 Å and the onset of asphaltene floculation can be observed when the concentration of solvent n-heptane was 30 wt %.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.65)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.60)
- 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 Asphaltene self-association and precipitation are unfavorable processes that can occur during production, transportation, and storage of crude oils. The primary mechanisms of asphaltene self-association are dispersion interactions, electrostatics interactions, hydrogen bonding, and orientation-dependent repulsive steric interactions. This process consists of sequential steps initiating with nano-aggregation of five to six asphaltene molecules and continues by increasing its concentration into formation of clusters. Further augmentation of asphaltene dosage leads to formation of asphaltene micro-aggregates that are detrimental to oil rheological behavior. However, a more detailed and comprehensive interpretation is required to determine the contribution of each mechanism in aforementioned steps. In the present work, asphaltene samples from a light crude oil have been accordingly fractionated by various precipitants and analyzes chemically in various solvents by none-fragmenting techniques such as matrix-assisted laser desorption/ionization (MALDI). Influences of heteroatoms on asphaltene precipitation mechanisms and molecular weight were assessed by conducting elemental analysis. Sensitivity of asphaltene constituents stacking to extraction methods were evaluated by curve deconvolution and fitting routines of X-ray diffraction (XRD) patterns of solid asphaltenes. Finally, asphaltene precipitation onsets were determined for various asphaltene samples and conditions by using near-infrared (NIR) spectroscopy technique. Results of the current study reveal the substantial impacts of various precipitants and solvents on asphaltene aromaticity and its propensity toward self-association. Also, the results indicate that alteration of the extraction methods is conducive to variation in asphaltene molecular weights as well as precipitation onset points. Alteration of critical aggregate concentration (CAC) and critical micelle concentration (CMC) were observed from NIR results and were used to determine asphaltene stability. Current study proposes further understanding of asphaltene self-association and aggregation mechanisms. Concrete understanding of these mechanisms leads to designing more efficient asphaltene dispersants and heavy oil viscosity modifiers to prompt higher oil recovery and facilitate transportation processes.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
Abstract There is a well-known theoretical chart that shows how compression, scales, liquid loading, corrosion, etc. appear as a gas field decreases production due to reservoir depletion. The approach of this paper is ambitious and will demonstrate and exemplify how these problems appeared in our gas field, and share the techniques, methods, and procedures we went through to satisfactorily handle them. This paper shows the development of a gas field placed in the Golfo San Jorge Basin (Argentina) including the different life stages of the field (High/Medium/Low Pressure) with the related problems in Facilities, Flow Assurance, and Liquid Loading, and finalizes with an introduction to the future problems we are expecting. Throughout the paper, we will show the changes we went through, lessons learned, and conclusions related to the following topics: + Facilities → Slugging in flowlines/changes in suction pressure/new facilities + Flow Assurance → Chemical usage for solving organic and inorganic scales. Need of migration from bullheading treatments to CT nitrogen assisted operations. Acid stick treatments. + Liquid Loading → Foaming agents/Velocity Strings/Capillary Strings/Wellhead Compression + Tendency of Scales Evolution in produced water. + Evolution of tubing metallography + New approaches in PLT interpretation Not many papers cover in such an integral way the development of a conventional gas field with a large exploitation history as this work does, where the field dates from the 2000s. This paper sets a reference and fills a gap in terms of an overall look at all problems together, and integrates the theory from the literature, information from field experiences, best practices, and the application of new technologies/methodologies. Challenges for future exploitation are presented as well. Reading this paper will help in understanding the complexity that those people involved in the management of a gas field will face as their reservoirs deplete and the production of the wells goes down.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Sierra Chata Field (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > Trahuil Field (0.99)
Abstract Stability of asphaltenes is affected mainly by the change in pressure and temperature within the reservoir or in production lines. Destabilized asphaltenes results in several flow assurance problems due to their higher precipitation tendency. While there are numerous studies investigating the role of pressure and temperature on asphaltenes stability, the role of reservoir components on asphaltenes stability still remains unknown. Hence, this study investigates the effect of reservoir rock-asphaltenes interaction on asphaltenes stability. 11 different crude oil samples from all around the world and their asphaltenes were analyzed. Both n-pentane and n-heptane asphaltenes surfaces were visualized under scanning electron microscope (SEM). Inorganic (mainly salts and clays) presence was observed on asphaltenes surfaces, which might be the consequence of the reservoir rock-oil interaction. Thus the inorganic content of separated asphaltenes were investigated by mixing asphaltenes and deionized water vigorously by a centrifuge to separate the inorganic content of asphaltenes from asphaltenes’ surfaces. The supernatant of these mixtures was subjected to total dissolved solids (TDS), pH, and conductivity measurements. The TDS level was observed high which proves the physical interaction of asphaltenes with reservoir rock and this interaction is also found to generate high conductivity mainly due to sodium salts. The electrostatic charges created in water due to inorganic content of asphaltenes were determined by zeta potential. Precipitation tendency of the colloids were found very high for most of the asphaltenes samples and they are mainly because of the presence of excessive amount of negatively charged particles. Particle sizes of those particles were also measured high which increases the chances of the particles to come together for precipitation. This study proves the presence of electrical charges on asphaltenes surface and highlights its importance on asphaltenes stability.
