Thermal Recovery Study for Improving Oil Recovery of Heavy Oil Accumulation with Strong Water Drive Mechanism in Sultanate of Oman

2018 ◽  
Author(s):  
M. Dinata ◽  
M. A. Arham ◽  
H. S. Sudono ◽  
A. Badar ◽  
A. Badr ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Thermal Recovery ◽  
Sultanate Of Oman ◽  
Oil Accumulation ◽  
Drive Mechanism ◽  
Recovery Study

Research Status and Prospect of Heavy Oil Recovery Technology

2021 ◽  
Vol 888 ◽  
pp. 111-117
Author(s):  
Yi Zhao ◽  
De Yin Zhao ◽  
Rong Qiang Zhong ◽  
Li Rong Yao ◽  
Ke Ke Li
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Development Trend ◽  
Thermal Recovery ◽  
Hot Water ◽  
Water Flooding ◽  
Oil Reservoir ◽  
Heavy Oil Recovery ◽  
Steam Flooding ◽  
Heavy Oil Reservoir

With the continuous exploitation of most reservoirs in China, the proportion of heavy oil reservoirs increases, and the development difficulty is greater than that of conventional reservoirs. In view of the important subject of how to improve the recovery factor of heavy oil reservoir, the thermal recovery technology (hot water flooding, steam flooding, steam assisted gravity drainage SAGD and steam huff and puff) and cold recovery technology (chemical flooding, electromagnetic wave physical flooding and microbial flooding) used in the development of heavy oil reservoir are summarized. The principle of action is analyzed, and the main problems restricting heavy oil recovery are analyzed The main technologies of heavy oil recovery are introduced from the aspects of cold recovery and hot recovery. Based on the study of a large number of literatures, and according to the development trend of heavy oil development, suggestions and prospects for the future development direction are put forward.

Experimental Design and Evaluation of Surfactant Polymer for a Heavy Oil Field in South of Sultanate of Oman

2021 ◽  
Author(s):  
Ali Reham Al-Jabri ◽  
Rouhollah Farajzadeh ◽  
Abdullah Alkindi ◽  
Rifaat Al-Mjeni ◽  
David Rousseau ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Field ◽  
Reservoir Rock ◽  
Sultanate Of Oman ◽  
Industrial Chemicals ◽  
Oil Viscosity ◽  
Injection Strategy ◽  
Operational Conditions

Abstract Heavy oil reservoirs remain challenging for surfactant-based EOR. In particular, selecting fine-tuned and cost effective chemical formulations requires extensive laboratory work and a solid methodology. This paper reports a laboratory feasibility study, aiming at designing a surfactant-polymer pilot for a heavy oil field with an oil viscosity of ~500cP in the South of Sultanate of Oman, where polymer flooding has already been successfully trialed. A major driver was to design a simple chemical EOR method, to minimize the risk of operational issues (e.g. scaling) and ensure smooth logistics on the field. To that end, a dedicated alkaline-free and solvent-free surfactant polymer (SP) formulation has been designed, with its sole three components, polymer, surfactant and co-surfactant, being readily available industrial chemicals. This part of the work has been reported in a previous paper. A comprehensive set of oil recovery coreflood tests has then been carried out with two objectives: validate the intrinsic performances of the SP formulation in terms of residual oil mobilization and establish an optimal injection strategy to maximize oil recovery with minimal surfactant dosage. The 10 coreflood tests performed involved: Bentheimer sandstone, for baseline assessments on large plugs with minimized experimental uncertainties; homogeneous artificial sand and clays granular packs built to have representative mineralogical composition, for tuning of the injection parameters; native reservoir rock plugs, unstacked in order to avoid any bias, to validate the injection strategy in fully representative conditions. All surfactant injections were performed after long polymer injections, to mimic the operational conditions in the field. Under injection of "infinite" slugs of the SP formulation, all tests have led to tertiary recoveries of more than 88% of the remaining oil after waterflood with final oil saturations of less than 5%. When short slugs of SP formulation were injected, tertiary recoveries were larger than 70% ROIP with final oil saturations less than 10%. The final optimized test on a reservoir rock plug, which was selected after an extensive review of the petrophysical and mineralogical properties of the available reservoir cores, led to a tertiary recovery of 90% ROIP with a final oil saturation of 2%, after injection of 0.35 PV of SP formulation at 6 g/L total surfactant concentration, with surfactant losses of 0.14 mg-surfactant/g(rock). Further optimization will allow accelerating oil bank arrival and reducing the large PV of chase polymer needed to mobilize the liberated oil. An additional part of the work consisted in generating the parameters needed for reservoir scale simulation. This required dedicated laboratory assays and history matching simulations of which the results are presented and discussed. These outcomes validate, at lab scale, the feasibility of a surfactant polymer process for the heavy oil field investigated. As there has been no published field test of SP injection in heavy oil, this work may also open the way to a new range of field applications.

