Moreno Ortiz, Jaime Eduardo (Schlumberger) | Gossuin, Jean (Schlumberger) | Liu, Yunlong (Schlumberger) | Klemin, Denis (Schlumberger) | Gurpinar, Omer (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Challenges on EOR process upscaling have been discussed extensively in the industry and effects of diffusion, dispersion, heterogeneity, force balance and frontal velocity -among others, recognized and qualified, along with the importance of understanding the numerical model finite difference equations and modeling strategy. Augmenting the upscaling complexity is the often-limited understanding/data on the EOR displacement at different scales (from micro to full field), including the EOR agent/rock/fluid interactions that is often available at the early stages of the EOR process de-risking.
A common denominator for the EOR process characterization and upscaling (along with the discretization of the displacement) is the non-uniqueness nature of the problem. As the complexity of numerical representation of the EOR process increases (thus increasing data characterization requirements), so does the number of plausible solutions and challenges when dealing with an otherwise incomplete dataset. Digital rock has evolved as a strong alternative to complement laboratory corefloods, allowing for EOR agent optimization on a high-resolution digital representation of the pore structure, detailed digital fluid model of both reservoir fluids and EOR agents and physical rock-EOR agent-reservoir fluid interaction, thus providing several calibration points to ensure the finite-difference model calibration and upscaling preserve the process behavior.
This paper discusses the use of digital rock solutions on the EOR deployment, particularly on translating the results to numerical finite difference models, addressing the inherent laboratory measurement uncertainty and proposing a fit-for-purpose multi-scale upscaling strategy that addresses both effects of heterogeneity and EOR agent characterization during the upscale process.
This paper addresses the challenges of chemical flooding upscaling, particularly polymer by using a real-life polymer injection case where digital rock, corefloods and more importantly pilot results are available to test and validate our observations. Using a polymer coreflood and digital rock results as input, numerical finite difference simulation models were built and calibrated to effectively reproduce the displacement physics observed on both digital rock and corefloods, digital flood results were used to bridge the laboratory-to-numerical model step by providing effective upscaled polymer properties as well as intrinsic rock properties such as relative permeability and capillary pressures, which are then taken through a series of multi-scale finite difference models to identify, validate and quantify upscaling requirements, addressing polymer deformation through pore throats and effective simulation viscosity. Digital rock is used to rank and resolve ambiguity on the finite difference model calibration by providing an otherwise rare opportunity to visualize the displacement in the 3D space. The analysis shed a new light on fluid-fluid and fluid-rock interaction at pore scale and enabled us to improve on the finite difference model generation and polymer properties.
Polymer enhanced oil recovery (EOR) has been successful in onshore and offshore reservoirs, and is especially promising for heavy oil or heterogeneous reservoirs. Polymer retention, mainly due to adsorption, results in the removal of polymer from the solution, leading to the formation of a polymer-free bank. Thus, determining the retention is a key factor in evaluating the feasibility of polymer flooding. This work investigates a method to reduce polymer adsorption and improve the economics of polymer EOR. This is done through laboratory experiments and reservoir simulation. The experimental investigations consisted of five dynamic retention core floodings in fresh and non-fresh high permeability sandstones. Five concentrations of a HPAM-AMPS in high salinity brine were tested. Two types of experiments were performed: fresh-adsorption, and re-adsorption. Injection of the polymer solution in porous media that had never been in contact with polymer composed the fresh-adsorption experiments. Differently, the re-adsorption experiments were performed in media that had been flushed with the same polymer previously. The experiments indicated a type IV isotherm for fresh-adsorption, while the re-adsorption isotherm was of type I. For a polymer concentration of 1250ppm, the fresh-adsorption was 166.7μg/g while the cumulative re-adsorption was 64.8μg/g. Therefore, reduction of ∼61% may be achieved by pre-flushing the medium with a low polymer concentration solution before the injection of the mobility control bank. Other properties of the polymeric system were measured in the core floodings to serve as inputs to the reservoir simulation model. The field-scale simulation studies evaluated the economic impact of the injection of a low concentration polymer slug to reduce polymer loss during EOR, such as observed in the re-adsorption experiments. The production strategy optimization was composed of eight steps, and targeted net present value (NPV) maximization. The case studied was a heavy oil offshore sandstone field, based on a benchmark. The strategy to reduce polymer retention represented a 4% increase in the final NPV over the conventional polymer flooding. Additionally, risk curve analysis demonstrated the advantage of this reduced-retention strategy over waterflooding and conventional polymer flooding. This work shows experimental evidence that polymer overall retention may be reduced through injection of a low polymer concentration bank prior to the mobility control one. Additionally, through numerical simulation and economic analysis, it indicates that the reduced retention allows for an economic advantage in polymer EOR, which may improve the feasibility of polymer flooding projects.
