scholarly journals Experimental Study on Enhanced Condensate Recovery by Gas Injection in Yaha Condensate Gas Reservoir

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Yiming Wu ◽  
Kun Yao ◽  
Yan Liu ◽  
Xiangyun Li ◽  
Mimi Wu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Recovery Rate ◽  
Oil And Gas ◽  
Gas Injection ◽  
Recovery Factor ◽  
Co2 Injection ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Injection Method ◽  
Production Ratio

A condensate gas reservoir is an important special oil and gas reservoir between oil reservoir and natural gas reservoir. Gas injection production is the most commonly used development method for this type of gas reservoir, but serious retrograde condensation usually occurs in the later stages of development. To improve the recovery efficiency of condensate oil in the middle and late stages of production of a condensate gas reservoir, a gas injection parameter optimization test study was carried out, taking the Yaha gas condensate reservoir in China as an example. On the premise that the physical experimental model and key parameters met the actual conditions of the formation, the injection method, injection medium, injection-production ratio, and other parameters of the condensate gas reservoir were studied. Research on the injection method showed that the top injection method had a lower gas-oil ratio and higher condensate oil recovery. The study of injection medium showed that the production effect of carbon dioxide (CO2) injection was the best injection medium, and the maximum recovery rate of condensate oil was 95.11%. The injection-production ratio study showed that the injection-production ratio was approximately inversely proportional to the recovery factor of condensate gas and approximately proportional to the recovery factor of condensate oil. When the injection-production ratio was 1 : 1, the maximum recovery rate of condensate oil was 83.31%. In summary, in the later stage of gas injection development of the Yaha condensate gas reservoir, it was recommended to choose the development plan of CO2 injection at the top position with an injection-production ratio of 1 : 1. This research can not only provide guidance for the later formulation of gas injection plans for Yaha condensate gas reservoirs but also lay a foundation for the research of gas injection migration characteristics of other condensate gas reservoirs.

scholarly journals Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery

Energies ◽  
2021 ◽  
Vol 14 (22) ◽  
pp. 7676
Author(s):  
Ilyas Khurshid ◽  
Imran Afgan
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Injection Rate ◽  
Rock Properties ◽  
Co2 Injection ◽  
Formation Damage ◽  
Gas Reservoirs ◽  
Oil And Gas Reservoirs ◽  
Carbon Dioxide Co2 ◽  
Injection Rates

The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

scholarly journals Investigation of Oil Recovery in Fractured Carbonate Rock by

2016 ◽  
Vol 6 (1) ◽  
pp. 14
Author(s):  
H. Karimaie ◽  
O. Torsæter
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Co2 Injection ◽  
Recovery Method ◽  
Asmari Limestone ◽  
Fractured Carbonate ◽  
Efficient Recovery ◽  
Live Oil ◽  
Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

Bati Raman Field Immiscible CO2 Application--Status Quo and Future Plans

2008 ◽  
Vol 11 (04) ◽  
pp. 778-791 ◽  
Author(s):  
Secaeddin Sahin ◽  
Ulker Kalfa ◽  
Demet Celebioglu
Keyword(s):  
Gas Injection ◽  
Critical Evaluation ◽  
Oil Field ◽  
Recovery Factor ◽  
Reservoir Rock ◽  
Current Status ◽  
Co2 Injection ◽  
Status Report ◽  
Random Pattern ◽  
Short Period

