DEVELOPMENT OF A FIELD MOBILE STANDARD OF THE 2ND CATEGORY AS A TOOL FOR VERIFYING WELL PRODUCTION MEASURING EQUIPMENT

2021 ◽  
Vol 7 (1) ◽  
pp. 163-176
Author(s):  
Vladimir E. VERSHININ ◽  
Sergey G. NIKULIN ◽  
Andrej A. Stupnikov
Keyword(s):  
Oil Recovery ◽  
Gas Flow ◽  
Oil Production ◽  
Production Optimization ◽  
Accuracy Class ◽  
Associated Gas ◽  
Well Production ◽  
Advantages And Disadvantages ◽  
Measuring Devices ◽  
Accuracy Of Measurements

In recent years, in the oil production industry there is a tendency of mass use of stationary multiphase metering units for determining oil, water, and associated gas flow rates in the recoverable well production. Automated group metering units, allowing to cover the whole group of wells in rotation metering mode, became widespread. The necessity of equipping wells with individual or group measuring devices is dictated, first of all, by the economic tasks of improving oil recovery factor and production optimization. In these conditions, the task of periodic verification of stationary measuring devices in the field with the help of mobile standards-measuring devices of higher accuracy class becomes urgent. The standard’s mobility and the need to work in the field with fluids of different composition significantly complicates the task of creating such a device. The practicality and economy of the created units first of all depends on a choice of a measuring method determining the design of the unit. This article analyzes the existing types of equipment for measuring oil, gas, and water consumption at the oil production wells. Showing the main advantages and disadvantages of each of them, this paper proves the necessity of using complex solutions based on different physical principles to improve the accuracy of measurements. The authors have proposed a combined scheme of a mobile standard of the 2nd category with a dynamic method for measuring the phase rates at the core. The unit performs a multi-stage partial separation of the input multiphase flow into liquid and gas phases and determines the fractions of water and oil in the liquid stream using a hydrostatic-type mixture composition analyzer. In addition, this article indicates the ways of increasing the accuracy of the measuring installation.

scholarly journals Application of an Oil-Displacing Composition for Increasing Flow Rate of Low Producing High-Viscosity Oil Wells of the Usinskoye Oil Field

2016 ◽  
Vol 18 (2) ◽  
pp. 133
Author(s):  
L.K. Altunina ◽  
I.V. Kuvshinov ◽  
V.A. Kuvshinov ◽  
V.S. Ovsyannikova ◽  
D.I. Chuykina ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
High Viscosity ◽  
Oil Field ◽  
Thermal Methods ◽  
Cold Stimulation ◽  
Well Production ◽  
Well Stimulation ◽  
High Viscosity Oil ◽  
Stimulation Of

The results of a pilot application of a chemical composition for enhanced oil recovery developed at the IPC SB RAS are presented. The EOR-composition was tested in 2014 at the Permian-Carboniferous heavy oil deposit at the Usinskoye oil field. It is very effective for an increase in oil production rate and decrease in water cuttings of well production. In terms of the additionally produced oil, the resulting effect is up to 800 tons per well and its duration is up to 6 months. The application of technologies of low-productivity-well stimulation using the oil-displacing IKhNPRO system with controlled viscosity and alkalinity is thought to be promising. This composition is proposed for the cold’ stimulation of high-viscosity oil production as an alternative to thermal methods.

Improving Oil Recovery Through Fracture Injection and Production of Multiple Fractured Horizontal Wells

2020 ◽  
Vol 142 (5) ◽  
Author(s):  
Youwei He ◽  
Shiqing Cheng ◽  
Zhe Sun ◽  
Zhi Chai ◽  
Zhenhua Rui
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Horizontal Wells ◽  
Co2 Injection ◽  
Production Rates ◽  
Well Production ◽  
Well Completion ◽  
Tight Formations ◽  
Fractured Horizontal Wells ◽  
The Impact