ExxonMobil’s hot streak of offshore discoveries have sparked investor interest in the Guyana-Suriname basin. How did the company get there, and why do industry representatives feel optimistic about future deepwater prospects in the region? In the 30 years of operations on Suriname’s Tambaredjo field, the prime mechanism for lifting the 15.6 °API crude to surface has been that of progressing cavity pumps (PCPs).
Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share. Every attendee leaves energised with a full list of ideas and a support network of fellow leaders. Those sections and student chapters actively participating in this workshop have consistently been recognized with awards as the best in SPE. SPE Cares is a global volunteering drive aimed at promoting, supporting and participating in community services at the SPE section and student chapter’s level. On its official launch this year at ATCE Dubai, SPE Cares will conduct a “Give a Ghaf” Tree Planting Programme to help preserve Ghaf’s cultural and ecological heritage. The Ghaf tree is an indigenous species, specific to UAE, Oman and Saudi Arabia. It is a drought tolerant, evergreen tree that can survive a harsh desert environment. The initiative not only aims to hold events/activities at ATCE, but also recognise community service that SPE members are already conducting in their respective student chapters and professional sections. The KEY Club, open daily, is an exclusive lounge for key SPE members. The lounge is open to those with 25 years or more of continuous membership, Century Club members, current and former SPE Board officers and directors, Honorary and Distinguished Members, as well as this year’s SPE International Award Winners and Distinguished Lecturers. DSATS (SPE’s Drilling Systems Automation Technical Section) will hold a half-day symposium featuring keynote presentations on urban automation. This symposium will explore technologies being used in developing smart cities through the automation of their infrastructure, transportation systems, energy distribution, water systems, street lighting, refuse collection, etc. These efforts rely on many of the same tools needed for drilling systems automation yielding increased efficiencies, lower maintenance and reduced emissions. Their knowledge and experience can guide the path being travelled by the oilfield drilling industry.
Application of polymer flooding as a chemical Enhanced Oil Recovery (EOR) has increased over recent years. The main type of polymer used is partially hydrolyzed polyacrylamide (HPAM). This polymer still has some challenges especially with shear stability and injectivity that restrict its utility, particularly for low permeability reservoirs. Injectivity limits the possible gain by acceleration in oil production due to polymer flooding. Hence, good polymer injectivity is a requirement for the success of the operation. This paper aims to investigate the influence of formation permeability on polymer flow in porous media.
In this study, a combination of core flooding with rheological studies is presented to evaluate the influence of permeability on polymer in-situ rheology behavior. The in-situ flow of HPAM polymers has also been studied for different molecular weights. The effect of polymer preconditioning prior to injection was studied through exposing polymer solutions to different extent of mechanical degradation.
Results from this study reveal that the expected shear thinning behavior of HPAM that is observed in rheometer measurements is not observed in in-situ rheology in porous media. Instead, HPAM in porous media exhibits near-Newtonian behavior at low flow rates representative of velocities deep in the reservoir, while exhibiting shear thickening behavior at high flow rates representative of velocities near wellbore region. The pressure build-up associated with shear thickening behavior during polymer injection is significantly higher than pressure differential during water injection. The extent of shear thickening is high during the injection of high Mw polymer regardless of cores' permeability. In low permeable Berea cores, shear thickening and mechanical degradation occur at lower velocities although the degree of shear thickening is lower in Berea to that observed in high permeable Bentheimer cores. This is ascribed to high polymer retention in Berea cores that results in high residual resistance factor (RRF). Results show that preshearing polymer before injection into porous media optimizes its injectability and transportability through porous media. The effect of preshearing becomes favorable for the injection of high Mw polymers into low permeability formation.
This study discusses polymer in-situ rheology and injectivity, which is a key issue in the design of polymer flood projects. The results provide beneficial information on optimizing polymer injectivity, in particular, for low permeability porous media.
The paper discusses the feasibility study approach of polymer flooding enhanced oil recovery. This work is focused on understanding and quantifying key aspects of polymer flooding and design parameter optimization case. A synthetic reservoir simulation model was employed for the study.
