Revisiting the Butler-Mokrys Model for the Vapor-Extraction Process

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 511-521
Author(s):  
V.. Mohan ◽  
P.. Neogi ◽  
B.. Bai
Keyword(s):  
Concentration Profile ◽  
Heavy Oil ◽  
Extraction Process ◽  
Previous Model ◽  
Oil Reservoir ◽  
Vapor Extraction ◽  
Oil Viscosity ◽  
Solvent Vapor ◽  
Vapor Interface ◽  
Heavy Oil Reservoir

Summary The dynamics of a process in which a solvent in the form of a vapor or gas is introduced in a heavy-oil reservoir is considered. The process is called the solvent vapor-extraction process (VAPEX). When the vapor dissolves in the oil, it reduces its viscosity, allowing oil to flow under gravity and be collected at the bottom producer well. The conservation-of-species equation is analyzed to obtain a more-appropriate equation that differentiates between the velocity within the oil and the velocity at the interface, which can be solved to obtain a concentration profile of the solvent in oil. We diverge from an earlier model in which the concentration profile is assumed. However, the final result provides the rate at which oil is collected, which agrees with the previous model in that it is proportional to h, where h is the pay-zone height; in contrast, some of the later data show a dependence on h. Improved velocity profiles can capture this dependence. A dramatic increase in output is seen if the oil viscosity decreases in the presence of the solvent, although the penetration of the solvent into the oil is reduced because under such conditions the diffusivity decreases with decreased solvent. One other important feature we observe is that when the viscosity-reducing effect is very large, the recovered fluid is mainly solvent. Apparently, some optimum might exist in the solubility φo, where the ratio of oil recovered to solvent lost is the largest. Finally, the present approach also allows us to show how the oil/vapor interface evolves with time.

scholarly journals The Research and Application of Microbial Degradation Technology on Heavy Oil Reservoir in Huabei Oilfield

2018 ◽  
Vol 38 ◽  
pp. 01054
Author(s):  
Guan Wang ◽  
Rui Wang ◽  
Yaxiu Fu ◽  
Lisha Duan ◽  
Xizhi Yuan ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
High Surface ◽  
Effective Rate ◽  
Water Flooding ◽  
Oil Reservoir ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Reservoir Conditions ◽  
Heavy Oil Reservoir

Mengulin sandstone reservoir in Huabei oilfield is low- temperature heavy oil reservoir. Recently, it is at later stage of waterflooding development. The producing degree of water flooding is poor, and it is difficult to keep yield stable. To improve oilfield development effect, according to the characteristics of reservoir geology, microbial enhanced oil recovery to improve oil displacement efficiency is researched. 2 microbial strains suitable for the reservoir conditions were screened indoor. The growth characteristics of strains, compatibility and function mechanism with crude oil were studied. Results show that the screened strains have very strong ability to utilize petroleum hydrocarbon to grow and metabolize, can achieve the purpose of reducing oil viscosity, and can also produce biological molecules with high surface activity to reduce the oil-water interfacial tension. 9 oil wells had been chosen to carry on the pilot test of microbial stimulation, of which 7 wells became effective with better experiment results. The measures effective rate is 77.8%, the increased oil is 1,093.5 tons and the valid is up to 190 days.

Study on Heating Zone and Producing Zone of Cyclic Steam Stimulation with Horizontal Well in Heavy Oil Reservoir

2012 ◽  
Vol 594-597 ◽  
pp. 2438-2441 ◽  
Author(s):  
Shi Jun Huang ◽  
Ping Hu ◽  
Qiu Li
Keyword(s):  
Heavy Oil ◽  
Horizontal Well ◽  
Thermal Recovery ◽  
Oil Reservoir ◽  
Heating Zone ◽  
Oil Viscosity ◽  
Cyclic Steam Stimulation ◽  
Heavy Oil Reservoir ◽  
Critical Viscosity ◽  
Steam Stimulation

In this paper, employing reservoir simulation and mathematical analysis methods, considering typical heavy oil reservoir and fluid thermal properties, the heating and producing shape of thermal recovery with horizontal well for different heavy oil reservoirs including ordinary, extra and super heavy oil are investigated based on the modification of thermal recovery parameters of different viscosity. By introducing heating radius and producing radius and considering the coupling effect of temperature, pressure and oil saturation fields, a quantitative expression between heating radius/producing radius and oil viscosity, formation thickness is presented, so is the impact of oil viscosity on the heating radius. Results shows that for Cyclic Steam Stimulation, the producing radius of horizontal well is bigger than its heating radius for light oil, both of which, however, shrink with higher viscosity. Beyond a critical viscosity, where the heating radius equals to the producing radius, the heating radius of horizontal well would be bigger than its producing radius. More over, the critical viscosity shows tight relationship to the formation thickness.