- South America (0.68)
- North America > United States > Texas (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (0.68)
- Geology > Petroleum Play Type > Unconventional Play (0.48)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.93)
Sand Production Risk Evaluation and Sand Control Screening, the Complete Workflow for the Future Development of the Oglan Field - Ecuador
Andrade, A.. (AGIP Oil Ecuador BV) | Correa, R. H. (AGIP Oil Ecuador BV) | Atahualpa, G. E. (AGIP Oil Ecuador BV) | Ripa, G.. (Eni E&P) | Brignoli, M.. (Eni E&P) | Ciccarone, T.. (Eni E&P)
Abstract The paper describes the complete workflow applied for the future development of the Oglan Field in the Ecuadorian Oriente Basin in a sanding potential scenario. First, a sand prediction study evaluates a potential risk of sand production in a certain range of drawdown, identifying 1000 Psi as the critical one. Then, the conceptual evaluation of sand production mechanism is presented and discussed, in order to define the most suitable completion method for the production section. The methodology is based on a Geomechanical characterization done over the Oglan 2Dir cores, which includes stress evaluation, and the definition of the geomechanical properties needed for the sand prediction model. The procedure integrates results from Scratch tests, Triaxial, Ultrasonic Tests, Geo-pressures and Log processing. Once the sand production potential was identified the evaluation of a suitable downhole sand control method becomes necessary; grain size analysis, sand sorting ratios, reliability, productivity are evaluated to identify the optimal sand control technique. Finally, a sand production comparison for Hollin Formation in Ecuador is performed. The initial section of the paper will show the results of the sand risk integrated study which evidences a certain degree of strength heterogeneity in the Hollin formation. According to the stresses and strength information, the risk of sand production in open hole horizontal wells is not negligible for high drawdown values ≥1000 psi. The risk of sanding decreases for lower drawdown (in the range from 500 psi – to 1000 psi), but cannot be totally excluded due to rock strength heterogeneity. Critical DD of 1000 psi and Safety DD of 500 psi is finally concluded. A simulation in a vertical well was done with no sanding risk. This result is in agreement with the Oglan 2 dir well test, which did not observe sand production with a maximum DD of ~700 psi. Since the development of the field is planned by the drilling of horizontal wells the risk of sand should be Included in planning of the completion method. No depletion has been considered through all the sand risk analyses, as strong aquifer support is believed to keep pressure almost at the virgin level. The effect of the water production in producing sand is considered since increasing water cut could increase the sanding potential. The second section describes the selection criteria used to evaluate different technologies for downhole sand control which involves sand failure characteristics, particle size distribution, well condition, reservoir and fluid characteristics, plugging risk, erosion risk and well productivity to identify the optimal downhole sand control. This paper provides the complete workflow applied for sanding evaluation necessary for the development plan of the field. The results of geomechanical analyses and modeling showed indeed that the mechanical behavior of the Hollin reservoir in Oglan Field is somewhat different when compared to information available in the Oriente Basin literature, so the technical information detailed in the paper is useful for future development and correlations of nearest fields.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- South America > Ecuador > Pastaza > Oriente Basin > Block 10 > Villano Field (0.99)
- South America > Ecuador > Oriente Basin (0.99)
- South America > Ecuador > Napo > Oriente Basin > Napo Formation > Napo T Formation (0.99)
- Africa > Angola > South Atlantic Ocean > Kwanza Basin > Azul Field (0.99)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)
Abstract This paper presents a case study focusing on the identification of CO2 in the Hollin reservoir, based on nuclear magnetic resonance (NMR) responses, its effect on petrophysical parameters, and the negative effect on production wells. The paper also discusses the strong relationship between the high CO2 concentration in the reservoir fluids and its effect on the formation damage resulting from pore throat plugging from organic and inorganic compounds. After NMR processing, it was possible to identify the CO2 response on porosity related to low hydrogen index; the PVT analysis reveals approximately 75% of CO2 in the reservoir conditions and more than 95% of CO2 in the surface conditions. Asphaltene stability was evaluated through four methods, including the Leontaritis method, colloidal stability index, Stankiewicz method, and stability crossplot (SCP), which enabled the determination of an unstable probability by more than 75%. Palo Azul wells have been completed with production enhancement techniques, such as fracturing, to minimize the formation damage and its negative production effect; until now, however, the unique hypothesis considered formation damage to be related to fine-grain migration without considering that the primary problem could be connected to asphaltene stability. The deposition of the asphaltene can plug pore throats, reducing wellbore permeability and dramatically reducing fracture wings conductivity. This case study provides several important contributions. First, NMR results were successfully used in the Oriente basin of Ecuador to identify reservoirs with high concentrations of CO2. Second, four different diagnostic methods were used to determine asphaltene stability; this has altered common paradigms regarding production reservoir behavior. Finally, this case study enabled the development of a new technical hypothesis concerning additional factors that can contribute to formation damage in the Hollin reservoir.