Abstract Well production rates decline quickly in the tight reservoirs, and enhanced oil recovery (EOR) is needed to increase productivity. Conventional flooding from adjacent wells is inefficient in the tight formations, and Huff-n-Puff also fails to achieve the expected productivity. This paper investigates the feasibility of the inter-fracture injection and production (IFIP) method to increase oil production rates of horizontal wells. Three multi-fractured horizontal wells (MFHWs) are included in a cluster well. The fractures with even and odd indexes are assigned to be injection fractures (IFs) and recovery fractures (RFs). The injection/production schedule includes synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). The production performances of three MFHWs are compared by using four different recovery approaches based on numerical simulation. Although the number of RFs is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than depletion and CO2 Huff-n-Puff. The sensitivity analysis is performed to investigate the impact of parameters on IFIP. The spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect oil production significantly, followed by the length of RFs, well spacing among MFHWs, and the length of IFs. The suggested well completion scheme for the IFIP methods is presented. This work discusses the ability of the IFIP method in enhancing the oil production of MFHWs.

Reservoir monitoring using borehole radars to improve oil recovery: Suggestions from 3D electromagnetic and fluid modeling

Geophysics ◽  
2018 ◽  
Vol 83 (2) ◽  
pp. WB19-WB32 ◽  
Author(s):  
Feng Zhou ◽  
Mattia Miorali ◽  
Evert Slob ◽  
Xiangyun Hu
Keyword(s):  
Oil Recovery ◽  
Production Control ◽  
Recovery Period ◽  
Oil Production ◽  
Control Procedure ◽  
Water Production ◽  
Proactive Control ◽  
Well Production ◽  
Reservoir Monitoring ◽  
Borehole Radar

The recently developed smart well technology allows for sectionalized production control by means of downhole inflow control valves and monitoring devices. We consider borehole radars as permanently installed downhole sensors to monitor fluid evolution in reservoirs, and it provides the possibility to support a proactive control for smart well production. To investigate the potential of borehole radar on monitoring reservoirs, we establish a 3D numerical model by coupling electromagnetic propagation and multiphase flow modeling in a bottom-water drive reservoir environment. Simulation results indicate that time-lapse downhole radar measurements can capture the evolution of water and oil distributions in the proximity (order of meters) of a production well, and reservoir imaging with an array of downhole radars successfully reconstructs the profile of a flowing water front. With the information of reservoir dynamics, a proactive control procedure with smart well production is conducted. This method observably delays the water breakthrough and extends the water-free recovery period. To assess the potential benefits that borehole radar brings to hydrocarbon recovery, three production strategies are simulated in a thin oil rim reservoir scenario, i.e., a conventional well production, a reactive production, and a combined production supported by borehole radar monitoring. Relative to the reactive strategy, the combined strategy further reduces cumulative water production by 66.89%, 1.75%, and 0.45% whereas it increases cumulative oil production by 4.76%, 0.57%, and 0.31%, in the production periods of 1 year, 5 years, and 10 years, respectively. The quantitative comparisons reflect that the combined production strategy has the capability of accelerating oil production and suppressing water production, especially in the early stage of production. We suggest that borehole radar is a promising reservoir monitoring technology, and it has the potential to improve oil recovery efficiency.

scholarly journals Analysis of the Efficiency of Sidetracking in the Variogan Field

2020 ◽  
Vol 126 (1) ◽  
pp. 30-33
Author(s):  
N. R. Yarkeeva ◽  
◽  
D. V. Imangulov ◽  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Development Status ◽  
Well Production ◽  
Rate Of Increase ◽  
Selection Of ◽  
Recovery Methods

The article discusses one of the most promising oil recovery methods - sidetracking (sidetracking), explores the development status of formation that use this method, and justifies the selection of candidate wells for its implementation. Based on the example of the Variogan field, the effectiveness of the sidetracking operations was determined depending on the increase in well production. Using the obtained dependence, we can estimate the rate of increase in cumulative oil production.

Sharpening a Cyclic Solvent Injection Technique in a Heavy Oil Reservoir from the Variation of the Nitrogen Injected as Dispersing: A Field Pilot, Colombia

2021 ◽  
Author(s):  
Andres Solano Arias ◽  
Edgar Garzon Navarro ◽  
Fernando Contreras Munevar ◽  
Isaac Luque Ortiz
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Gas Flow ◽  
Oil Production ◽  
Dilution Effect ◽  
Injection Technique ◽  
Solvent Concentration ◽  
Solvent Injection ◽  
Production Stage ◽  
Production Stages

