scholarly journals Application of a physics-based lumped parameter model to evaluate reservoir parameters during CO2 storage

2020 ◽  
Vol 10 (8) ◽  
pp. 3925-3935
Author(s):  
Samin Raziperchikolaee ◽  
Srikanta Mishra
Keyword(s):  
Oil Recovery ◽  
Co2 Storage ◽  
Field Application ◽  
Oil Field ◽  
Lumped Parameter Model ◽  
Linear Regression Method ◽  
Oil Reservoir ◽  
Michigan Basin ◽  
Reservoir Properties ◽  
Lumped Parameter

Abstract Evaluating reservoir performance could be challenging, especially when available data are only limited to pressures and rates from oil field production and/or injection wells. Numerical simulation is a typical approach to estimate reservoir properties using the history match process by reconciling field observations and model predictions. Performing numerical simulations can be computationally expensive by considering a large number of grids required to capture the spatial variation in geological properties, detailed structural complexity of the reservoir, and numerical time steps to cover different periods of oil recovery. In this work, a simplified physics-based model is used to estimate specific reservoir parameters during CO2 storage into a depleted oil reservoir. The governing equation is based on the integrated capacitance resistance model algorithm. A multivariate linear regression method is used for estimating reservoir parameters (injectivity index and compressibility). Synthetic scenarios were generated using a multiphase flow numerical simulator. Then, the results of the simplified physics-based model in terms of the estimated fluid compressibility were compared against the simulation results. CO2 injection data including bottom hole pressure and injection rate were also gathered from a depleted oil reef in Michigan Basin. A field application of the simplified physics-based model was presented to estimate above-mentioned parameters for the case of CO2 storage in a depleted oil reservoir in Michigan Basin. The results of this work show that this simple lumped parameter model can be used for a quick estimation of the specific reservoir parameters and its changes over the CO2 injection period.

scholarly journals Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

2021 ◽  
Author(s):  
Hesham A. Abu Zaid ◽  
◽  
Sherif A. Akl ◽  
Mahmoud Abu El Ela ◽  
Ahmed El-Banbi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Field Measurements ◽  
Field Trials ◽  
Oil Field ◽  
Reservoir Properties ◽  
Actual Performance ◽  
Reservoir Performance ◽  
Mechanical Waves ◽  
Incremental Oil Recovery ◽  
Wave Induced

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

Research on Efficient Microbial Enhanced Oil Recovery Technology Based on Low-Temperature Heavy Oil

2013 ◽  
Vol 734-737 ◽  
pp. 1434-1439 ◽  
Author(s):  
Gang Wu ◽  
Fu Ping Ren ◽  
Jing You ◽  
Ji Liang Yu ◽  
Ya Tuo Pei ◽  
...  
Keyword(s):  
Low Temperature ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Average Concentration ◽  
Oil Field ◽  
Oil Reservoir ◽  
Oil Degradation ◽  
Microbial Enhanced Oil Recovery ◽  
Well Pattern

Based on the low-temperature and heavy oil reservoir of conventional injection well pattern separated two strains of oil degradation bacteria LC and JH which had satisfactory compatibleness with BaoLige oill field. In order to study the feasibility of enhancing oil recovery rate of the two strains, the experiment of huff and puff with 15 wells were carried out. The average concentration of bacteria increase from 4.7×102cells/ml to 8.1×106cells/ml. The average reduction of surface tension and viscosity is 33.1% and 31.9%. The accumulative total was 1163.2t. The ratio of input to output was 1:2.12. Microbial enhanced oil recovery can improve the low-temperature and heavy oil production status, which provide a effective method for the similar oil field.

scholarly journals CO2 Storage and Enhanced Oil Recovery: Sugar Creek Oil Field Test Site, Hopkins County, Kentucky

2013 ◽  
Author(s):  
Scott Frailey ◽  
Thomas Parris ◽  
James Damico ◽  
Roland Okwen ◽  
Ray McKaskle
Keyword(s):  
Enhanced Oil Recovery ◽  
Field Test ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Test Site ◽  
Oil Field

scholarly journals Experimental Investigations of Forward and Reverse Combustion for Increasing Oil Recovery of a Real Oil Field

Energies ◽  
2020 ◽  
Vol 13 (17) ◽  
pp. 4581
Author(s):  
Aysylu Askarova ◽  
Evgeny Popov ◽  
Matthew Ursenbach ◽  
Gordon Moore ◽  
Sudarshan Mehta ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Numerical Models ◽  
Front Propagation ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Oil Field ◽  
Combustion Tube ◽  
Experimental Investigations ◽  
Reservoir Conditions ◽  
Lower Permeability

