Laboratory Investigation on Oil Increment and Water Cut Control of CO2, N2, and Gas Mixture Huff-n-Puff in Edge-Water Fault-Block Reservoirs

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Peng Wang ◽  
Fenglan Zhao ◽  
Shijun Huang ◽  
Meng Zhang ◽  
Hairu Feng ◽  
...  
Keyword(s):  
Synergistic Effect ◽  
Production Efficiency ◽  
Gas Injection ◽  
Co2 Injection ◽  
Gas Mixture ◽  
Injection Volume ◽  
Fault Block ◽  
Asphaltene Deposition ◽  
Water Cut ◽  
Injection Ratio

Abstract Excessive water production is a common matter that seriously affects production efficiency during the development of edge-water fault-block reservoirs. Gas huff-n-puff is an effective water shutoff technology that has the characteristics of small injection volume, no interwell connectivity impact, and minor gas channeling. However, gas injection can destroy the stability of the asphaltene to induce asphaltene deposition. In this article, the laboratory experiment had been conducted to investigate the effect of injection ratio and injection sequence on oil increment and water cut control for gas mixture huff-n-puff. Experimental results indicated that the effect of N2 huff-n-puff on water cut control was the most obvious, while CO2 huff-n-puff had the best performance on oil increment. Oil increment and water cut control of gas mixture huff-n-puff with CO2 injected in advance were obviously better than that of N2 injection preferentially. Subsequently, PVTsim Nova was utilized to investigate whether reducing CO2 injection volume can inhibit asphaltene deposition and predict the possibility of asphaltene deposition at reservoir conditions. Simulation results demonstrated that the asphaltenes were easily deposited with CO2 injection while N2 injection will be unlikely to induce asphaltene deposition. Asphaltene deposition pressure envelope can qualitatively analyze the possibility of asphaltene deposition and provide a reference for screening the appropriate gas injection ratio based on giving full play to the synergistic effect of CO2 and N2. In this study, 7:3 is selected as the optimum injection ratio considering the synergistic effect and the possibility of asphaltene deposition.

scholarly journals A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

Energies ◽  
2020 ◽  
Vol 13 (2) ◽  
pp. 402
Author(s):  
Kang Ma ◽  
Hanqiao Jiang ◽  
Junjian Li ◽  
Rongda Zhang ◽  
Kangqi Shen ◽  
...  
Keyword(s):  
Production Process ◽  
Oil Recovery ◽  
Production Efficiency ◽  
High Water ◽  
Gas Oil ◽  
Fault Block ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Gas Channeling ◽  
Water Cut

As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage.

scholarly journals Comparative Analysis of CO2, N2, and Gas Mixture Injection on Asphaltene Deposition Pressure in Reservoir Conditions

Energies ◽  
2018 ◽  
Vol 11 (9) ◽  
pp. 2483 ◽  
Author(s):  
Peng Wang ◽  
Fenglan Zhao ◽  
Jirui Hou ◽  
Guoyong Lu ◽  
Meng Zhang ◽  
...  
Keyword(s):  
Crude Oil ◽  
Pressure Range ◽  
Co2 Injection ◽  
Gas Mixture ◽  
Low Permeability ◽  
Deposition Pressure ◽  
Severe Problem ◽  
Asphaltene Deposition ◽  
Reservoir Conditions ◽  
Buried Hill

CO2 and N2 injection is an effective enhanced oil recovery technology in the oilfield especially for low-permeability and extra low-permeability reservoirs. However, these processes can induce an asphaltene deposition during oil production. Asphaltene-deposition-induced formation damage is a fairly severe problem. Therefore, predicting the likelihood of asphaltene deposition in reservoir conditions is crucial. This paper presents the results of flash separation experiments used to investigate the composition of crude oil in shallow and buried-hill reservoirs. Then, PVTsim Nova is used to simulate the composition change and asphaltene deposition of crude oil. Simulation tests indicate that the content of light components C1-C4 and heavy components C36+ decrease with increasing CO2 and N2 injection volumes. However, the extraction of CO2 is significantly stronger than that of N2. In shallow reservoirs, as the CO2 injection volume increases, the deposition pressure range decreases and asphaltenes are easily deposited. Conversely, the asphaltene deposition pressure of crude oil injected with N2 is higher and will not cause serious asphaltene deposition. When the CO2-N2 injection ratio reaches 1:1, the deposition pressure range shows a significant transition. In buried-hill reservoirs, asphaltene deposition is unlikely to occur with CO2, N2, and a gas mixture injection.