Cyclic Steam Stimulation Effect on Skin Factor Reviewed Case Study

2016 ◽  
Vol 818 ◽  
pp. 287-290 ◽  
Author(s):  
Wan Rosli Wan Sulaiman ◽  
Azza Hashim
Keyword(s):  
Production Rate ◽  
Heavy Oil ◽  
Development Program ◽  
Thermal Recovery ◽  
Reservoir Rock ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Cyclic Steam Stimulation ◽  
Heavy Oil Reservoir ◽  
Steam Stimulation

High oil viscosity is a major concern for recovery from heavy oil reservoir. Introducing heat to the formation has proven to be an effective way to improve mobility. The Heat transfer to the oil and reservoir rock is good for thermal recovery. The thermal recovery involves a well-known technique of cyclic steam stimulation which actually effect the nearby well area. Heavy oil reservoir which uses the thermal technique will experience the change of property. Fula North East (FNE) Sudanese field is located in the north-eastern part of Fula sub-basin. According to the development program of FNE, Bentiu layer (of Bentiu group) is the targeted reservoir where the pressure gradient is 285.65 psi/100m, perforation intervals is 540-533 m, and the average oil production rate of single well by applying the cyclic steam stimulation (CSS) is 236 bbl/d. For well- Q, (one of the hot wells) to void the bottom water the average production rate is 191 bbl/d. A minor change is observed in the key properties of the well when the skin affect is varied.

scholarly journals EVALUATION OF THE INFLUENCE OF THE UNDERLYING WATERS FOR DEVELOPING OF HEAVY OIL RESERVOIR PK1-3 OF THE VOSTOCHNO-MESSOYAKHSKOYE OIL FIELD BY USING WELL TESTS

2018 ◽  
pp. 57-63
Author(s):  
I. V. Kovalenko ◽  
S. K. Sokhoshko ◽  
D. A. Listoykin
Keyword(s):  
Heavy Oil ◽  
Horizontal Wells ◽  
Geological Structure ◽  
Oil Field ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Complex Geological Structure ◽  
Heavy Oil Reservoir ◽  
Well Tests

The article presents the experience in the stage of experimental industrial exploitation and industrial exploitation of the field with a system for the development of horizontal wells with non-standard oil properties (high oil viscosity) and complex geological structure (gas cap and aquifer). The focus of the article is on the estimation of aquifer activity by using well tests.

Influence Factor Research of Artificial-Interlayer Shape in Bottom-Water Heavy Oil Reservoir

2012 ◽  
Vol 524-527 ◽  
pp. 1245-1251
Author(s):  
Fu Lin Wang
Keyword(s):  
Numerical Simulation ◽  
Heavy Oil ◽  
Bottom Water ◽  
Influence Factor ◽  
Simulation Method ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Numerical Simulation Method ◽  
Volume Viscosity ◽  
Heavy Oil Reservoir

Artificial barrier morphology distribution mechanism and the EOR factors of he heavy oil reservoir with bottom water is be researched, Through numerical calculation and numerical simulation method. The model for calculating the height of the artificial-interlayer with curvilinear side surface is established. This model quantitatively describes the relationship between the artificial-interlayer height and oil yield, reservoir thickness, radial distance from well axis, reservoir permeability and crude oil viscosity. Maximum artificial-interlayer height and radius, the artificial-interlayer heights at different radial distances can be obtained according to this model. Through the case, the characteristics of artificial-interlayer form are analyzed, and rules of artificial-interlayer conformation are obtained when artificial-interlayer liquid with different volume, viscosity and race are injected. The further research are carried out through numerical simulation method, and the theoretical results are be Compared and verified which deepen the study of artificial-interlayer shape influence factor . Results show that: the volume and position of injected gel have more influence on development effect is obviously, the interlayer is designed 3M over the oil-water interface and thickness perforated is 6m is better, which provides a reference for the development of bottom-water reservoir.