The work presented herein is devoted to a unique set of forward and reverse combustion tube (CT) experiments to access the suitability and potential of the in situ combustion (ISC) method for the light oil carbonate reservoir. One forward and one reverse combustion tube tests were carried out using the high-pressure combustion tube (HPCT) experimental setup. However, during reverse combustion, the front moved in the opposite direction to the airflow. The results obtained from experiments such as fuel/air requirements, H/C ratio, and recovery efficiency are crucial for further validation of the numerical model. A quantitative assessment of the potential for the combustion was carried out. The oil recovery of forward combustion was as high as 91.4% of the initial oil in place, while that for the reverse combustion test demonstrated a 43% recovery. In the given conditions, forward combustion demonstrated significantly higher efficiency. However, the stabilized combustion front propagation and produced gases of reverse combustion prove its possible applicability. Currently, there is a limited amount of available studies on reverse combustion and a lack of publications within the last decades despite advances in technologies. However, reverse combustion might have advantages over forward combustion for heavy oil reservoirs with lower permeability or might serve as a reservoir preheating technique. These experiments give the opportunity to build and validate the numerical models of forward and reverse combustion conducted at reservoir conditions and test their field application using different scenarios.

scholarly journals Production Allocation on Commingled Two Layer Well Using Fingerprint Method

2018 ◽  
Vol 1 (3) ◽  
Author(s):  
Fahrudin Zuhri ◽  
Rachmat Sudibjo ◽  
R. S. Trijana Kartoatmodjo
Keyword(s):  
Gas Chromatography ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Oil Field ◽  
Oil Reservoir ◽  
Production Time ◽  
Well Production ◽  
Well Completion ◽  
Production Allocation ◽  
Production Problem

<p>Production proportion ratio study of commingled well two layers reservoir has been developed by geochemistry approaching, with oil reservoir fingerpint methode by using Gas Chromatography then processed by Chemstation software. The study is developed to solve the commingled well production alocation problem in oil field. There are 4 oil samples will be analyzed to represent each layer and commingle production oil sample in 2009 and 2015.<br />Result of study, figures out that oil fingerprint from commingle production has a difference as long as production time. Oil sample that taken from different commingle production time is predicted to produce a different ratio contribution form each layer of reservoir. Every layer reservoir has a different contribution from 2009 to 2015. Result of production proportion ratio study can be applied to decisionmaking of reservoir developement in an oil field, especially for well completion and enhanced oil recovery. This methode is proven to be a solution of commingle production problem of two layers reservoir. Fingerprint methode to determine production proportion ratio of commingled well production is the first in Indonesia.</p>

scholarly journals Half a century of continuous oil production by in-situ combustion in Romania – case study Suplacu de Barcau field

2021 ◽  
Vol 343 ◽  
pp. 09009
Author(s):  
Gheorghe Branoiu ◽  
Florinel Dinu ◽  
Maria Stoicescu ◽  
Iuliana Ghetiu ◽  
Doru Stoianovici
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Oil Field ◽  
Oil Reservoir ◽  
In Situ Combustion ◽  
Cyclic Steam Stimulation ◽  
The Impact ◽  
Steam Stimulation

Thermal oil recovery is a special technique belonging to Enhanced Oil Recovery (EOR) methods and includes steam flooding, cyclic steam stimulation, and in-situ combustion (fire flooding) applied especially in the heavy oil reservoirs. Starting 1970 in-situ combustion (ISC) process has been successfully applied continuously in the Suplacu de Barcau oil field, currently this one representing the most important reservoir operated by ISC in the world. Suplacu de Barcau field is a shallow clastic Pliocene, heavy oil reservoir, located in the North-Western Romania and geologically belonging to Eastern Pannonian Basin. The ISC process are operated using a linear combustion front propagated downstructure. The maximum oil production was recorded in 1985 when the total air injection rate has reached maximum values. Cyclic steam stimulation has been continuously applied as support for the ISC process and it had a significant contribution in the oil production rates. Nowadays the oil recovery factor it’s over 55 percent but significant potential has left. In the paper are presented the important moments in the life-time production of the oil field, such as production history, monitoring of the combustion process, technical challenges and their solving solutions, and scientific achievements revealed by many studies performed on the impact of the ISC process in the oil reservoir.

SATURATION EXPONENT AS A FUNCTION OF RESERVOIR HETEROGENEITY AND WETTABILITY IN THE TAMBAREDJO OIL FIELD, SURINAME

2021 ◽  
Author(s):  
Elias R. Acosta ◽  
◽  
Bhagwanpersad Nandlal ◽  
Ryan Harripersad ◽  
◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Variable Parameter ◽  
Oil Field ◽  
High Resistivity ◽  
Reservoir Properties ◽  
Core Data ◽  
The Core ◽  
Irreducible Water Saturation ◽  
Saturation Exponent

