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.
Chemical EOR is a common process to increase recovery in oil reservoirs but these techniques are limited today in the case of high temperature and hard brines, mainly due to high adsorption issues and thermal stability of the chemicals. Specific formulations of surfactant and/or surfactant-polymer have to be designed and injection strategy has to be adapted for these challenging cases.
In this paper we first investigate the evolution of surfactant phase behavior in high temperatures and high hardness conditions and the way surfactant formulations can be adapted to these conditions. Specific chemicals are required to withstand challenging environment, specifically high temperatures. Adapted lab protocols are also required including essentially anaerobic conditions. We demonstrate how properly selected chemicals can be successfully blended and adapted injection strategies designed in these conditions.
We then present at the lab scale the effect of temperature and brine composition on surfactant adsorption through oil recovery coreflood experiments. In addition, we show the way adsorption is reduced in the case of hard brines,by the use of a salinity gradient. In these cases, the optimization of the injection strategy can help reduce the surfactant loss. High oil recoveries together with moderate surfactant adsorption can then be achieved opening new opportunities for development of chemical EOR.
1. Background information
Surfactant-Polymer (SP) and Alkaline-Surfactant-Polymer (ASP) have been acknowledged for decades to be among the most promising techniques to enhance oil production and reserves in mature oil fields. These processes consist in the injection into a formation of chemical slugs composed of surfactants, polymer and in some cases alkali [1; 2].
Surfactants are used to decrease interfacial tension (IFT) leading to an additional mobilization of oil initially trapped by capillary forces in the rock matrix . Polymers are used in order to improve mobility control and sweeping efficiency [1; 2]. The addition of alkali leads to a decrease of surfactant adsorption onto reservoir rock, specifically in presence of clays. Additionally, for reactive oils, alkali leads to the in-situ generation of soaps induced by the saponification of acidic crude oil components  improving overall process performances.
Most published successful studies so far focus on relatively favourable reservoir conditions. Under more challenging conditions, performance of ASP/SP flooding can drastically decrease . Among specific hurdles, high salinity/hardness and/or high temperature make ASP/SP processes challenging, both at laboratory and field scale.
Oukhemanou, Fanny (SOLVAY) | Courtaud, Tiphaine (SOLVAY) | Morvan, Mikel (SOLVAY) | Moreau, Patrick (SOLVAY) | Mougin, Pascal (IFP Energies Nouvelles) | FÃ©jean, Christophe (IFP Energies Nouvelles) | Pedel, Nicolas (IFP Energies Nouvelles) | Bazin, Brigitte (IFP Energies Nouvelles) | Tabary, Rene (IFP Energies Nouvelles)
An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria.
To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and high-pressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment.
We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil.
First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stock-tank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through illustrative case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.
Low permeability reservoirs contain a significant and growing portion of the world oil reserves, but their exploitation is often associated with poor recovery even after waterflood. Miscible or immiscible gas injection is usually the first choice in terms of EOR methods but it is not always feasible for instance due to lack of adequate supply. In such cases chemical EOR is often considered.
In this paper we propose to examine the specific challenges of chemical EOR in low permeability reservoirs reviewing the well documented chemical EOR field operations that were implemented in reservoirs ranging from conventional low permeability (around 100 mD) to so-called tight reservoirs (few mD). Shale plays where permeability is in the µD range and which only produce when simulated by hydraulic fractures are not considered in our investigation.
We show that what works at the lab scale in low permeability plugs cannot be automatically transposed to the field scale. In particular, low permeability can lead to injectivity issues and uncontrolled fracturing due to near wellbore plugging or simply to the high pressures required to propagate the injected chemical over large distances. Another challenging aspect of chemical EOR in low permeability reservoirs is the high chemical adsorption due to important surface to volume ratio and specific mineralogy, as in the case of carbonates (fractured or not). Success and failures of chemical EOR pilots in such challenging reservoirs, including innovative approaches such as wettability alteration, are reviewed.