Well-Placement Optimization in Heavy Oil Reservoirs Using a Novel Method of In Situ Steam Generation

2018 ◽  
Vol 141 (3) ◽  
Author(s):  
Tamer Moussa ◽  
Mohamed Mahmoud ◽  
Esmail M. A. Mokheimer ◽  
Mohamed A. Habib ◽  
Salaheldin Elkatatny
Keyword(s):  
Heavy Oil ◽  
Net Present Value ◽  
Recovery Process ◽  
Steam Injection ◽  
Optimization Techniques ◽  
Oil Reservoir ◽  
Steam Generation ◽  
Oil Viscosity ◽  
Heavy Oil Reservoir

Determination of optimal well locations plays an important role in the efficient recovery of hydrocarbon resources. However, it is a challenging and complex task. The objective of this paper is to determine the optimal well locations in a heavy oil reservoir under production using a novel recovery process in which steam is generated, in situ, using thermochemical reactions. Self-adaptive differential evolution (SaDE) and particle swarm optimization (PSO) methods are used as the global optimizer to find the optimal configuration of wells that will yield the highest net present value (NPV). This is the first known application, where SaDE and PSO methods are used to optimize well locations in a heavy oil reservoir that is recovered by injecting steam generated in situ using thermo-chemical reactions. Comparison analysis between the two proposed optimization techniques is introduced. On the other hand, laboratory experiments were performed to confirm the heavy oil production by thermochemical means. CMG STARS simulator is utilized to simulate reservoir models with different well configurations. The experimental results showed that thermochemicals, such as ammonium chloride along with sodium nitrate, can be used to generate in situ thermal energy, which efficiently reduces heavy-oil viscosity. Comparison of results is made between the NPV achieved by the well configuration proposed by the SaDE and PSO methods. The results showed that the optimization using SaDE resulted in 15% increase in the NPV compared to that of the PSO after 10 years of production under in situ steam injection process using thermochemical reactions.

Quantitative Evaluation on the Evolution of Water Cone Behavior in a Heavy Oil Reservoir With Bottom Water

2020 ◽  
Vol 142 (6) ◽  
Author(s):  
Kai Wang ◽  
Ke Li ◽  
Wensheng Zhou ◽  
Guojin Zhu ◽  
Yue Pan ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Bottom Water ◽  
Field Application ◽  
Physical Models ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Heavy Oil Reservoir ◽  
Water Cut ◽  
Effective Development

Abstract In order to solve the problem of the unclear understanding of the water cone behavior and its influencing factors of horizontal well in a heavy oil reservoir with bottom water, in this paper, a series of physical models were established to quantitatively describe the inner relationships between them and further illustrated their influence on the water-cut increasing law. The results showed that the water cone and water-cut grew quickly in the heavy oil reservoir with bottom water. The sweep efficiency of the basic 2D sand-pack model reaches 0.68. The decrement of crude oil viscosity increases the sweep efficiency to about 0.08. The increment of production pressure drop increases the sweep efficiency to about 0.05–0.07. Heterogeneity enhancement decreases the sweep efficiency to about 0.06. The addition of adjustment well and barriers increases the sweep efficiency to about 0.20 and 0.08, respectively. The final sweep efficiency of the whole water cone in the 3D sand-pack model reaches 0.42. Finally, we found that the water-cut increment rules are mainly affected by water cone behavior, production schedule, and the location and distribution of barriers. The study in this paper lays a foundation for the rational and effective development of heavy oil reservoirs with bottom water, which has a broad field application prospects in the future.

An Analytical Production Model for Primary Production and Cyclic Solvent Injection in a Heavy-Oil Reservoir

SPE Journal ◽  
2019 ◽  
Vol 24 (06) ◽  
pp. 2695-2710
Author(s):  
Hongze Ma ◽  
Gaoming Yu ◽  
Yuehui She ◽  
Yongan Gu
Keyword(s):  
Primary Production ◽  
Heavy Oil ◽  
Gas Production ◽  
Production Model ◽  
Production Data ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Solvent Injection ◽  
Foamy Oil ◽  
Heavy Oil Reservoir

Summary In this paper, we formulated an analytical material–balance model (MBM) to predict cumulative heavy–oil and gas-production data, as well as the average reservoir pressures, during the primary production and subsequent cyclic solvent injection (CSI) in a heavy–oil reservoir. The theoretical MBM considers the nonequilibrium foamy–oil phase behavior and foamy–oil flow by invoking two kinetic equations with nucleation and decay coefficients. In addition, we conducted four laboratory sandpack tests of the primary production and subsequent CSI to validate the new production model. It was found that the predicted cumulative heavy–oil production data and average reservoir pressures agreed reasonably well with the measured data during the primary production and subsequent CSI. However, there were large discrepancies between the predicted and measured cumulative gas-production data in the CSI owing to its strong gas channeling, which is a major technical issue to be studied further. Moreover, dissolved CH4 in the heavy oil became dispersed CH4 bubbles more quickly when the nucleation coefficient was larger at a higher pressure–drawdown rate or in less–viscous heavy oil. The foamy heavy oil with dispersed CH4 bubbles was more stable when the decay coefficient was smaller at a higher pressure–drawdown rate or in more–viscous heavy oil. It was also found that the foamy–oil isothermal compressibility increased by 10 to 1,000 times and that the dispersed–gas percentage in the foamy oil could reach as high as 14 vol% during the primary production. The foamy–oil viscosity was reduced by 36 to 55%, and the solution CH4/heavy–oil ratio was decreased by 41 to 76% at the end of the CSI.

