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.

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.

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.

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.

Enhancing Oil Recovery With Bottom Water Drainage Completion

2014 ◽  
Vol 136 (4) ◽  
Author(s):  
Ephim Shirman ◽  
Andrew K. Wojtanowicz ◽  
Hilal Kurban
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Fold Increase ◽  
Recovery Process ◽  
Field Trials ◽  
Experimental Results ◽  
Water Drainage ◽  
Performance Study ◽  
Time Required

Field trials and physical modeling of wells with downhole water sink (DWS) completions have demonstrated controlled water coning and increased oil production rate. However, no field trials were long enough to show DWS potential in improving of oil recovery in comparison with conventional wells. Presented here are theoretical and experimental results from a DWS recovery performance study. The recovery study involved experiments with a physical model and computer simulations. The experimental results reveal that DWS dramatically accelerates the recovery process; a fivefold increase of the oil production rate was reached by adjusting the water drainage rate at the bottom completion. The results also show a 70% increase of oil recovery; from 0.52 to 0.88 for conventional and DWS completions, respectively. The computer-simulated experiments with commercial reservoir simulator demonstrate progressive improvement of recovery with downhole water drainage from 0.61 to 0.79 with no drainage and maximum drainage, respectively—a 24% increase of recovery factor, and a fivefold reduction of the time required to reach the limiting value of water cut, 0.98. However, the accelerated recovery process with DWS requires a substantial, up to 3.5-fold, increase of total water production. The simulation experiments also show that the main advantage of using DWS is its flexibility in controlling the recovery process. For conventional completions, recovery could be slightly increased by reducing production rates and largely increasing production times. For DWS, a combination of the top and bottom rates could be optimized for maximum recovery and minimum production time.

scholarly journals Correlation for Predicting Water Breakthrough Time in Thin Oil Rim Reservoirs in the Niger Delta

2018 ◽  
Vol 6 (3) ◽  
Author(s):  
Anietie Okon ◽  
Dulu Appah ◽  
Julius Akpabio
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Coefficient Of Determination ◽  
Reservoir Model ◽  
Breakthrough Time ◽  
Well Completion ◽  
Water Breakthrough ◽  
Oil Rim

In the Niger Delta, available correlations to predict water breakthrough time in thin oil rim reservoirs are based on generic reservoir models and/or experimental design approach. This approach had not considered the heterogeneity of the reservoir. Thus, the prediction of these available correlations for thin oil rim reservoirs in the Niger Delta is in doubt, considering the sensitive nature of developing thin oil rim reservoirs. Then, a correlation for water breakthrough time (tbt) was developed based on integrated reservoir model of thin oil rim reservoir in the Niger Delta. The obtained result indicated that the developed correlation predicted 1652.72 days compared to the actual Oilfield breakthrough time of 1653 days (about 4.53 years). Also, sensitivity study showed that the developed correlation and the integrated reservoir model predictions of oil production rate (qo), fractional well penetration (hp/h) and height above perforation-oil column (hap/h) on the water breakthrough time (tbt) were close and resulted in coefficient of determination (R2) of 0.9697, 0.8597 and 0.9553, respectively. Furthermore, the results depicted that water coning breakthrough time (tbt) depends directly on oil production rate (q) and well completion parameters: fractional well penetration (hp/h) and height above perforation (hap). Hence, to delay early water breakthrough in thin oil rim reservoirs, these completion parameters are consideration in vertical wells to achieve optimum oil recovery. Also, the developed correlation can be used as a quick and robust tool to predict water breakthrough time of thin oil rim reservoirs in the Niger Delta.

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.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

2014 ◽  
Vol 17 (03) ◽  
pp. 304-313 ◽  
Author(s):  
A.M.. M. Shehata ◽  
M.B.. B. Alotaibi ◽  
H.A.. A. Nasr-El-Din
Keyword(s):  
Oil Recovery ◽  
Sudden Change ◽  
Oil Production ◽  
Deionized Water ◽  
Production Performance ◽  
Shallow Aquifer ◽  
Secondary Recovery ◽  
Tertiary Recovery ◽  
The Impact ◽  
Indiana Limestone

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

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.

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