The Application of the Multi-Component Thermal Fluid Huff and Puff Technology to Daqing Heavy Oil Block

2021 ◽  
Author(s):  
Xianjun Wang ◽  
Xiangbin Liu ◽  
Borui Li ◽  
Qiang Yin ◽  
Zhonglian Han ◽  
...  
Keyword(s):  
High Temperature ◽  
Corrosion Inhibitor ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Thermal Recovery ◽  
Gas Absorption ◽  
Composition Ratio ◽  
Steam Flooding ◽  
Gas Channeling ◽  
Lock In

Abstract The reservoir of Daqing Heidimiao Oilfield (permeability 1736×10−3μm2) contains heavy oil, with the average viscosity of 3306 mPa•s. It is developed by steam flooding and steam huff and puff, however, the recovery rate is only 14.6%. Therefore, the multi-component thermal fluid huff-and-puff technology is applied to, dealing with pertinent problems such as gas channeling, corrosion and oil pump lock in the process so as to improve oil recovery and production. Mechanism: Cooling by water, the ultra-high temperature gas generated via combustion of diesel or natural gas with air produces a multi-component thermal fluid containing CO2,N2 and vapor, combining the advantages of gas absorption and thermal recovery. Simulation: A multi-component and multi-phase percolation model is built to optimize the huff-and-puff parameters including composition ratio, temperature and injection volume. Supporting techniques: a high temperature oil-and-acid resistant foam system to form a precedent-blocking slug and automatically adjust the huff-and-puff profile. a dedicated low-cost and high-efficiency corrosion inhibitor system to realize corrosion-resistance. a four-node down-hole gas-liquid separation device to increase efficiency. The comprehensive reduced-viscosity rate is more than 30%; high-pressure air chambers, ranging from 0.2 to 2.0MPa, are formed for elastic energy replenishment. Field tests show the average annual oil increase per well is about 3800 barrels, with the highest being about 7200 barrels. The numerical simulation results show that the optimal composition ratio (N2: CO2: vapor) is 5:1:1.5, that the best injection amount is 30∼50×104Nm3 and that the injection temperature is preferably 280 ∼ 300 °C. The oil-and-acid resistant foaming agent has improved recovery efficiency, as a significantly improved profile of gas absorption, and the oil extraction degree increases by about 31.5%. High temperature corrosion is prevented, through intermittent injection of high-temperature-resistant corrosion inhibitor (corrosion inhibition rate 70.5% at 350 °C), and the frequency of pipeline corrosion is reduced averagely by 98.5%. Air-lock in pump vanishes via gas-liquid separation devise, with the average indoor pump efficiency increases by more than 50% (gas-liquid ratio ≤3000m3/m3)and the one in field test increases from less than 20% to over 45%. More importantly, the maintenance period has reached 662d. This technology has been applied to 98 wells in Daqing to date, 95 of which are stimulated successfully. The multi-component thermal fluid huff-and-puff technology solves the problems such as gas channeling, corrosion and air-lock in pumps through supporting techniques and the synergism of steam flooding and thermal recovery to enhance oil recovery and can be used as a superseded technology after steam huff-and-puff treatment to increase the EUR, especially for heavy oil reservoirs with medium and high permeability.

Research on Hydrothermal Modification of Heavy Oil

2014 ◽  
Vol 1008-1009 ◽  
pp. 312-318 ◽  
Author(s):  
Ke Xu ◽  
Yun Hong Ding ◽  
Wei Dong Liu ◽  
Jin Chang
Keyword(s):  
Small Molecules ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Structural Parameters ◽  
Static Condition ◽  
Atomic Ratio ◽  
Thermal Recovery ◽  
Colloidal Structure ◽  
Hydrothermal Modification

Thermal recovery technology are widely used to enhance heavy oil recovery, the four most important of which are thermal modification, sub-critical water modification, catalytic modification and catalytic modification with hydrogen donor. These four kinds of technologies previously were studied separately, which were not systematically integrated together. This paper used high-temperature and high-pressure reactor to simulate heavy oil’s thermal recovery in static condition. By studying basic properties and structural parameters changed of four kinds of thermal recovery technologies, we have drawn the conclusion that The quality of crude oil dropped only by the use of TM, and The degrees of improvement were as follows: CMH> CM> SWM . H/C (Atomic ratio), fA, fN, fPand CI were important parameters, which could explain the extent of condensation and condensation direction. Long chain sulfur compound break down into small molecules, damaging the colloidal structure of heavy oil, improving the quality of heavy irreversible.