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.

scholarly journals Optimasi Intermittent Gas lift Pada Sumur AB-1 Lapangan Brownfield

2018 ◽  
Vol 2 (1) ◽  
pp. 32
Author(s):  
Mia Ferian Helmy
Keyword(s):  
Pressure Gradient ◽  
Production Rate ◽  
Flow Rate ◽  
Oil Recovery ◽  
Gas Injection ◽  
Production Method ◽  
Production Flow ◽  
Injection Volume ◽  
Artificial Lift ◽  
Gas Lift

Gas lift is one of the artificial lift method that has mechanism to decrease the flowing pressure gradient in the pipe or relieving the fluid column inside the tubing by injecting amount of gas into the annulus between casing and tubing. The volume of  injected gas was inversely proportional to decreasing of  flowing  pressure gradient, the more volume of gas injected the smaller the pressure gradient. Increasing flowrate is expected by decreasing pressure gradient, but it does not always obtained when the well is in optimum condition. The increasing of flow rate will not occured even though the volume of injected gas is abundant. Therefore, the precisely design of gas lift included amount of cycle, gas injection volume and oil recovery estimation is needed. At the begining well AB-1 using artificial lift method that was continuos gas lift with PI value assumption about 0.5 STB/D/psi. Along with decreasing of production flow rate dan availability of the gas injection in brownfield, so this well must be analyze to determined the appropriate production method under current well condition. There are two types of gas lift method, continuous and intermittent gas lift. Each type of gas lift has different optimal condition to increase the production rate. The optimum conditions of continuous gaslift are high productivity 0.5 STB/D/psi and minimum production rate 100 BFPD. Otherwise, the intermittent gas lift has limitations PI and production rate which is lower than continuous gas lift.The results of the analysis are Well AB-1 has production rate gain amount 20.75 BFPD from 23 BFPD became 43.75 BFPD with injected gas volume 200 MSCFPD and total cycle 13 cycle/day. This intermittent gas lift design affected gas injection volume efficiency amount 32%.

Laboratory Investigation of Permeability Impairment Caused by Asphaltene Precipitation during Screening for Gas-Injection Enhanced Oil Recovery and Pressure Change in a Major Gulf of Mexico Field

SPE Journal ◽  
2021 ◽  
pp. 1-21
Author(s):  
M. R. Fassihi ◽  
E. Turek ◽  
M. Matt Honarpour ◽  
D. Peck ◽  
R. Fyfe
Keyword(s):  
Gulf Of Mexico ◽  
Gas Injection ◽  
Rock Surface ◽  
Permeability Reduction ◽  
Test Results ◽  
Asphaltene Precipitation ◽  
The Core ◽  
Asphaltene Deposition ◽  
Core Permeability ◽  
Permeability Impairment

Summary As part of studying miscible gas injection (GI) in a major field within the Green Canyon protraction area in the Gulf of Mexico (GOM), asphaltene-formation risk was identified as a key factor affecting a potential GI project. The industry has not conducted many experiments to quantify the effect of asphaltenes on reservoir and well performance under GI conditions. In this paper we discuss a novel laboratory test for evaluating the asphaltene effect on permeability. The goals of the study were to define the asphaltene-precipitation envelope using blends of reservoir fluid and injection gas, and measure permeability reduction caused by asphaltene precipitation in a core under GI. To properly analyze the effect of GI, a suite of fluid-characterization studies was conducted, including restored-oil samples, compositional analysis, constant composition expansion (CCE), and differential vaporization. Miscibility conditions were defined through slimtube-displacement tests. Gas solubility was determined through swelling tests complemented by asphaltene-onset-pressure (AOP) testing. The unique procedure was developed to estimate the effect of asphaltene deposition on core permeability. The 1-ft-long core was saturated with the live-oil and GI mixture at a pressure greater than the AOP, and then pressure was depleted to a pressure slightly greater than the bubblepoint. Several cycles of charging and depletion were conducted to mimic continuous flow of oil along the path of injected gas and thereby to observe the accumulation of asphaltene on the rock surface. The test results indicated that during this cyclic asphaltene-deposition process, the core permeability to the live mixture decreased in the first few cycles but appeared to stabilize after Cycle 5. The deposited asphaltenes were analyzed further through environmental scanning electron microscopy (ESEM), and their deposition was confirmed by mass balance before and after the tests. Finally, a relationship was established between permeability reduction and asphaltene precipitation. The results from the asphaltene-deposition experiment show that for the sample, fluids, and conditions used, permeability is impaired as asphaltene flocculates and begins to coat the grain surfaces. This impairment reaches a plateau at approximately 40% of the initial permeability. Distribution of asphaltene along the core was measured at the end by segmenting the core and conducting solvent extraction on each segment. Our recommendation is numerical modeling of these test results and using this model to forecast the magnitude of the permeability impairment in a reservoir setting during miscible GI.

scholarly journals Simulation of High Water-Cut in Tight Oil Reservoirs during Cyclic Gas Injection

2019 ◽  
Author(s):  
Chi Zhang ◽  
Ye Tian ◽  
Yizi Shen ◽  
Bowen Yao ◽  
Yu-Shu Wu
Keyword(s):  
Gas Injection ◽  
High Water ◽  
Oil Reservoirs ◽  
Tight Oil ◽  
Tight Oil Reservoirs ◽  
High Water Cut ◽  
Water Cut

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.

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