Optimal Application Conditions for Steam/Solvent Coinjection

2015 ◽  
Vol 18 (01) ◽  
pp. 20-38 ◽  
Author(s):  
Mohsen Keshavarz ◽  
Ryosuke Okuno ◽  
Tayfun Babadagli
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Detailed Knowledge ◽  
Critical Question ◽  
Factors Affecting ◽  
Operation Conditions ◽  
Solvent Retention ◽  
Edge Temperature

Summary Laboratory and field data, although limited in number, have shown that steam/solvent coinjection can lead to a higher oil-production rate, higher ultimate oil recovery, and lower steam/oil ratio, compared with steam-only injection in steam-assisted gravity drainage (SAGD). However, a critical question still remains unanswered: Under what circumstances can the previously mentioned benefits be obtained when steam and solvent are coinjected? To answer this question requires a detailed knowledge of the mechanisms involved in coinjection and an application of this knowledge to numerical simulation. Our earlier studies demonstrated that the determining factors for improved oil-production rates are relative positions with respect to the temperature and solvent fronts, the steam and solvent contents of the chamber at its interface with reservoir bitumen, and solvent-diluting effects on the mobilized bitumen just ahead of the chamber edge. Then, the key mechanisms for improved oil displacement are solvent propagation, solvent accumulation at the chamber edge, and phase transition. This paper deals with this unanswered question by providing some key guidelines for selecting an optimum solvent and its concentration in coinjection of a single-component solvent with steam. The optimization considers the oil-production rate, ultimate oil recovery, and solvent retention in situ. Multiphase behavior of water/hydrocarbon mixtures in the chamber is explained in detail analytically and numerically. The proposed guidelines are applied to simulation of the Senlac solvent-aided-process pilot and the Long Lake expanding-solvent SAGD pilot. Results show that an optimum volatility of solvent can be typically observed in terms of the oil-production rate for given operation conditions. This optimum volatility occurs as a result of the balance between two factors affecting the oil mobility along the chamber edge: reduction of the chamber-edge temperature and superior dilution of oil in coinjection of more-volatile solvent with steam. It is possible to maximize oil recovery and minimize solvent retention in situ by controlling the concentration of a given coinjection solvent. Beginning coinjection immediately after achieving interwell communication enables the enhancement of oil recovery early in the process. Subsequently, the solvent concentration should be gradually decreased until it becomes zero for the final period of the coinjection. Simulation case studies show the validity of the oil-recovery mechanisms described. In the final section of the paper, a limited economic analysis of SAGD and different coinjection cases is provided.

scholarly journals Simultaneous lipid biosynthesis and recovery for oleaginous yeast Yarrowia lipolytica

2019 ◽  
Vol 12 (1) ◽  
Author(s):  
Pratik Prashant Pawar ◽  
Annamma Anil Odaneth ◽  
Rajeshkumar Natwarlal Vadgama ◽  
Arvind Mallinath Lali
Keyword(s):  
Yarrowia Lipolytica ◽  
Oil Recovery ◽  
Oleaginous Yeast ◽  
Fermentation Broth ◽  
Continuous Production ◽  
Oil Production ◽  
Biofuel Production ◽  
Oil Yield ◽  
Microbial Oil

Abstract Background Recent trends in bioprocessing have underlined the significance of lignocellulosic biomass conversions for biofuel production. These conversions demand at least 90% energy upgradation of cellulosic sugars to generate renewable drop-in biofuel precursors (Heff/C ~ 2). Chemical methods fail to achieve this without substantial loss of carbon; whereas, oleaginous biological systems propose a greener upgradation route by producing oil from sugars with 30% theoretical yields. However, these oleaginous systems cannot compete with the commercial volumes of vegetable oils in terms of overall oil yields and productivities. One of the significant challenges in the commercial exploitation of these microbial oils lies in the inefficient recovery of the produced oil. This issue has been addressed using highly selective oil capturing agents (OCA), which allow a concomitant microbial oil production and in situ oil recovery process. Results Adsorbent-based oil capturing agents were employed for simultaneous in situ oil recovery in the fermentative production broths. Yarrowia lipolytica, a model oleaginous yeast, was milked incessantly for oil production over 380 h in a media comprising of glucose as a sole carbon and nutrient source. This was achieved by continuous online capture of extracellular oil from the aqueous media and also the cell surface, by fluidizing the fermentation broth over an adsorbent bed of oil capturing agents (OCA). A consistent oil yield of 0.33 g per g of glucose consumed, corresponding to theoretical oil yield over glucose, was achieved using this approach. While the incorporation of the OCA increased the oil content up to 89% with complete substrate consumptions, it also caused an overall process integration. Conclusion The nondisruptive oil capture mediated by an OCA helped in accomplishing a trade-off between microbial oil production and its recovery. This strategy helped in realizing theoretically efficient sugar-to-oil bioconversions in a continuous production process. The process, therefore, endorses a sustainable production of molecular drop-in equivalents through oleaginous yeasts, representing as an absolute microbial oil factory.

