Tristan Euzen will be an expert speaker at the Canadian Shale Production Exhibition and Conference held in Calgary on July 14-15, 2020. He will talk about Controls on liquids recovery in the Montney condensate and oil fairways of NEBC.

Link: https://canada.shale-production.com/

Tristan Euzen is a guest editor with John Bryer for a special issue of the Bulletin of American Petroleum Geology on “Carrier Beds as Reservoirs: Linking Conventional and Unconventional Resources”. This volume will gather latest research from well-recognized international experts of unconventional resources.

Tristan Euzen will be co-chairing a session on “Integrated Geochemistry of Oil-Prone and Gas-Prone Unconventional Resource Plays with Geology and Petrophysics” at the Unconventional Resources Technology Conference (URTeC) held on July 20-22 in Austin (Texas).

Expressing surprise that T&T had not taken advantage of the latest oil production technology despite the crisis in oil production, Canadian reservoir engineer Eric Delamaide is recommending that polymer flooding and foam flooding be used in Trinidad to extract oil.

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Eric Delamaide of IFP Canada has been selected to receive international recognition for his outstanding service in 2016 as a Technical Editor of SPE’s peer-reviewed scholarly journal under Reservoir Evaluation and Engineering and of the SPE Journal. These prestigious accolades are exclusively awarded to only 1% of SPE’s 110,000 members worldwide.

See full list of 2016 recipients

Eric Delamaide of IFP Canada has been selected to receive international recognition for his outstanding service in 2015 as a Technical Editor of SPE’s peer-reviewed scholarly journal under Reservoir Evaluation and Engineering. This prestigious accolade is exclusively awarded to only 1% of SPE’s 110,000 members worldwide.

Find out more about IFP Canada experts here: https://ifp-canada.com/about-us/management-team/

Nowadays steam injection is commonly used as a thermal EOR method. However this process is also associated with chemical reactions in the reservoirs, called aquathermolysis, which produce the highly toxic and corrosive acid gas H2S in the presence of sulfur-rich heavy oil.

The overall objective of this work is to understand the aquathermolysis reactions in reservoirs undergoing steam injections and provide Oil companies with a numerical model for reservoir simulators that forecasts H2S production risk.

Heavy oil extraction is mostly based on thermal EOR processes. Warming up the reservoir reduces oil viscosity, makes it more mobile and in turn enhances heavy oil recovery. The most prominent thermal heavy oil EOR method relies on steam injection. This recovery process consumes high quantities of fresh water and energy to produce the steam, and heat loss due to reservoir heterogeneities and thief zones must be minimized. For that purpose, steam foams can be used to decrease steam mobility and improve its utilization by a better distribution in the reservoir. Selection of appropriate products for steam harsh temperature conditions poses several challenges regarding chemicals stability and foam durability. We have shown in previous papers that synergistic association of thermally stable surfactants can highly improve high temperature foaming performances. Here, we extend these results to specific surfactant formulations designed to provide enhanced bulk viscosity. These formulations are intended to compensate for the strong decrease of water viscosity with temperature. This is expected to enhance steam foams lifetime and in turn provide a better steam mobility control in application conditions.

Bulk foam half-life is highly dependent on experimental conditions, in particular on the initial state of the foam in terms of quality and bubble size. This is even truer for steam foams that are also highly sensitive to possible temperature gradients. An optimized experimental setup has been developed to evaluate high temperature foam half-life obtained with standard and enhanced viscosity formulations. We couple these measurements with rheology and mobility reduction evaluation in sandpack experiments.

Based on these various parameters, we try to extract correlations between bulk steam foam half-life, bulk viscosity and mobility reduction in porous media.

This paper describes the characteristics of newly developed enhanced viscosity surfactant formulations, and also provides data regarding impact of viscosity on high temperature foam stability and mobility reduction.

This document will highlight the challenges with produced water treatments that facility engineers and operators will have in preparing for a chemical EOR project. The methodology used will help identify common issues, and then emphasize procedures to mitigate the risk to the operations. The complete water cycle will be analyzed and topics will include chemical interactions of the EOR products and production chemistry as well as EOR chemicals preparation.