Comparative Effectiveness of CO2 Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery

1999 ◽  
Vol 2 (03) ◽  
pp. 238-247 ◽  
Author(s):  
Raj K. Srivastava ◽  
Sam S. Huang ◽  
Mingzhe Dong
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Thermal Recovery ◽  
Oil Reservoirs ◽  
Heavy Oil Recovery ◽  
Heavy Oil Reservoirs ◽  
The World ◽  
Recovery Methods

Summary A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2), a produced gas (containing 15 mol?% CO2 in CH4), and pure CO2 . The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada. PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods. Introduction A sizable number of heavy-oil reservoirs in Canada1 and in other parts of the world are thin and shaly. Some of these reservoirs are also characterized by low-oil saturation, heterogeneity, low permeability, and bottom water.2,3 For example, about 55% of 1.7 billion m3 of proven heavy-oil resource in the Lloydminster and Kindersley region in Saskatchewan, Canada, is contained in less than 5 m (15 ft.) pay zone and nearly 97% is in less than 10 m (30 ft.) pay zone.4,5 Primary and secondary methods combined recover only about 7% of the proven initial oil in place (IOIP).1 Such reservoirs are not amenable to thermal recovery methods: heat is lost excessively to surroundings and steam is scavenged by bottomwater zones.6,7 The immiscible gas displacement appears to be a very promising enhanced oil recovery (EOR) process for these thin reservoirs. The immiscible gas EOR process has the potential to access more than 90% of the total IOIP.1,7 It could, according to previous studies,6–12 recover up to an additional 30% IOIP incremental over that recovered by initial waterflood for some moderately viscous oils. For the development of a viable immiscible gas process applicable to moderately viscous heavy oils found in this sort of reservoirs, we selected three injection gases for study: CO2 reservoir-produced gas (RPG), and flue gas (FG) from power plant exhausts. Extensive literature is available on CO2 flooding for heavy-oil recovery, dealing with pressure/volume/temperature (PVT) behavior,3,6,7,13-15 oil recovery characteristics from linear and scaled models,3,6-8,10-12,15,16 numerical simulation, and field performance.17–19 However, only limited data are available on flue gas and produced gas flooding.20–22 To determine the most suitable gas for EOR application from laboratory investigations, we need knowledge of the physical and chemical interaction between gas, reservoir oil, and formation rock; and information on the recovery potential for various injection gases for a targeted oil. The test oil selected for this study was from the Senlac reservoir (14° API) located in northwest Saskatchewan (Lloydminster area). The PVT properties for the oil/injection gas mixtures were measured and compared. A comparative study of the oil recovery behavior for Senlac dead oil and Senlac reservoir fluid was carried out with different injection gases to assess their relative effectiveness for EOR. Senlac Reservoir Geology The Senlac oil pool is located within the lower Cretaceous sand/shale sequence of the Mannville Group. The Mannville thickens northward and lies unconformably on the Upper Devonian Carbonates of the Saskatchewan Group. The trapping mechanism for the oil is mainly stratigraphic. The lower Lloydminster oil reservoir is a wavy, laminated, very fine- to fine-grained, well sorted, and generally unconsolidated sandstone. It exhibits uniform dark oil staining throughout, interrupted by a number of shale beds of 2 to 9 m (6 to 27 ft) thick, which are distributed over the entire reservoir. The reservoir is overlain by a shale/siltstone/sandstone sequence and lies on a 3 m (9 ft) thick coal seam. The detailed reservoir (Senlac) data and operating characteristics are provided in Ref. 5. The reservoir temperature is 28°C (82.4°F) and the reservoir pressure varies between 2.5 and 4.1 MPa (363 and 595 psia). The virgin pressure of the reservoir at discovery was 5.4 MPa (783 psia) and the gas/oil ratio (GOR) was 16.2 sm3/m3 (89.8 sft3 /bbl). The reservoir matrix has a porosity of about 27.7% by volume and permeability of about 2.5 mD. The average water saturation is about 32% pore volume (PV). The pattern configuration for oil production is five-spot on a 16.2 ha (40 acre) drainage area. The estimated primary and secondary (solution gas and waterflood) recovery is 5.5% of the initial oil in place. Experiment Wellhead Dead Oil and Brine. Senlac wellhead dead oil and formation brine (from Well 16-35-38-27 W3M) were supplied by Wascana Energy, Inc. The oil was cleaned for the experiments by removal of basic sediment and water (BS&W) through high-speed centrifugation. The chemical and physical properties of cleaned Senlac stock tank oil are shown in Table 1. The formation brine was vacuum filtered twice to remove iron contamination from the sample barrels.