- South America > Ecuador (0.91)
- North America > United States (0.68)
- Geology > Sedimentary Geology (0.69)
- Geology > Mineral > Silicate (0.47)
- South America > Ecuador > Oriente Basin (0.99)
- Africa > Angola > South Atlantic Ocean > Kwanza Basin > Azul Field (0.99)
Abstract A rigorous three-phase asphaltene precipitation model was implemented into a compositional reservoir simulator to represent and estimate the reduction of porosity and permeability responsible for productivity impairment. Previous modeling techniques were computationally inefficient, showed thermodynamic inconsistencies, or required special laboratory experiments to characterize the fluid. The approach developed in this study uses a cubic equation of state to solve for vapor/liquid/liquid equilibrium (VLLE), where asphaltene is the denser liquid phase. Precipitation from the liquid mixture occurs as its solubility is reduced either by changes in pressure (natural depletion) or composition (i.e. mixing resulting from gas injection). The dynamic relationship between phase composition, pressure, and porosity/permeability is modeled with a finite differences reservoir simulator and solved using an implicit-pressure, explicit-saturations and explicit-compositions (IMPESC) direct sequential method. The robustness of this model is validated by the ability to reproduce experimental asphaltene precipitation data while predicting the expected phase behavior envelope and response to key thermodynamic variables (i.e. type of components and composition, pressure and, temperature). The three-phase VLLE flash provides superior thermodynamic predictions compared to existing commercial techniques. This model offers the speed of a flash calculation while maintaining thermodynamic consistency, enabling efficient optimization of reservoir development strategies to mitigate the detrimental effects of asphaltene precipitation on productivity.
Abstract In the early life of most gas wells, there is sufficient reservoir pressure and flow rate to assure reliable evacuation of associated fluids from the reservoir/wellbore to the surface facility. In unconventional plays and in the case of Deep Basin gas field, this natural flow phase is usually short with a characteristic hyperbolic decline. When gas flow reaches critical velocity i.e. the minimum required velocity to lift out the liquids, pressure drop as a result of the hydrostatic head of liquid that is being left behind in the wellbore, increases till the well eventually stops flowing. Reduced rates and ultimate recovery due to liquid loading has significant impact on the economics of tight gas developments. The methods (timer cycling, foam, plunger, velocity string) presented in this paper are relevant to many low rate and low pressure gas wells. These methods have been used singly or in combination to optimally utilize the reservoir's energy for long term flow assurance. Cost, rate and estimated ultimate recovery of the deliquification decision have been key driving factors in the pursuit of effective hydrocarbon flow. Challenges and lessons learned thus far for deliquification decisions in Deep Basin are discussed, including the criteria/requirements for each method, inflow performance, wellbore hydraulics, water dynamics (formation and condensed water), scale deposition, associated secondary benefits/complications and field data showing impact.
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (14 more...)
Abstract One of the most important rock properties in Reservoir Engineering is very often absolute permeability. Unconsolidated sands offer some of the highest permeabilities due to their typically low consolidation degree, leaving more space between the porous media for conductivity. This low degree of consolidation, however, also brings high sand production potential while producing the reservoir; therefore sand control is required. This paper discusses how well failure histories were used, along with downhole analytical methods, to determine maximum FLUX limitations recommended to be used to minimize completion failures and sand production while producing at the highest safe rate. Chevron has a 50% working interest in an NOJV area with BG, in three different offshore dry gas fields located in Trinidad and Tobago. Dolphin field is the main producing field, having been on production since 1996 from four main groups of sands, all of which are unconsolidated (D, Upper E, Lower E and G sands). Due to the sands highly unconsolidated nature and targeting high gas production rates, all completions in the field utilize openhole gravel packs for sand control. During the field production history, several sand completion failures were encountered, as evidenced by formation sand production at the surface and reduced rates; and in some cases, complete cessation of flow (due to sand fill). After completing various analyses on possible failure root causes, it was found that the highest probable reason for sand completion failure was high FLUX across the completions. After drawing this conclusion, it was imperative for the Reservoir Management and Production Teams to understand FLUX associated with the failures, determine the maximum recommended FLUX to avoid future failures and finally, to apply a FLUX limit on current and future forecasts, from a prudent reservoir management perspective, in order to develop more realistic and reliable production forecasts. This case study shows how the failure history data was used and integrated with a downhole velocity analytical approach in order to determine the maximum FLUX limit to prevent current and new completion failures and sand production.
- Oceania > Australia > Victoria > Bass Strait (0.61)
- North America > United States > North Dakota > Divide County (0.61)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean (0.61)
- Asia > Middle East > Israel > Mediterranean Sea (0.61)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > East Coast Marine Area > Block 5A > Dolphin Field (0.99)
- Europe > Romania > Black Sea > West Black Sea Basin > Dolphin Well (0.98)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)