scholarly journals An Improved Mathematical Model for Accurate Prediction of the Heavy Oil Production Rate during the SAGD Process

Processes ◽  
2020 ◽  
Vol 8 (2) ◽  
pp. 235
Author(s):  
Aria Rahimbakhsh ◽  
Morteza Sabeti ◽  
Farshid Torabi
Keyword(s):  
Production Rate ◽  
Penetration Depth ◽  
Oil Recovery ◽  
Current Model ◽  
Oil Production ◽  
Exponential Model ◽  
Analytical Models ◽  
Test Facility ◽  
Drainage Rate ◽  
Heat Penetration

Steam-assisted gravity drainage (SAGD) is one of the most successful thermal enhanced oil recovery (EOR) methods for cold viscose oils. Several analytical and semi-analytical models have been theorized, yet the process needs more studies to be conducted to improve quick production rate predictions. Following the exponential geometry theory developed for finding the oil production rate, an upgraded predictive model is presented in this study. Unlike the exponential model, the current model divides the steam-oil interface into several segments, and then the heat and mass balances are applied to each of the segments. By manipulating the basic equations, the required formulas for estimating the oil drainage rate, location of interface, heat penetration depth of steam ahead of the interface, and the steam required for the operation are obtained theoretically. The output of the proposed theory, afterwards, is validated with experimental data, and then finalized with data from the real SAGD process in phase B of the underground test facility (UTF) project. According to the results, the model with a suitable heat penetration depth correlation can produce fairly accurate outputs, so the idea of using this model in field operations is convincing.

scholarly journals NANO-SURFACTANT HUFF AND PUFF OPTIMATIZATION IN MARGINAL X FIELD USING COMMERCIAL SIMULATOR

2019 ◽  
Vol 42 (2) ◽  
pp. 51-57
Author(s):  
Ariel Paramastya ◽  
Steven Chandra ◽  
Wijoyo Niti Daton ◽  
Sudjati Rachmat
Keyword(s):  
Interfacial Tension ◽  
Production Rate ◽  
Oil Recovery ◽  
Oil And Gas ◽  
Oil Production ◽  
Full Scale ◽  
Economic Aspect ◽  
Economic Optimization ◽  
Single Well

Economic optimization of an oil and gas project is an obligation that has to be done to increase overall profi t, whether the fi eld is still economically feas ible or the fi eld has surpassed its economic limit. In this case, a marginal fi eld waschosen for the study. In this marginal fi eld EOR methods have been used to boost the production rate. However, a full scale EOR method might not be profi table due to the amount of resources that is required to do it. Alternatively, Huff and Puff method is an EOR technique that is reasonable in the scope of single well. The Huff and Puff method is an EOR method where a single well serves as both a producer and an injector. The technique of Huff and Puff: (1) The well isinjected with designed injection fl uid, (2) the well is shut to let the fl uid to soak in the reservoir for some time, and (3) the well is opened and reservoir fl uids are allowed to be produced. The injection fl uid (in this case, nano surfactant) is hypothesized to reduce interfacial tension between the oil and rock, thus improving the oil recovery. In this study, the application of Huff and Puff method using Nanoparticles (NPs) as the injected fl uid, as a method of improving oil recovery is presented in a case study of a fi eld in South Sumatra. The study resulted that said method yields an optimum Incremental Oil Production (IOP) in which the economic aspect gain more profi t, and therefore it is considered feasible to be applied in the fi eld.

scholarly journals Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3961
Author(s):  
Haiyang Yu ◽  
Songchao Qi ◽  
Zhewei Chen ◽  
Shiqing Cheng ◽  
Qichao Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Co2 Emission ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

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.

