Laboratory Study of Rock Softening and Means of Prevention During Steam or Hot Water Injection

Abstract This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water. INTRODUCTION The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water. DERIVATION OF BASIC EQUATIONS We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1 This can be written in the formEquation 2 This is sometimes referred to as the Lagrangian form of the displacement equation.

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SS - Gas Hydrate: Gas production from methane hydrate sediment layer by thermal stimulation with hot water injection

10.4043/20592-ms ◽

2010 ◽

Author(s):

Kyuro Sasaki ◽

Shinzi Ono ◽

Yuichi Sugai ◽

Norio Tenma ◽

Takao Ebinuma ◽

...

Keyword(s):

Gas Hydrate ◽

Methane Hydrate ◽

Water Injection ◽

Gas Production ◽

Hot Water ◽

Thermal Stimulation ◽

Sediment Layer

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Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2021.109644 ◽

2021 ◽

pp. 109644

Author(s):

Yanfang Gao ◽

Zhanli Ren ◽

Mian Chen ◽

Hailong Jiang ◽

Shuaiwei Ding

Keyword(s):

Water Injection ◽

Thermal Simulation ◽

Hot Water ◽

Oil Sand ◽

Vertical Well

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Software Tool for the Study, Analysis and Evaluation of Enhanced Oil Recovery Processes

10.2118/spe-169917-ms ◽

2014 ◽

Author(s):

C. L. Delgadillo-Aya ◽

M.L.. L. Trujillo-Portillo ◽

J.M.. M. Palma-Bustamante ◽

E.. Niz-Velasquez ◽

C. L. Rodríguez ◽

...

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Water Injection ◽

Software Tool ◽

Steam Injection ◽

Hot Water ◽

Assessment Process ◽

Analytical Models ◽

Financial Assessment ◽

Recovery Processes

Abstract Software tools are becoming an important ally in making decisions on the development or implementation of an enhanced oil recovery processes from the technical, financial or risk point of view. This work, can be manually developed in some cases, but becomes more efficient and precise with the help of these tools. In Ecopetrol was developed a tool to make technical and economic evaluation of enhanced oil recovery processes such as air injection, both cyclic and continuous steam injection, and steam assisted gravity drainage (SAGD) and hot water injection. This evaluation is performed using different types of analysis as binary screening, analogies, benchmarking, and prediction using analytical models and financial and risk analysis. All these evaluations are supported by a comprehensive review that has allowed initially find favorable conditions for different recovery methods evaluated, and get a probability of success based on this review. Subsequently, according to the method can be used different prediction methods, given an idea of the process behavior for a given period. Based on the prediction results, it is possible to feed the software to generate a financial assessment process, in line with cash flow previously developed that incorporates all the elements to be considered during the implementation of a project. This allows for greater support to the choice or not the application of a method. Finally the tool to evaluate the levels of risks that outlines the development of the project based on the existing internal methodology in the company, identifying the main and level of criticality and define actions for prevention, mitigation and risk elimination.

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Compositional simulation of hydrocarbon recovery from oil shale reservoirs with diverse initial saturations of fluid phases by various thermal processes

Energy Exploration & Exploitation ◽

10.1177/0144598716684307 ◽

2016 ◽

Vol 35 (2) ◽

pp. 172-193 ◽

Cited By ~ 7

Author(s):

Kyung Jae Lee ◽

George J Moridis ◽

Christine A Ehlig-Economides

Keyword(s):

Aqueous Phase ◽

Single Phase ◽

Water Injection ◽

Hot Water ◽

Electrical Heating ◽

Hydrocarbon Production ◽

Well Pattern ◽

Shale Reservoirs ◽

Fluid Phases

We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase.

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