Abstract This paper analyzes the use of a cyclic solvent injection technique (CSI) as a non-thermal EOR alternative to cyclic steam stimulation (CSS) for increasing the heavy oil recovery in a shallow reservoir located at the middle Magdalena basin in Colombia. A pilot well with less than 30% of water-cut and 10.9 °API was selected. Heavy natural gasoline of 30 °API obtained from the same reservoir was injected by using nitrogen (N2) as dispersing gas. Three procedures were performed being the procedure A, a Solvent slug injection of 60 bbl through the annular pushed and dispersed by 46,444 m3 (1,640 Mscf) of N2 immiscible (considering the low reservoir pressure). The procedure B consisted of injecting the same Solvent volume, but this time pushed by a third part of the N2 injected previously 15,481 m3 (547 Mscf). The procedure C consisted of only inject the same N2 volume than B procedure to analyze the heavy oil response without Solvent. There were collected production data, °API (by hydrometer), gas-flow and gas-gravity values using a liquid level software. Knowing the °API of each component in the laboratory—Solvent and heavy oil—the Solvent concentration from the real °API produced in production stages was calculated. All procedures had 48 hours of soaking, followed by a flowing process to tank to carefully release the excess of N2 before starting the production stage, avoiding gas lock issues. Without considering the Solvent injected, incremental oil production in procedure A was 232 bbl, in procedure B was 120 bbl and for procedure C, incremental oil only reached 11 bbl. With the last result it was determined the N2 injection by itself as a production mechanism without the Solvent effect in the in-situ heavy oil had a negligible effect on incremental oil. The gas-gravity showed the gas composition became heavier along the time, this considering the high-frequency N2 injections swept the methane near the well, requiring more time to produce the N2 traces from the porous media. The excess of N2 as a heavy Solvent dispersing mechanism does not warrant a better dilution effect since as observed in A and B procedures, Solvent concentration in the early production stage never dropped below 35% (17 °API), regardless of the N2 volume injected in the first two days. Finally, although A procedure had more incremental oil production (+93% than B), less N2 injected in B procedure was more efficient (+55% than A) regarding the incremental oil and N2 injected ratio (ONR).

Argon Plasma Coagulation: Elucidation of the Mechanism of Gas Embolism

Respiration ◽  
2021 ◽  
pp. 1-5
Author(s):  
Erik E. Folch ◽  
Catherine L. Oberg ◽  
Atul C. Mehta ◽  
Adnan Majid ◽  
Colleen Keyes ◽  
...  
Keyword(s):  
Direct Contact ◽  
Gas Flow ◽  
Argon Plasma Coagulation ◽  
Argon Plasma ◽  
Tracheobronchial Tree ◽  
Bleeding Complications ◽  
Gas Transfer ◽  
Gas Embolism ◽  
Associated Gas ◽  
Plasma Coagulation

<b><i>Background:</i></b> Argon plasma coagulation (APC) is a tool used in the management of tracheobronchial obstruction or bleeding. Complications include gas embolism which can cause devastating effects including hemodynamic instability, cardiac arrest, and stroke. Multiple theories as to how gas embolism occurs with APC have been postulated; however, none have identified the exact mechanism. <b><i>Objectives:</i></b> To identify the mechanism by which APC causes gas embolism in the tracheobronchial tree. <b><i>Methods:</i></b> Using an explanted porcine tracheobronchial tree with lung parenchyma, the APC catheter was applied through noncontact and direct contact to the endobronchial airway mucosa via flexible bronchoscopy. This was done at multiple gas flow settings and pulse durations. Visual changes in the mucosa were photographed, videoed, and described. <b><i>Results:</i></b> Gross evidence of submucosal gas transfer occurred when the APC catheter was in direct contact with the mucosa at all gas flow settings in all applications, despite using shorter pulse durations. Whenever the catheter was not in contact with the mucosa, there was no transfer of gas at any gas flow setting or pulse duration. <b><i>Conclusions:</i></b> Direct mucosal contact with the APC probe leads to submucosal gas deposition and is a likely mechanism for gas entry into the intravascular space. In reported cases of APC-associated gas embolism, presence of a vascularized endobronchial tumor may have increased the risk of gas tracking into the intravascular space. Care should be taken when applying APC during brisk bleeding or limited vision, as inadvertent mucosal contact may occur and could increase the risk of gas embolism.

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.

Sign in / Sign up

Export Citation Format

Share Document