Efficiency Analysis of the Geological-Technical Activities in Severo-Ostrovnoe Field

2019 ◽  
Vol 16 (11) ◽  
pp. 4584-4588
Author(s):  
I. A. Pogrebnaya ◽  
S. V. Mikhailova
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Horizontal Wells ◽  
Oil Field ◽  
Field Development ◽  
Multi Stage ◽  
Field Works ◽  
Technical Measures

The work is devoted to identifying the most relevant geological and technical measures carried out in Severo-Ostrovnoe field from the period of its development to the present. Every year dozens of geotechnical jobs (GJ) are carried out at each oil field-works carried out at wells to regulate the development of fields and maintain target levels of oil production. Today, there are two production facilities in the development of the Severo-Ostrovnoe field: UV1a1 and BV5. With the help of geotechnical jobs, oil-producing enterprises ensure the fulfillment of project indicators of field development (Mikhailov, N.N., 1992. Residual Oil Saturation of Reservoirs Under Development. Moscow, Nedra. p.270; Good, N.S., 1970. Study of the Physical Properties of Porous Media. Moscow, Nedra. p.208). In total, during the development of the Severo-Ostrovnoe field, 76 measures were taken to intensify oil production and enhance oil recovery. 12 horizontal wells were drilled (HW with multistage fracking (MSF)), 46 hydraulic fracturing operations were performed, 12 hydraulic fracturing operations were performed at the time of withdrawal from drilling (HW with MSF), five sidetracks were cut; eight physic-chemical BHT at production wells; five optimization of well operation modes. The paper analyzes the performed geological and technical measures at the facilities: UV1a1∦BV5 of the Severo-Ostrovnoe field. Four types of geological and technical measures were investigated: hydraulic fracturing, drilling of sidetracks with hydraulic fracturing, drilling of horizontal wells with multi-stage hydraulic fracturing, and physic-chemical optimization of the bottom-hole formation zone. It was revealed that two geotechnical jobs, namely, formation hydraulic fracturing (FHF) and drilling of lateral shafts in the Severo-Ostrovnoe field are the most highly effective methods for intensifying reservoir development and increasing oil recovery. SXL was conducted at 5 wells. The average oil production rate is 26.6 tons per day, which is the best indicator. Before this event, the production rate of the well was 2.1 tons per day. Currently, the effect of ongoing activities continues.

Steam Alternating Solvent Process

2007 ◽  
Vol 10 (02) ◽  
pp. 185-190 ◽  
Author(s):  
Litong Zhao
Keyword(s):  
Energy Consumption ◽  
Water Treatment ◽  
Production Rate ◽  
Heavy Oil ◽  
Energy Input ◽  
Oil Production ◽  
Viscosity Reduction ◽  
Hydrocarbon Solvent ◽  
The Past