Design of a New Type Intelligent Transformation Joint in Heavy Oil Thermal Recovery

2015 ◽  
Vol 1090 ◽  
pp. 238-244
Author(s):  
Chuan Jun Li ◽  
Wan Wan Huang ◽  
Bin Han ◽  
Kai Li ◽  
Shu Wen Liu
Keyword(s):  
High Temperature ◽  
Energy Loss ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Pressure Difference ◽  
High Reliability ◽  
Fluid Pressure ◽  
Material Model ◽  
Thermal Recovery ◽  
Well Testing

In order to improve the efficiency of the heavy oil thermal recovery in high temperature and high pressure conditions, a new transformation joint was designed based on the theory of fluid pressure difference. Through the automatic displacement of a one-way valve and a seal tongue under the action of pressure difference, it realized intelligent transformation between the production status and the well testing status. According to the oil recovery requirements about structure size, energy loss, high temperature sealing property and high temperature resistance, thermal expansion of material, designs about structure, key sizes, material model and sealing parts were carried out, and strength of key parts was verified theoretically. Fluent was used to simulate the internal flows of the structure, to analyze and verify the energy loss under the working status. The result shows that the product can meet the requirements of heavy oil exploitation, and its simple structure, high reliability and strong durability can greatly improve the efficiency of crude oil recovery.

Research on Heavy Oil Thermal Recovery by CO2 Steam Flooding with Help of Combination of Borehole-Surface Electric Potential and Cross-Borehole Electric Potential

2011 ◽  
Vol 29 (6) ◽  
pp. 797-815 ◽  
Author(s):  
Benyu Su ◽  
Yasuhiro Fujimitsu
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Electric Potential ◽  
Sparse Matrix ◽  
Global Strategy ◽  
Thermal Recovery ◽  
Heavy Oil Recovery ◽  
Steam Flooding ◽  
The World ◽  
Borehole Surface

With an increasing tendency towards more demand for energy resources, the supply of energy as a focus of global strategy is attracting more and more attention from the world. However, on the one hand, conventional hydrocarbon resources are decreasing gradually, and therefore it is definitely an urgent task to search for renewable and replaceable resources at the present time. On the other hand, it has been proved that the total reserves of heavy oil are already up to 1105×108 tons around the world, which means that exploring heavy oil can be a beneficial supplement for alleviating the shortage of oil and gas. Moreover, it is noteworthy that because the heavy oil can be exploited by heated CO2, collecting and consuming CO2 during the production process will help to relieve global warming. In this study, we take the feasibility of heavy oil recovery by CO2 steam into consideration only from the viewpoint of geophysics. In the process of research, with the help of borehole-surface electric potential and cross-borehole electric potential, the entire procedures from heating heavy oil reservoir and optimizing the location of well to deciding the layer of perforation are exhibited completely. In the course of calculation, potential distributions corresponding to a point source of current are acquired by solving the Poisson equation using a direct and explicit finite difference technique for a lower half-space with 3-D distribution of conductivity. As for computation of a large sparse matrix, the technique of nonzero bandwidth storage and the Incomplete Cholesky Conjugate Gradient method are adopted. The consequences prove that with the assistance of cross-borehole electric potential combining with borehole-surface electric potential, the project of heavy oil recovery by CO2 steam is feasible and effective.

scholarly journals Influence of the Interfacial Properties on the Stability of Water in Heavy Oil Emulsions in Thermal Recovery Process

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-11
Author(s):  
Yongtao Sun ◽  
Zhaomin Li
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Interfacial Properties ◽  
Thermal Recovery ◽  
Oil Reservoir ◽  
Stirring Rate ◽  
Heavy Oil Reservoir ◽  
The Stability ◽  
Increasing Temperature ◽  
Stability Of Water