Chemical Enhanced Oil Recovery (EOR) has seen numerous applications worldwide onshore but very few offshore. The reasons for that are mostly related to the technical and logistical challenges that need to be overcome for the successful implementation of chemical EOR: transporting various chemicals to the platforms, the need for space for the mixing skids and storing chemicals on the platforms, the need to use sea water as the injection fluid among others. As primary and secondary recovery reach their technical and economical limits in offshore fields, the operators are faced with the dilemma of abandoning the field and the platforms or resorting to EOR to increase recovery and extend the life of the field. Non chemical EOR techniques face their own challenges such as the need for large gas supply for gas injection so chemical methods cannot be ruled out so easily. However new approaches need to be defined to make chemical EOR a realistic method for offshore reservoirs. A large part of these issues arise from the mindset which associates chemical EOR with Alkali-Surfactant-Polymer injection. The approach proposed is to use only surfactant in cases where polymer is not absolutely required and to eliminate alkali altogether. This will eliminate various obstacles such as deck space limitations and the need to soften the injection water. This approach opens new doors for chemical Enhanced Recovery offshore. Such an approach is possible thanks to the progress in surfactant formulation and the development of adsorption inhibitors which allow dealing with seawater as an injection fluid. The novelty is not the technology but the way the standard approach is discarded to the benefit of a simpler solution.

Oil production in presence of a bottom aquifer is one of the most challenging issues in reservoir engineering. In most cases water coning happens very quickly and the influx of water restricts oil production and limits recovery. The problem is even more difficult when the oil is heavy because the viscosity contrast is large. In some cases horizontal wells may be used to improve the situation but when reservoirs are thin and the oil is viscous even horizontal wells are of limited use. This paper presents the challenges and potential solutions for Enhanced Oil Recovery in heavy oil reservoirs with bottom aquifer.

Existing literature is reviewed for field cases of EOR experience with bottom aquifer for chemical as well as thermal processes (SAGD, steam injection as well as In Situ Combustion).

In the case of chemical EOR the chemicals may be lost to the aquifer; for thermal recovery the bottom water can act as a heat sink and affect and steam oil ratio. Some in-situ combustion projects have been successful in such settings but in every case the outcome is the same: the economics of the project can be affected.

The paper contains some previously unpublished data of polymer injection in a heavy oil pool with some limited bottom aquifer; for the most part it is a review of the existing literature which may prove useful to practicing engineers who are faced with the issue of developing heavy oil resources in the presence of bottom aquifer.

Taken from: Journal of Petroleum Technology – January 2015
Authors: Eric Delamaide (IFP Technologies (Canada) Inc.) \ Alain Zaitoun (Poweltec) \Gerard Renard (IFP Energies nouvelles) \ Rene Tabary (IFP Energies nouvelles)

Abstract

The Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production using vertical wells was poor because of the thin (less than 5m) reservoir formation and high oil viscosity (600 to over 40,000cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. Still, with primary recovery less than 10% and several billion barrels of oil in place, the prize for EOR is large.

Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake due to the high viscosity of the oil, until the idea came of combining it with horizontal wells. A first – unsuccessful – pilot was implemented in 1997 but the lessons drawn from that failure were learnt and a second pilot met with success in 2006. The response to polymer injection in this pilot was excellent, oil rate climbing from 43bopd to over 700bopd and remaining high for over 6 years now; the water-cut has generally remained below 60%.

This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the two polymer flood pilots as well as the extension of the flood to the rest of the field (currently in progress).

Polymer flooding has generally been applied in light or medium gravity oil and even today, standard industry screening criteria limit its use to viscosities up to 150cp only. Pelican Lake is the first successful application of polymer flooding in much higher viscosity oil (1,000-2,500cp) and as such, it opens a new avenue for the development of heavy oil resources that are not accessible to thermal methods.

 

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