This research proposed an alternative method for determining the saturation exponent (n) by finding the best correlations for the heterogeneity index using available core data and considering wettability changes. The log curves of the variable n were estimated, and the effect on the water saturation (Sw) calculations and the Stock Tank Oil Initially In Place (STOIIP) in the Tambaredjo (TAM) oil field was analyzed. Core data were employed to obtain the relationship between n and heterogeneity using cross-plots against several heterogeneity indices, reservoir properties, and pore throat size. After filtering the data, the clay volume (Vcl), shale volume, silt volume, basic petrophysical property index (BPPI), net reservoir index, pore grain volume ratio, and rock texture were defined as the best matches. Their modified/improved equations were applied to the log data and evaluated. The n related to Vcl was the best selection based on the criteria of depth variations and logical responses to the lithology. The Sw model in this field showed certain log readings (high resistivity [Rt] reading ≥ 500 ohm.m) that infer these intervals to be probable inverse-wet (oil-wet). The cross-plots (Rt vs. Vcl; Rt vs. density [RHOB]; Rt vs. total porosity [PHIT]) were used to discard the lithologies related to a high Rt (e.g., lignites and calcareous rocks) and to correct Sw when these resulted in values below the estimated irreducible water saturation (Swir). The Sw calculations using the Indonesian equation were updated to incorporate n as a variable (log curves), comparing it with Sw from the core data and previous calculations using a fixed average value (n = 1.82) from the core data. An integrated approach was used to determine n, which is related to the reservoir’s heterogeneity and wettability changes. The values of n for high Rt (n > 2) intervals ranged from 2.3 to 8.5, which is not close to the field average n value (1.82). Specific correlations were found by discriminating Swir (Swir < 15%), (Swir 15%–19%), and Swir (> 19%). The results showed that using n as a variable parameter improved Sw from 39.5% to 36.5% average in the T1 and T2 sands, showing a better fit than the core data average and increasing the STOIIP estimations by 6.81%. This represents now a primary oil recovery of 12.1%, closer to the expected value for these reservoirs. Although many studies have been done on n determination and its effect on Sw calculations, using average values over a whole field is still a common practice regardless of heterogeneity and wettability considerations. This study proposed a method to include the formation of heterogeneity and wettability changes in n determination, allowing a more reliable Sw determination as demonstrated in the TAM oil field in Suriname.

Analysis of Microbial Community Succession in Daqing Oil Field

2010 ◽  
Vol 113-116 ◽  
pp. 830-834
Author(s):  
Yong Hong Huang ◽  
Guo Ling Ren ◽  
Li Wei ◽  
Xiao Lin Wu ◽  
Hong Mei Yuan ◽  
...  
Keyword(s):  
Microbial Community ◽  
Oil Recovery ◽  
Dynamic Change ◽  
Oil Production ◽  
Oil Field ◽  
Community Diversity ◽  
Oil Reservoir ◽  
Crude Oil Production ◽  
Daqing Oil Field ◽  
Single Well

It is difficult to increase crude oil production for Daqing oil field by conventional technologies. In order to increase crude oil production, we make use of microbial enhanced oil recovery technology. The results showed that fluid production increased by 11 tons, oil production increased by 1.7 tons, water rate has decreased by 0.6 tons in oil reservoir after polymer flooding, North-2-4-P47 single-well daily. Microbial community diversity and dynamic change in oil reservoir after polymer flooding in Daqing Oil Field, North 2-4-P47 single-well in the process of microbial enhanced oil recovery was analyzed by PCR-DGGE. The results showed that the dominant microbes of North-2-4-P47 single-well are Acinetobacter johnsonii., Pseudomonas fluorescens., Pseudomonas sp., Bosea sp., Syntrophothermus lipocalidus., Aeromonas media. and some uncultured bacterium. Overall, microbial community diversity is abundant, and dynamic change of microbial community is also great in North-2-4-P49 single-well.

scholarly journals Optimization Wells Placement Policy for Enhanced CO2 Storage Capacity in Mature Oil Reservoirs

Energies ◽  
2020 ◽  
Vol 13 (16) ◽  
pp. 4054
Author(s):  
Michał Kuk ◽  
Edyta Kuk ◽  
Damian Janiga ◽  
Paweł Wojnarowski ◽  
Jerzy Stopa
Keyword(s):  
Carbon Dioxide ◽  
Carbon Dioxide Emissions ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Oil Field ◽  
Ecological Effect ◽  
Co2 Injection ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Co2 Eor

One of the possibilities to reduce carbon dioxide emissions is the use of the CCS method, which consists of CO2 separation, transport and injection of carbon dioxide into geological structures such as depleted oil fields for its long-term storage. The combination of the advanced oil production method involving the injection of carbon dioxide into the reservoir (CO2-EOR) with its geological sequestration (CCS) is the CCS-EOR process. To achieve the best ecological effect, it is important to maximize the storage capacity for CO2 injected in the CCS phase. To achieve this state, it is necessary to maximize recovery factor of the reservoir during the CO2-EOR phase. For this purpose, it is important to choose the best location of CO2 injection wells. In this work, a new algorithm to optimize the location of carbon dioxide injection wells is developed. It is based on two key reservoir properties, i.e., porosity and permeability. The developed optimization procedure was tested on an exemplary oil field simulation model. The obtained results were compared with the option of arbitrary selection of injection well locations, which confirmed both the legitimacy of using well location optimization and the effectiveness of the developed optimization method.

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