Under the conditions of thermal oil recovery, the heavy oil in a reservoir usually exists in the form of W/O emulsion with high water content, which has significant effect on oil recovery performance. The most important parameter on the stability of W/O emulsion is interfacial properties. Thus, in order to investigate the effect of interfacial properties on the stability of W/O emulsion in a heavy oil reservoir at elevated temperatures, experiments have been conducted to generate various emulsions with variations in the temperature; stirring rate; contents of asphaltene, resin, and wax of the simulated heavy oil; and water salinity based on a target heavy oil reservoir in China. Then, the properties of the W/O emulsions include viscosity, interfacial viscosity (IFV), interfacial tension (IFT), and dehydration rate; the microscopic morphologies are measured as well. The experimental results show evidently stable W/O emulsion of heavy oil and water generated in thermal processes due to the stable, thick, and indistinct interface between heavy oil and water, where the active molecules of asphaltene and resin are accumulated. The interface connects the central large droplet and the surrounding small droplets tightly. The results also indicate the size of the central droplet, and the indistinct interface can be enlarged with increasing temperature and increasing stirring rate. Compared to resin, it is noted that the larger asphaltene molecules have stronger connection because of their stronger intermolecular force, larger IFV, and less IFT. At the same time, the stability of W/O emulsion will be strengthened with increasing temperature and stirring rate and gradually weakened with increasing salinity. In conclusion, the stability of water in heavy oil emulsion is mainly related to the large interfacial viscosity of the interface with much more heavy components such as asphaltene and resin compared to thin oil.

Optimisation of Steam Assisted Gravity Drainage [SAGD] for Improved Recovery from Unconsolidated Heavy Oil Reservoirs

2011 ◽  
Vol 367 ◽  
pp. 403-412 ◽  
Author(s):  
Babs Mufutau Oyeneyin ◽  
Amol Bali ◽  
Ebenezer Adom
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Industry ◽  
Steam Injection ◽  
Thermal Capacity ◽  
Thermal Recovery ◽  
Viscosity Reduction ◽  
Gravity Drainage ◽  
Steam Assisted Gravity Drainage ◽  
The Impact

Most of the heavy oil resources in the world are in sandstone reservoir rocks, the majority of which are unconsolidated sands which presents unique challenges for effective sand management. Because they are viscous and have less mobility, then appropriate recovery mechanisms that lower the viscosity to the point where it can readily flow into the wellbore and to the surface are required. There are many cold and thermal recovery methods assisted by gravity drainage being employed by the oil industry. These are customised for specific reservoir characteristics with associated sand production and management problems. Steam Assisted Gravity Drainage (SAGD) based on horizontal wells and gravity drainage, is becoming very popular in the heavy oil industry as a thermal viscosity reduction technique. SAGD has the potential to generate a heavy oil recovery factor of up to 65% but there are challenges to ‘’realising the limit’’. The process requires elaborate planning and is influenced by a combination of factors. This paper presents unique models being developed to address the issue of multiphase steam-condensed water-heavy oil modelling. It addresses the effects of transient issues such as the changing pore size distribution due to compaction on the bulk and shear viscosities of the non-Newtonian heavy oil and the impact on the reservoir productivity, thermal capacity of the heavy oil, toe-to-heel steam injection rate and quality for horizontal well applications. Specific case studies are presented to illustrate how the models can be used for detailed risk assessment for SAGD design and real-time process optimisation necessary to maximise production at minimum drawdown. Nomenclature

scholarly journals Optimizing the development strategy of combined steam flooding & cyclic steam stimulation for enhanced heavy oil recovery through reservoir proxy modeling

2021 ◽  
Author(s):  
Boni Swadesi ◽  
Suranto Ahmad Muraji ◽  
Aditya Kurniawan ◽  
Indah Widiyaningsih ◽  
Ratna Widyaningsih ◽  
...  
Keyword(s):  
Objective Function ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Model Development ◽  
Thermal Recovery ◽  
Oil Field ◽  
Heavy Oil Recovery ◽  
Proxy Model ◽  
Steam Flooding ◽  
Scenario Optimization

AbstractThermal injection methods are usually used for high viscosity oil. The results of previous studies showed that the combination of SF and SFF had the highest increase in oil recovery but still requires further study to determine the optimum strategy. This work is purposed to optimize the development scenario of a combined CSS-SF applied to a heavy oil field located in Sumatera, Indonesia. The recovery factor and NPV become the objective function, and several given and controlled parameters sensitivity toward the objective function are studied. A proxy model based on quadratic multivariate regression is developed to evaluate and get the desired objective function. The reservoir simulation of the thermal recovery process is done using CMG-STARS simulator. The overall workflow of scenario optimization is conducted using CMOST™ module. Optimum development scenario is obtained through maximization of the objective function. This work shows that the combination of proxy model development and optimization results in the best scenario of combined CSS-SF for heavy oil recovery.

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