Summary The Bati Raman field is the largest oil field in Turkey and contains approximately 1.85 billion bbl of oil initially in place. The oil is heavy (12°API), with high viscosity and low solution-gas content. Primary recovery was less than 2% of oil originally in place (OOIP). Over the period of primary recovery (1961-86), the reservoir underwent extensive pressure depletion from 1,800 psig to as low as 400 psig in some regions, resulting in a production decline from 9,000 to 1,600 STB/D. In March 1986, a carbon-dioxide (CO2) -injection pilot in a 1,200-acre area containing 33 wells was initiated in the western portion of the field. The gas-injection was initially cyclic. In 1988, the gas injection scheme was converted to a CO2-flood process. Later, the process was extended to cover the whole field. A peak daily production rate of 13,000 STB/D was achieved, whereas rate would have been less than 1,600 STB/D without CO2 application. However, the field has undergone a progressive production decline since 1995to recent levels of approximately 5,500 STB/D. Polymer-gel treatments were carried out to increase the CO2 sweep efficiency. Multilateral- and horizontal-well technology also was applied on a pilot scale to reach the bypassed oil. A water-alternating-gas (WAG) application has been applied extensively in the western part of the field. Current production is 7,000 STB/D. This paper documents more than 25 years of experience of the Turkish Petroleum Corporation (TPAO) on the design and operation of this full-field immiscible CO2-injection project conducted in the Bati Raman oil field in Turkey. The objective is to update the current status report, update the reservoir/field problems that TPAO has encountered (unpredictable problems and results), and provide a critical evaluation of the success of the project. Introduction The Bati Raman field is the biggest oil accumulation in Turkey and is operated by TPAO. It contains very viscous and low-API-gravity oil in a very challenging geological environment. Because of the fact that the recovery factor by primary recovery was limited, several enhanced-oil-recovery (EOR) techniques had been proposed and tested at the pilot level in the 1970s and 1980s. On the basis of the success of the laboratory tests and the vast amount of CO2 available in a neighboring field, which is only 55 miles away from the Bati Raman field, huff ‘n’ puff injection was started in the early 1980s. Because of the early breakthrough of CO2 in offset wells in a short period of time, the project was converted to field-scale random-pattern continuous injection. During more than 20 years of injection, the recovery peaked at approximately 13,000 STB/D and began to decline, reaching today's value of approximately 7,000 STB/D. In the case of Bati Raman, in its mature, the injected agent is bypassing the remaining oil and production is curtailed by excessively high gas/oil ratios (GORs). The naturally fractured character of the reservoir rock has been a challenge for establishing successful 3D conformance from the beginning, and its impact is even more pronounced in the later stages of the process. Therefore, the field requires modifications in the reservoir-management scheme to improve the recovery factor and to improve productivity of the current wells.

scholarly journals Development of a prmA genes quantification technique and assessment of the technique’s application potential for oil and gas reservoir exploration

2018 ◽  
Vol 36 (5) ◽  
pp. 1172-1188 ◽  
Author(s):  
Zhuo Ning ◽  
Ze He ◽  
Sheng Zhang ◽  
Miying Yin ◽  
Yaci Liu ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Quantitative Polymerase Chain Reaction ◽  
Oil Field ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Gas Field ◽  
Detection Range ◽  
Gene Copies ◽  
Application Potential ◽  
Sensitivity Specificity

Propane-oxidizing bacteria in surface soils are often used to indicate the position of oil and gas reservoirs. As a potential replacement for the laborious traditional culture-dependent counting method, we applied real-time fluorescent quantitative polymerase chain reaction detection as a quick and accurate technology for quantification of propane-oxidizing bacteria. The propane monooxygenase gene was set as the target and the assay is based on SYBR Green I dye. The detection range was from 9.75 × 108 to 9.75 × 101 gene copies/µl, with the lowest detected concentration of 9.75 copies/µl. All coefficient of variation values of the threshold cycle in the reproducibility test were better than 1%. The technique showed good sensitivity, specificity, and reproducibility. We also quantified the propane-oxidizing bacteria in soils from three vertical 250 cm profiles collected from an oil field, a gas field, and a nonoil gas field using the established technique. The results indicated that the presence of propane monooxygenase A genes in soils can indicate an oil or gas reservoir. Therefore, this technique can satisfy the requirements for microbial exploration of oil and gas.

THE DEVELOPMENT OF THE TIRRAWARRA OIL AND GAS FIELD

1984 ◽  
Vol 24 (1) ◽  
pp. 278
Author(s):  
H. T. Pecanek ◽  
I. M. Paton
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Gas Injection ◽  
Oil Field ◽  
Oil Reservoir ◽  
Gas Reservoirs ◽  
Gas Field ◽  
Associated Gas ◽  
Oil And Gas Field ◽  
Cooper Basin

The Tirrawarra Oil and Gas Field, discovered in 1970 in the South Australian portion of the Cooper Basin, is the largest onshore Permian oil field in Australia. Development began in 1981 as part of the $1400 million Cooper Basin Liquids ProjectThe field is contained within a broad anticline bisected by a north-south sealing normal fault. This fault divides the Tirrawarra oil reservoir into the Western and Main oil fields. Thirty-four wells have been drilled, intersecting ten Patchawarra Formation sandstone gas reservoirs and the Tirrawarra Sandstone oil reservoir. Development drilling discovered three further sandstone gas reservoirs in the Toolachee Formation.The development plan was based on a seven-spot pattern to allow for enhanced oil recovery by miscible gas drive. The target rates were 5400 barrels of oil (860 kilolitres) per day with 13 million ft3 (0.37 million m3) per day of associated gas and 70 million ft3 (2 million m') per day of wet, non-associated gas. Evaluation of early production tests showed rapid decline. The 100 ft (30 m) thick, low-permeability Tirrawarra oil reservoir was interpreted as an ideal reservoir for fracture treatment and as a result all oil wells have been successfully stimulated, with significant improvement in well production rates.The oil is highly volatile but miscibility with carbon dioxide has been proven possible by laboratory tests, even though the reservoir temperature is 285°F (140°C). Pilot gas injection will assess the feasibility of a larger-scale field-wide pressure maintenance scheme using miscible gas. Riot gas injection wells will use Tirrawarra Field Patchawarra Formation separator gas to defer higher infrastructure costs associated with the alternative option of piping carbon dioxide from Moomba, the nearest source.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1402-1415 ◽  
Author(s):  
A. H. Al Ayesh ◽  
R.. Salazar ◽  
R.. Farajzadeh ◽  
S.. Vincent-Bonnieu ◽  
W. R. Rossen
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Model Parameters ◽  
High Permeability ◽  
Fractional Flow ◽  
Injection Method ◽  
Heterogeneous Reservoirs ◽  
Irreducible Water Saturation

