How to Space SAGD Well Pairs for Optimal Performance

2021 ◽  
Author(s):  
Zeinab Zargar ◽  
S. M. Farouq Ali
Keyword(s):  
Oil Recovery ◽  
Moving Boundary ◽  
Late Phase ◽  
Oil Production ◽  
Steam Injection ◽  
Injection Rate ◽  
Analytical Relation ◽  
Oil Sand ◽  
Steam Quality ◽  
Well Spacing

Abstract Steam-Assisted Gravity Drainage (SAGD) is a remarkably successful process for the tar sands (oil sands). Two closely spaced parallel horizontal wells, injector above the producer, form a SAGD well pair. Steam is injected to provide heat to the reservoir oil and mobilize it. The low viscosity oil drains down to the producer under the gravity effect. Parallel well pairs 1000 m long are utilized in the process, spaced 100 m apart horizontally almost in all projects. In this work, an analytical model for the SAGD process is introduced by coupling heat and fluid flow and constitutive equations. A moving boundary, counter-current flow approach is used for the steam chamber rise and subsequent sideways expansion. The model is unique because it assumes the steam injection rate is constant and it permits modeling of the late phase of SAGD when adjacent well pair interference occurs. This leads to a reduction in heat loss to the overburden and a decline in oil production rate. This study examines the question of optimal well pair spacing in relation to the formation thickness and in-place oil. The effect of other variables on SAGD performance is investigated. A case study was performed using Christina Lake oil sand properties to show how the project performance varies under different senerios involving well pair spacing, reservoir thickness, steam injection rate, and steam quality. Results show that, in evaluating a SAGD pad performance, as the spacing is increased, the cumulative oil production decreases, with a simultanous increase in the cumulative steam-oil ratio at the same steam injection rate. However, a smaller portion of injected heat is lost to the overburden. It is concluded that a smaller well spacing requires more wells to deplete the whole pad area. On the other hand, a larger pattern well spacing affects oil recovery and heat consumption. Different conclusions are derived for the same pattern well spacing value using a single well pair model and pattern well pair configuration. Results also show that SAGD well pair spacing can be increased with an increase in formation thickness. The computational procedure is simple and makes it possible to examine a series of options for well spacing for a given set of conditions. This study presents for the first time an analytical relation between SAGD pattern well pair spacing and oil recovery.

scholarly journals A steam rising model of steam-assisted gravity drainage production for heavy oil reservoirs

2019 ◽  
Vol 38 (4) ◽  
pp. 801-818
Author(s):  
Ren-Shi Nie ◽  
Yi-Min Wang ◽  
Yi-Li Kang ◽  
Yong-Lu Jia
Keyword(s):  
Production Rate ◽  
Horizontal Well ◽  
Oil Production ◽  
Steam Injection ◽  
Injection Rate ◽  
Gravity Drainage ◽  
Model Parameters ◽  
Steam Quality ◽  
Steam Chamber ◽  
Steam Assisted Gravity Drainage

The steam chamber rising process is an essential feature of steam-assisted gravity drainage. The development of a steam chamber and its production capabilities have been the focus of various studies. In this paper, a new analytical model is proposed that mimics the steam chamber development and predicts the oil production rate during the steam chamber rising stage. The steam chamber was assumed to have a circular geometry relative to a plane. The model includes determining the relation between the steam chamber development and the production capability. The daily oil production, steam oil ratio, and rising height of the steam chamber curves influenced by different model parameters were drawn. In addition, the curve sensitivities to different model parameters were thoroughly considered. The findings are as follows: The daily oil production increases with the steam injection rate, the steam quality, and the degree of utilization of a horizontal well. In addition, the steam oil ratio decreases with the steam quality and the degree of utilization of a horizontal well. Finally, the rising height of the steam chamber increases with the steam injection rate and steam quality, but decreases with the horizontal well length. The steam chamber rising rate, the location of the steam chamber interface, the rising time, and the daily oil production at a certain steam injection rate were also predicted. An example application showed that the proposed model is able to predict the oil production rate and describe the steam chamber development during the steam chamber rising stage.

Effect of Confinement and Well Interference on SAGD Performance: An Analytical Assessment

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1595-1612
Author(s):  
Zeinab Zargar ◽  
S. M. Farouq Ali
Keyword(s):  
Heat Loss ◽  
Moving Boundary ◽  
Steam Injection ◽  
Injection Rate ◽  
Unsteady Temperature ◽  
Steam Chamber ◽  
Heat Loss Rate ◽  
Well Spacing ◽  
Interface Length ◽  
First Time