Overall, this review will provide the reader with an updated view of past and on-going developments in chemical EOR applied to low permeability reservoirs. It should help operators determine whether a given low permeability reservoir is eligible to such processes or not.
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.
Dupas, Adeline (IFP Energies nouvelles) | Henaut, Isabelle (IFP Energies nouvelles) | Rousseau, David (IFP Energies nouvelles) | Poulain, Philippe (IFP Energies nouvelles) | Tabary, Rene (IFP Energies nouvelles) | Argillier, Jean- Francois (IFP Energies nouvelles) | Aubry, Thierry (Universite de Bretagne Occidentale)
Field data from polymer flooding operations sometimes indicate a better-than-expected polymer injectivity below fracturing pressure. Current interpretations for this unexpected phenomenon are based either on geomechanical considerations (for unconsolidated sand formations) or on polymer mechanical degradation, potentially occurring in the injection facilities and the near wellbore area. In this paper, a new approach of polymer injectivity is suggested. It is based on the study of polymer mechanical degradation with respect to both shear and extensional viscosities.
In the first part of this work, we have investigated the onset of mechanical degradation by submitting semi-dilute solutions of high molecular weight partially hydrolyzed polyacrylamide (HPAM) to extensional laminar flow created by an API capillary system. We have then measured both shear and extensional viscosity of the native and the degraded HPAM solutions. We consider the onset of mechanical degradation to be reached when shear viscosity loss is equal to 10%. At low degradation rate, shear viscosity is unaffected while extensional viscosity decreases up to 30%, whereas, at higher degradation rates, shear viscosity drops by 10% (onset) while extensional viscosity is reduced up to 60%. This means that degraded HPAM with weakly affected shear viscosity can develop much less resistance to extensional flow.
In the second part, we have explored the influence of mechanical degradation on injectivity by determining resistance factors of native and degraded HPAM solutions. Solutions have been injected in reproducible unconsolidated sand packs. At low velocities, resistance factors were similar for both kinds of solutions, as expected from their comparable shear viscosities. However, at high velocities, namely where flow in porous media implies high extensional deformations in the vicinities of the pore throats, apparent rheo-thickening was much less marked for solutions degraded at high extensional rate.
These results allow understanding why polymers which do not seem to be mechanically degraded according to their shear viscosity can show a very good injectivity, thanks to the reduction of extensional resistance in porous media. They could also lead to establish guidelines for designing new polymer pre-treatment methods aimed at improving injectivity while retaining the mobility control ability of polymers.
Tabary, Rene (IFP Energies Nouvelles) | Douarche, Frederic (IFP Energies Nouvelles) | Bazin, Brigitte (IFP Energies Nouvelles) | Lemouzy, Pierre Maxime (Beicip-Franlab) | Moreau, Patrick (Rhodia) | Morvan, Mikel (Rhodia)
Bramberge reservoir is a low temperature (40°C), high permeability (~1 Darcy) sandstone reservoir located in Germany. Waterflooded during several decades, oil production has been declining for the past few years. These conditions make this reservoir a good candidate for surfactant-polymer flooding.
Despite favourable attributes, the use of production brine, which exhibits very high hardness, as a re-injection fluid makes this project challenging and unique.
In this paper, we illustrate how this specific hurdle can be managed using a new strategy specifically developed for hard brines.
We show that surfactant/polymer formulations can be optimized in Bramberge re-injection brine despite its hardness with adequate properties for SP flooding (ultra-low interfacial tension and good solubility). The high level of divalent ions, and especially calcium ions, makes alkalis irrelevant for this project. We demonstrate using coreflood experiments that conventional injection strategies, successfully applied in soft brines (salinity gradient, etc…), and brine management options fail in these specific conditions because of the high chemicals adsorption. This high adsorption is showed to be strongly related to divalent ions.