Summary A new heavy-oil-recovery process, the steam alternating solvent (SAS) process, is proposed and studied using numerical simulation. The process is intended to combine the advantages of the steam-assisted gravity drainage (SAGD) and vapor-extraction (vapex) processes to minimize the energy input per unit oil recovered. The SAS process involves injecting steam and solvent alternately, and the basic well configurations are the same as those in the SAGD process. Field-scale simulations were conducted to assess the SAS process performance under typical Cold Lake, Alberta, reservoir conditions. These results suggested that the oil-production rate of an SAS process could be higher than that of a SAGD process, while the energy input was 18% less than that of a SAGD process. By varying the length of the steam- and solvent-injection periods in a cycle, a different set of steam/oil and solvent/oil ratios may be obtained because the temperature profiles and solvent-concentration distributions in the vapor chamber can be affected by the injection pattern. The process therefore can be optimized for a specific reservoir under certain economic conditions. Introduction There are large heavy-oil and bitumen deposits in many areas of the world. The resources are especially enormous in northern Alberta, Canada. However, the high viscosity of these oils, usually more than 10 000 mPa×s, hinders the recovery of these resources. To recover such petroleum resources, two types of methods exist for the reduction of oil viscosity. The first is to increase oil temperature. This can be achieved by injecting a hot fluid, such as steam, into the formation, or by in-situ combustion through injecting oxygen-containing gases. The second method is to dilute the viscous petroleum by lower-viscosity hydrocarbon solvent. This method involves injecting a hydrocarbon solvent, such as propane or butane, or a mixture of hydrocarbons into the oil reservoir. As the solvent dissolves into viscous oil, the viscosity of the mixture becomes much lower than the original viscosity of the heavy oil. The diluted oil then can be recovered. The combinations of the above viscosity reduction methods and the horizontal-well technology have been the focus of research for the past 20 years. Two processes, SAGD and vapex, have been developed for the recovery of heavy-oil and bitumen resources (Butler et al. 1981; Butler and Mokrys 1991; Frauenfeld and Lillico 1999). The first has been tested successfully in the field and is currently the process of choice for commercial in-situ recovery (Edmunds et al. 1994; Mukherjee et al. 1995), while the second is starting initial field testing (Butler and Yee 2000). The advantage of the SAGD process is its high recovery and high oil-production rate. However, the high production rate is associated with excessive energy consumption, CO2 generation, and expensive post-production water treatment. The vapex process has the advantage of lower energy consumption (and, therefore, less CO2 generation) and much lower water-treatment costs. The major drawback of the vapex process, however, is its expected relatively lower oil-production rate and the uncertainty on reservoir retention of solvent. In the past several years, modifications have been proposed to improve SAGD's energy efficiency, either through injection of noncondensable gas with steam for reducing heat loss (Jiang et al. 1998) or through injection of solvents and steam together for increasing production rate (Nasr and Isaacs 2001). The combination of solvent with steam also has been studied in the steamflooding process (Farouq Ali and Abad 1976; Venturini and Mamora 2003).

An Experimental Study of the Post-CHOPS Cyclic Solvent Injection Process

2015 ◽  
Vol 137 (4) ◽  
Author(s):  
Zhongwei Du ◽  
Fanhua Zeng ◽  
Christine Chan
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Early Time ◽  
Oil Production ◽  
The Other ◽  
Late Time ◽  
Solvent Injection ◽  
Injection Process ◽  
Different Diameters

Cold heavy oil production with sand (CHOPS) has been applied successfully in many oil fields in Canada. However, typically only 5–15% of the original oil in place (OOIP) is recovered during cold production. Therefore, effective follow-up techniques are of great importance. Cyclic solvent injection (CSI), as a post-CHOPS process, has greater potential than continuous solvent injection to enhance heavy oil recovery. Continuous solvent injection results in early breakthrough due to the existence of wormholes; while in CSI process, the existence of wormholes can increase the contact area of solvent and heavy oil and the wormholes also provide channels that allow diluted oil to flow back to the wellbore. In this study, the effects of wormhole and sandpack model properties on the performance of the CSI process are experimentally investigated using three different cylindrical sandpack models. The length and diameter of the base model are 30.48 cm and 3.81 cm, respectively. The other two models, one with a larger length (i.e., 60.96 cm) and the other with a larger diameter (i.e., 15.24 cm), are used for up-scaling study in the directions parallel and perpendicular to the wormhole, respectively. The porosity and permeability of these models are about 35% and 5.5 Darcy typically. A typical western Canadian oil sample with a viscosity of 4330 mPa·s at 15 °C is used. And pure propane is selected as the solvent. The experimental results suggest that the existence of wormhole can significantly increase the oil production rate. The larger the wormhole coverage is, the better the CSI performance obtained. In terms of the effect of wormhole's location, a reservoir or well with wormholes developed at bottom is more favorable for post-CHOPS CSI process due to the gravity effect. The production of the CSI process can be divided into two phases: early time chamber rising and late time chamber spreading phases. The oil recovery factor in the chamber rising phase is almost independent of the sandpack model diameter; and the oil relative production rates (the oil production rate divided by the OOIP) in two models with different diameters are close during the chamber spreading phase due to similar solvent dispersion rate. It is also found that if the wormhole length is the same, the sandpack model length hardly affects the oil production rate in the earlier stage. In terms of the effects of the wormhole orientation, the well with a horizontal wormhole is inclined to get a good CSI performance. Through analyzing the experimental data, a relationship of oil production rate to drainage height is also obtained and verified.

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