Summary In this paper, we introduce, for the first time, an analytical approach for evaluating the effect of confinement and well interference on the SAGD process and achieving a better understanding of the situation. In the well-confinement stage of SAGD, there is adjacent-chamber interference, the effective head of drainage decreases, and the heat-loss rate decreases or, in a conservative design, remains constant. Our objectives were to predict the oil-production rate, steam-injection rate, thermal efficiency, steam-chamber velocity, unsteady temperature profile, heat distribution, and the cumulative steam/oil ratio (CSOR). In this approach, heat transfer was coupled with fluid flow. The governing equations were Darcy's law, volumetric balance, and heat conduction—constitutive equations indicating the temperature dependence of some physical properties. Our model was developed on the basis of a moving-boundary problem. The predicted oil rate remained constant during the sideways-expansion phase, while the steam-injection rate had to be constantly increased. After a determined confinement time, the oil rate started to decline with time because the decreasing steam-chamber interface length was offset by a decreasing head. The unsteady temperature profiles from the model showed that lower temperatures were predicted ahead of the interface owing to the confinement effect. Also, the model showed that, for a small lateral well spacing, confinement occurred earlier and heat loss started decreasing sooner, resulting in a lower CSOR than for a large spacing. It was shown that, even though the oil rate declined faster in a confined model rather than in an unconfined model, the reservoir depleted faster, just like the angle between the steam-chamber interface and the horizon. The results were validated using experimental data reported in the literature.

scholarly journals Optimization of Cyclic Steam Stimulation Process Using Response Surface Methodology

2021 ◽  
Vol 2 (1) ◽  
pp. 26
Author(s):  
Suranto A.M. ◽  
Eko Widi Pramudiohadi ◽  
Anisa Novia Risky
Keyword(s):  
Response Surface Methodology ◽  
Response Surface ◽  
Heavy Oil ◽  
Steam Injection ◽  
High Viscosity ◽  
Injection Rate ◽  
Operating Conditions ◽  
Steam Quality ◽  
Cyclic Steam Stimulation ◽  
Steam Stimulation

Heavy oil has characteristics such as API gravity 10-20 and high viscosity (100-10,000 cp) at reservoir temperature. Several methods have been successfully applied to produce these reserves, such as cyclic steam stimulation (CSS). Cyclic steam stimulation is a thermal injection method that aims to heat the oil around production wells. This paper presents the investigation regarding CSS application in heavy oil using Response Surface Methodology. Several scenarios were done by varying the operating conditions to obtain the most realistic results and also evaluating the factors that most influence the success of CSS process. Optimization is performed to find the maximum recovery factor (RF) value and minimum steam oil cumulative ratio (CSOR). The operating parameters used are CSS cycle, steam injection rate, and steam quality. Then statistical modeling is carried out to test the most important parameters affecting RF and CSOR for 10 years. The simulation results show that the CSS cycle, steam injection rate, and steam quality affect the RF and CSOR. The maximum RF results with the minimum CSOR were obtained at 39 cycles, an injection rate of 300 bbl/day, and a steam quality of 0.9 with an RF and CSOR value is 24.102% and 3.5129 respectively.

Field Realization of Adaptive Reservoir Simulation for Steam Injection Forecasting

2021 ◽  
Author(s):  
Stanislav Ursegov ◽  
Evgenii Taraskin ◽  
Armen Zakharian
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Steam Injection ◽  
Carbonate Reservoirs ◽  
Base Case ◽  
Simple Liquid ◽  
Limited Information ◽  
Viscous Oil ◽  
Production Wells ◽  
Liquid Displacement

Abstract Globally, steam injection for heavy and high-viscous oil recovery is increasing, including carbonate reservoirs. Lack of full understanding such reservoir heating and limited information about production and injection rates of individual wells require to forecast steam injection not only deterministic and simple liquid displacement characteristic modeling types, but also the data-driven one, which covers the adaptive modeling. The implementation and validation of the adaptive system is presented in this paper by one of the world's largest carbonate reservoirs with heavy and high-viscous oil of the Usinsk field. Steam injection forecasting in such reservoirs is complicated by the unstable well interactions and relatively low additional oil production. In the adaptive geological model, vertical dimensions of cells are similar to gross thicknesses of stratigraphic layers. Geological parameters of cells with drilled wells do not necessarily match actual parameters of those wells since the cells include information of neighboring wells. During the adaptive hydrodynamic modeling, a reservoir pressure is reproduced by cumulative production and injection allocation among the 3D grid cells. Steam injection forecasting is firstly based on the liquid displacement characteristics, which are later modified considering well interactions. To estimate actual oil production of steamflooding using the reservoir adaptive geological and hydrodynamic models, dimensionless interaction coefficients of injection and production wells were first calculated. Then, fuzzy logic functions were created to evaluate the base oil production of reacting wells. For most of those wells, actual oil production was 25 – 30 % higher than the base case. Oil production of steamflooding for the next three-year period was carried out by modeling two options of the reservoir further development - with and without steam injection. Generally, forecasted oil production of the option with steam injection was about 5 % higher. The forecasting effectiveness of cyclic steam stimulations of production wells was done using the cross-section method, when the test sample was divided into two groups - the best and the worst, for which the average forecasted oil rates after the stimulations were respectively higher or lower than the average actual oil rate after the stimulations for the entire sample. The difference between the average actual oil rates after the stimulations of the best and the worst groups was 32 %, i.e. this is in how much the actual oil production could have increased if only the best group of the sample had been treated.