We finally propose a successful alternative based on a careful selection of adsorption inhibitors. Using these additives, high oil recovery (94 %OOIP) was obtained together with low anionic surfactant and polymer adsorption. The overall technical performance is in line with conventional alkali-surfactant-polymer strategy in soft brine making this project very attractive and promising.
The process is currently in an optimization phase for pilot and field scale simulations allowing technical and economical optimization.
After primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency - so that one can recover some of this remaining capillary-trapped or water-by-passed oil -, it is necessary to screen enhanced oil recovery (EOR) techniques and to apply processes such as surfactant flooding, either Surfactant (S), Surfactant Polymer (SP) or Alkaline Surfactant Polymer (ASP), when recommended.
This paper describes an advanced methodology to select EOR surfactant based processes with special emphasis on the design of a formulation by considering real brine compositions. Salinity is the major parameter for the design of an efficient surfactant process. Salinity is defined by running reservoir numerical simulations with SARIPCH, a black oil simulator for chemical tertiary recovery. Inputs are formation water salinity and composition of waterflood brine. Strong heterogeneity of flow properties and resisual oil zones as well as reservoir geometry, for example crossflow, are considered. Results help to define the effective salinity and the salinity window for the surfactant formulation design.
Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted in order to take into account the potential efficiency and the economics of the process. Core flood experiments are performed to validate performances of selected
chemical formulation(s). Conclusions are drawn on the key effect of salinity and on the necessity of adopting a methodology giving a first appraisal of the salinity that will be seen by the surfactant slug during its transport.
The associative properties of Hydrophobically Modified Water Soluble Polymers (HMWSP) are known to be attractive for IOR, both because of their enhanced thickening capability as compared to classical water soluble polymers (for mobility control) and of their marked adsorptions on surfaces (for well treatments). In previous works, we have studied HMWSP injectivity in the dilute regime and shown, in particular, that adsorption played a major role in controlling injectivity. In this paper, we report new experimental data on the injectivity of HMWSP solutions in the semi-dilute regime.
From membrane filtration tests at imposed flow rate, we have firstly observed the formation of a filter-cake made of HMWSP physical gel, which remained largely permeable to polymers. This "gel-filtration" entailed modifications of the solution's viscosimetric properties, which can be explained by a rearrangement of the intra- and inter-chain hydrophobic bonds in the solution. The second part of our work consisted in injectivity tests in model granular packs. We have performed comparative experiments in porous media with variable permeabilities but at the same shear rate in the pore throats. Results show that, above a critical pore throat radius, rpC, HMWSP injection lead to stable resistance factors, with values close to the solution's viscosity, and that, below rpC, gelation occurs during injection. Furthermore, resistance factors measured on the cores internal sections evidence for in-depth gel formation. These insights could represent a new step towards the tuning of HMWSP injection conditions to the application targeted: mobility control or profile/conformance control.
Gas production from gas wells or storage reservoirs is sometimes associated with solid particles eroded from the rock matrix. This phenomenon often called sand production can cause damages to the equipments, leading to choke the wells under their full capacity. Colloid release is often associated as a precursor of larger solid production and clay release can be a forecast of inter-granular cement erosion.
Injections of dilute polymer/microgel solutions form a small part of the techniques employed today to deal with sand production in gas and oil wells. Nevertheless they could be used more often as a remedy against starting sand production problems as shown through recent field applications.
The paper presents laboratory experiments carried out with model systems to reproduce particle generation and their transport in porous media. The approach consists in following the evolution of the colloidal particle detachment after ionic strength reduction and in defining the key parameters for release rate prediction. A different behaviour is highlighted at short and long time and the model, built to predict the colloid production evolution, is based on the introduction of two different time scales of the eroded rate.
The laboratory experiments demonstrate the great efficiency of polymer/microgel treatments. The proportion of fines produced decreases drastically when the surface coverage related to the adsorption rate increases. The use of the model to describe the effect of the chemical treatment helps to show that this one does not modify the mode of production of fines but significantly reduces the quantity of fines likely to be carried away from the pore surface.