scholarly journals Experimental study on percolation mechanism and displacement characteristics of cold recovery in offshore heavy oil field

2021 ◽  
Author(s):  
Ying-xian Liu ◽  
Jie Tan ◽  
Hui Cai ◽  
Gong-chang Wang ◽  
Song-ru Mou
Keyword(s):  
Crude Oil ◽  
Rheological Properties ◽  
Heavy Oil ◽  
Production Capacity ◽  
Oil Field ◽  
Water Flooding ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Heavy Oil Reservoir ◽  
Target Block

AbstractThe heavy oil reservoir is a special kind of oil and gas reservoir that differs from the conventional reservoir in many ways. Due to the high viscosity of crude oil, it is not easy to recover. When the viscosity of underground crude oil exceeds 150 cp, the land heavy oil field is generally developed by thermal recovery. S.Z. oilfield is a heavy oil reservoir in the Bohai Sea, with surface crude oil viscosity of 3000–25,000 cp and underground crude oil viscosity of 400–1000 cp. Limited by offshore equipment, the development strategy of land oilfields can't be directly applied. High production capacity is obtained through the cold production development of horizontal branch experimental wells, and the water drive production capacity can reach 40–70 m3/day. At present, there is a lack of research on cold recovery development under the viscosity of crude oil. The existing primary research and common knowledge are challenging to support efficient development technology for effectively producing heavy oil reservoirs. In this paper, through physical simulation experiments, the phase behavior and rheological properties of crude oil in the target block are studied, and the rheological properties of crude oil are clarified. Then, the depletion production and water flooding experiments are carried out, and the displacement characteristics and laws of water flooding cold production are analyzed. Finally, the indoor experiments of water flooding sweep efficiency and oil displacement efficiency in the target block are carried out. Clear its micro and macro spread. It provides technical support for the effective production of offshore heavy oil fields.

Autonomous Inflow-Control Devices Boost Production While Managing Sand

2021 ◽  
Vol 73 (10) ◽  
pp. 71-72
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Field ◽  
Oil Reservoir ◽  
Oil Viscosity ◽  
Alpha Wave ◽  
Offshore Technology ◽  
Control Devices ◽  
Heavy Oil Reservoir ◽  
Gravel Packing ◽  
Gravel Pack

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30403, “Sand Production Management While Increasing Oil Production of a Gravel-Packed Well Equipped With Rate-Controlled-Production Autonomous Inflow-Control Devices in a Thin Heavy-Oil Reservoir Offshore China,” by Shuquan Xiong, Fan Li, and Congda Wei, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. A 2018 infill development campaign for a horizontal well offshore China targeted improved production through the installation of autonomous inflow-control devices (AICDs). However, because the well requires gravel packing to manage the sand, the integration of AICDs and the gravel pack was an issue. An integrated work flow was followed to deliver the AICD application successfully in an offshore heavy-oil reservoir with major uncertainties in remaining oil thickness and water/oil contacts. AICD completions ensured balanced contribution from all reservoir sections and limited water production significantly while the gravel pack kept the valves safe from the effects of sand. Field Description The field is a low-amplitude fault anticline oil field developed on the basement uplift. The structure is relatively gentle (Fig. 1). The reservoir lithology is mainly feldspathic quartz sandstone, with an average porosity of 22%, an average permeability of 397 md, a reservoir pressure coefficient of 1, an oil density of 0.92 g/cm3, and crude oil viscosity of 150 cp. The current methodology for gravel packing with ICDs/AICDs in the well uses a multiple alpha-wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the buildup of the alpha wave. The flow rate is reduced progressively to maximize the dune weight until screenout is observed. Once the gravel-packing operation is complete, the standalone-screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. This methodology is most applicable in unconsolidated sands with high net-to-gross reservoirs where borehole collapse will occur early in well life. One technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint. However, in long lateral wellbores, this may be prohibitively expensive and requires multiple manual manipulations as the wash pipe is retrieved. The use of a temporary bypass valve is recommended to enable standard gravel-packing operations to be performed with ICDs without significant additional cost, complexity, or compromise. The dissolvable material is used with a valve located within the ICD/AICD housing to provide a high-flow-area path from the annulus to the tubing during completion operations.

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