Summary Foam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers. Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG process, diversion of the first slug of gas depends on foam behavior at very-high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether foam collapses completely at irreducible water saturation. In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.

Classification of Oil and Gas Reservoirs Based on Recovery Factor: A Data-Mining Approach

2010 ◽  
Author(s):  
Aviral Sharma ◽  
Sanjay Srinivasan ◽  
Larry Wayne Lake
Keyword(s):  
Data Mining ◽  
Oil And Gas ◽  
Recovery Factor ◽  
Gas Reservoirs ◽  
Data Mining Approach ◽  
Oil And Gas Reservoirs

scholarly journals Minimum miscibility pressure computation in eor by flare gas flooding

2018 ◽  
Vol 10 (2) ◽  
pp. 61
Author(s):  
Tjokorde Walmiki Samadhi ◽  
Utjok W.R. Siagian ◽  
Angga P Budiono
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Molar Ratio ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Minimum Miscibility Pressure ◽  
Gas Flooding ◽  
Model Oil ◽  
Gas Drive

The technical feasibility of using flare gas in the miscible gas flooding enhanced oil recovery (MGF-EOR) is evaluated by comparing the minimum miscibility pressure (MMP) obtained using flare gas to the MMP obtained in the conventional CO2 flooding. The MMP is estimated by the multiple mixing cell calculation method with the Peng-Robinson equation of state using a binary nC5H12-nC16H34 mixture at a 43%:57% molar ratio as a model oil. At a temperature of 323.15 K, the MMP in CO2 injection is estimated at 9.78 MPa. The MMP obtained when a flare gas consisting of CH4 and C2H6 at a molar ratio of 91%:9% is used as the injection gas is predicted to be 3.66 times higher than the CO2 injection case. The complete gas-oil miscibility in CO2 injection occurs via the vaporizing gas drive mechanism, while flare gas injection shifts the miscibility development mechanism to the combined vaporizing / condensing gas drive. Impact of variations in the composition of the flare gas on MMP needs to be further explored to confirm the feasibility of flare gas injection in MGF-EOR processes. Keywords: flare gas, MMP, miscible gas flooding, EORAbstrakKonsep penggunaan flare gas untuk proses enhanced oil recovery dengan injeksi gas terlarut (miscible gas flooding enhanced oil recovery atau MGF-EOR) digagaskan untuk mengurangi emisi gas rumah kaca dari fasilitas produksi migas, dengan sekaligus meningkatkan produksi minyak. Kelayakan teknis injeksi flare gas dievaluasi dengan memperbandingkan tekanan pelarutan minimum (minimum miscibility pressure atau MMP) untuk injeksi flare gas dengan MMP pada proses MGF-EOR konvensional menggunakan injeksi CO2. MMP diperkirakan melalui komputasi dengan metode sel pencampur majemuk dengan persamaan keadaan Peng-Robinson, pada campuran biner nC5H12-nC16H34 dengan nisbah molar 43%:57% sebagai model minyak. Pada temperatur 323.15 K, estimasi MMP yang diperoleh dengan injeksi CO2 adalah 9.78 MPa. Nilai MMP yang diperkirakan pada injeksi flare gas yang berupa campuran CH4-C2H6 pada nisbah molar 91%:9% sangat tinggi, yakni sebesar 3.66 kali nilai yang diperoleh pada kasus injeksi CO2. Pelarutan sempurna gas-minyak dalam injeksi CO2 terbentuk melalui mekanisme dorongan gas menguap (vaporizing gas drive), sementara pelarutan pada injeksi flare gas terbentuk melaui mekanisme kombinasi dorongan gas menguap dan mengembun (vaporizing/condensing gas drive). Pengaruh variasi komposisi flare gas terhadap MMP perlu dikaji lebih lanjut untuk menjajaki kelayakan injeksi flare gas dalam proses MGF-EOR.Kata kunci: flare gas, MMP, miscible gas flooding, EOR

Sign in / Sign up

Export Citation Format

Share Document