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.

A Study on Influence Factor of Steam Flooding Development Effect in Heavy Oil Reservoir

2013 ◽  
Vol 316-317 ◽  
pp. 872-877 ◽  
Author(s):  
Yu Chuan Cai ◽  
Yong Jian Liu ◽  
Xiang Fang Li ◽  
Jie Fan ◽  
Jian Yang ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Influence Factor ◽  
Steam Injection ◽  
Injection Rate ◽  
Steam Quality ◽  
Well Completion ◽  
Steam Flooding ◽  
Numerical Simulation Methods ◽  
The Impact ◽  
Quality Production

Steam flooding is an important method to improve the recovery factor heavy oil. Produce energy would consume a certain amount of crude oil in steam flooding; as a result, the evaluation of development effect of steam flooding should consider not only the degree of reserve recovery but also the heat utilization. In this paper, through the analysis of the mechanism of steam flooding, using reservoir engineering and numerical simulation methods, research the deposition, strata dip, steam injection rate, steam quality, production injection ratio and well completion method on the impact of steam flooding development effect in heavy oil.

scholarly journals Optimization Study of Integrated Scenarios on Cyclic Steam Stimulation (CSS) Using CMG STARS Simulator

2020 ◽  
Vol 1 (1) ◽  
pp. 8
Author(s):  
Boni Swadesi ◽  
Suranto Suranto ◽  
Indah Widiyaningsih ◽  
Matrida Jani
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
Steam Quality ◽  
Recovery Method ◽  
Final Project ◽  
Optimum Parameters ◽  
Cyclic Steam Stimulation ◽  
Optimization Study ◽  
The World ◽  
The Difference

Reservoirs in the world contain various types of oil, the difference of these oil types can be seen in the viscosity value and also the value of the API degree. Reservoirs in the U-field contain heavy oil that cannot be produced conventionally so we need the EOR (Enhanced Oil Recovery) method. CSS is a method that uses high-temperature hot steam aimed at reducing the viscosity of the oil so that oil can be produced. In this final project, a simulation is conducted to study the effect of various parameters such as steam quality, injection rate, and cyclic period on CSS and also determine the best scenario for U-field. The simulation begins by determining the best steam quality value, then doing sensitivity to the expected injection rate, followed by sensitivity to the cyclic period. The best scenario results are the integration of optimum parameters, namely steam quality 0.8, the injection rate of 550 BPD, and cyclic period of 20 days injection, 4 days soaking, and 60 days of production produce RF of 35.02%.

Effect of Flue Gas on Steam Chamber Expansion in Steamflooding

SPE Journal ◽  
2021 ◽  
pp. 1-11
Author(s):  
Teng Lu ◽  
Zhengxiao Xu ◽  
Xiaochun Ban ◽  
Dongliang Peng ◽  
Zhaomin Li
Keyword(s):  
Heat Exchange ◽  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Steam Injection ◽  
Injection Rate ◽  
Displacement Efficiency ◽  
Steam Condensation ◽  
Steam Chamber ◽  
Swept Volume

Summary The expansion of the steam chamber is very important for the recovery performance of steamflooding. In this paper, we discuss 1D and 2D sandpack experiments to performed analyze the effect of flue gas on steam chamber expansion and displacement efficiency in steamflooding. In addition, we examine the effect of flue gas acting on the steam condensation characteristics. The results show that within a certain range of injection rate, flue gas can significantly enlarge the swept volume and oil displacement efficiency of steam. However, when the flue gas injection rate is excessively high (the ratio of gas injection rate to steam injection rate exceeds 4), gas channels may form, resulting in a decline of oil recovery from steamflooding. The results of the 2D visualization experiments reveal that the swept volume of the steam chamber during steamflooding was small, and the remaining oil saturation in the reservoir was high, so the recovery was only 28%. The swept volume of the steam chamber for flue-gas-assisted steamflooding was obviously larger than that of steamflooding, and the recovery of flue-gas-assisted steamflooding in 2D experiments could reach 40.35%. The results of the steam condensation experiment indicate that flue gas could reduce the growth and coalescence rates of steam-condensed droplets on the cooling wall and increase the shedding period of the droplets. Macroscopically, flue gas could reduce the heat exchange rate between the steam and the reservoir and inhibit the rapid condensation and heat exchange of the steam near the injection well. As a result, flue gas could expand the steam chamber into the reservoir for heating and displacing oil.

A Comprehensive Wellbore Stream/Water Flow Model for Steam Injection and Geothermal Applications

1981 ◽  
Vol 21 (05) ◽  
pp. 527-534 ◽  
Author(s):  
S.M. Farouq Ali
Keyword(s):  
Flow Regime ◽  
Oil Recovery ◽  
Two Phase Flow ◽  
Injection Pressure ◽  
Steam Injection ◽  
Steam Pressure ◽  
Injection Rate ◽  
Phase Flow ◽  
Two Phase ◽  
Well Completion

Abstract A comprehensive mathematical model was developed to simulate the downward or upward flow of a steam/water mixture in a well. Comparisons of model predictions with actual field data for both steam injection for oil recovery and geothermal production showed the validity of the model.The proposed model is based on mass and momentum balances in the wellbore and on heat balance in the wellbore and the surrounding media. Unlike the previous models, the pressure calculation accounts for slip and the prevailing flow regime, based on noted correlations. Furthermore, heat loss to the surrounding formations is treated rigorously. The overall heat transfer coefficient involved permits the consideration of a variety of well completions.The model was employed for a series of tests to evaluate the effects of the injection pressure, injection rate, time, and well completion on the downhole steam pressure and quality. It was found that the slip concept and the flow regime are essential elements in wellbore steam/water flow calculations. Pressure drop was found to increase with a decrease in the injection pressure, as also with more obvious parameters. An increase in the injection pressure or tubing size and/or a decrease in the injection rate led to a decrease in steam quality at a given depth. Introduction Most steam injection operations for heavy oil recovery involve injection of wet steam down the tubing and occasionally down the casing/tubing annulus. Computations of reservoir heating by the injected steam require a knowledge of steam pressure and quality at the formation face. At the same time, it is important to know the heat loss to the surroundings during flow in the wellbore, as well as the casing temperature, for an appropriate well completion. Although several investigators have presented wellbore models for steam injection, none considered the flow regime concept in a unified approach. Furthermore, all models employed only approximate solutions of the one-dimensional radial heat conduction equation to investigate the heat loss.Vertical two-phase flow of water and steam occurs in geothermal wells. Among the geothermal reservoirs, only a few areas are classified as vapor-dominated systems, producing dry to superheated steam. All others are hot-water systems and generally produce a mixture of water and steam at the surface. Here, again, it is necessary to consider two phase flow in the wellbore, coupled with heat transfer, to predict steam pressure and quality at the surface. This problem was considered in detail by Gould.The main purpose of this work was to develop an integrated and comprehensive wellbore model to simulate vertical, nonisothermal, two-phase flow phenomena. The model is a combination of the previous model of Pacheco and Farouq Ali and the pressure/flow-regime correlations of Gould et al., Chierici et al., and Duns and Ros, as well as a number of refinements such as the rigorous treatment of heat flow, geothermal gradient, etc. Mathematical Model The system to be modeled consists of three parts:the fluid flow conduit (tubing or annulus),tubing/casing annulus, casing wall, and cement,the formation encircling the cement. Within the conduit, steady, homogeneous, one-dimensional, two-phase flow is assumed. This is described mathematically by combining a two-phase mass balance with a momentum balance and is as follows (the vertical coordinate z is taken positive in the downward direction). SPEJ P. 527^

Optimization of Superheated Steam Huff and Puff Wells Sequence in Heavy Oil Reservoir

2013 ◽  
Vol 295-298 ◽  
pp. 3154-3157
Author(s):  
An Zhu Xu ◽  
Zi Fei Fan ◽  
Ling He ◽  
Xia Xue ◽  
Bing Bo
Keyword(s):  
Superheated Steam ◽  
High Reliability ◽  
Oil Production ◽  
Steam Injection ◽  
Injection Rate ◽  
Practical Application ◽  
Good Correspondence ◽  
Functional Correlation ◽  
Proportional Relationship ◽  
Water Cut

Production of superheated steam huff and puff wells is affected by reservoir geological characteristics (effective thickness, net gross ratio), the state of development (recovery degree, integrated water-cut) and steam injection parameters (intensity of steam injection, steam injection rate, temperature and degree of superheat. etc.). On the basis of analysis of each factor, All factors set were established by a new specified model and the weight of each factor was determined by the functional correlation between the factors and production of each well. The integrated measured value of all factors was calculated by dimensionless value of each factor through integrated evaluation methods. Statistics results showed that the oil production of each well has perfect proportional relationship with the integrated measured value of all factors, there is the higher the integrated measured value of all factors, the higher the oil production of each well. According to this good correspondence, the integrated evaluation template was formed, and the total coincidence reached 96% with high reliability in the practical application in the Kenkiyak Oilfield, Kazakhstan.

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