The first stage is to identify and understand key factors that have most significant impact to polymer flooding response. There are eight parameters that are considered in the analysis, such as polymer concentration, polymer thermal degradation, polymer injection duration, and polymer-rock properties (adsorption, residual resistance factor, etc.). The impact of each parameter to oil recovery response was sensitized with its low, mid, and high values. The difference of high to low oil recovery output for all parameters was ranked to determine their significance levels. The top three parameters obtained from the sensitivity analysis are polymer injection duration, thermal degradation, and polymer concentration. Sensitivity cases of polymer injectivity and thermal degradation effects were covered in this work.
The second stage is to determine optimum design parameters of polymer flooding. The most significant parameters from the sensitivity analysis results were considered for further optimization. Three parameters that were selected for design optimization include polymer injection duration, polymer concentration, and well spacing. An optimization workflow with simplex algorithm is linked with a reservoir simulator to generate optimization cases by varying values of optimized parameters. The optimization iteration stops when the maximum value of the objective function, which is the net revenue, is reached. The optimization cycle was done for rock permeability of 500 md and 1000 md.
For a low rock permeability reservoir, the well spacing should be short and a lower polymer concentration is sufficient to provide a good response, in addition to avoiding potential injectivity problem. There should be minimum injectivity problem for reservoir with permeability above 1000 md. It is very important to apply polymer thermal degradation in the simulation model to avoid an optimistic performance prediction. The sensitivity analysis results provide a good understanding on the significance impact of parameters controlling polymer injection response and potential challenges. The optimization approach used in the study aids in investigating many optimization scenario within a short period of time.
Siv Marie Åsen, UiS, IRIS, and The National IOR Centre of Norway; Arne Stavland and Daniel Strand, IRIS; and Aksel Hiorth, UiS, IRIS, and The National IOR Centre of Norway Summary In this work, we examine the common understanding that mechanical degradation of polymers takes place at the rock surface or within the first few millimeters of the rock. The effect of core length on mechanical degradation of synthetic enhanced-oil-recovery (EOR) polymers was investigated. We constructed a novel experimental setup for studying mechanical degradation at different flow velocities as a function of distances traveled. The setup enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8, and 13 cm individually or combined. By recycling, we could also evaluate degradation at effective distances up to 20 m. Experiments were performed with two different polymers [high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) and low-MW acrylamide tertiary butyl sulfonic acid (ATBS)] in two different brines [0.5% NaCl and synthetic seawater (SSW)]. In the linear flow at high shear rates, we observed a decline in degradation rate with distance traveled. Even after 20 m, some degradation occurred. However, the observed degradation was associated with high pressure gradients of 100 bar/m, which at field scale is not realistic. It is possible that oxidative degradation played a significant role during our experiments, where the polymer was cycled many times through a core.
In the fluid flow study of polymer solutions through porous media in chemical enhanced oil recovery (ChemEOR) it is important to take into account very important properties such as the adsorption of polymer on mineral substrates, the residual resistance factor (Rk), the resistance factor (Rm), the wettability of the medium and cumulative recovery factor. For these reasons, this study has as main objective to evaluate rock-fluid behavior in presence of polymeric formulations by coreflood tests in porous media representative of extra-heavy crude reservoir conditions. To do this, an experimental methodology was proposed and a range of concentrations (800, 1500 and 2000 ppm) was established as the main variable of this study. Subsequently, relative permeability curves (Kr) on real sand cores were generated with an average absolute permeability of 7486.60 mD. Resulting in endpoints of the area of interest of: 29.0% and 65.6% of Swirr (Irreducible water saturation) and Sor (Residual oil saturation) respectively and a primary recovery factor of 36.4%. The amount of polymer adsorbed under dynamic regime was 19.1, 124.1 and 136.9 ug polymer/g rock. Following the same order, the values of additional oil recovery factor under polymer injection were 5.4, 10.2 and 15.2%, indicating a proportional increase with respect to injected concentration. However, there was no apparent correlation between the polymer concentration and residual resistance factor. Additionally, the initial wettability of the medium was preferential to water and this property increased with the injection of polymer formulations. Finally, using a methodology developed in this study, recycled polymer produced efficient results in ChemEOR processes generating an additional recovery factor of 2.38%. It also reduced the mobility of water in 98% (of that reported initially) and lastly its injection proportion per volume of crude produced was 3.522.
Polymer flooding and low salinity waterflooding are two different but potentially complementary Enhanced Oil Recovery (EOR) techniques. Polymer flooding improves fractional flow and sweep efficiency by improving the mobility ratio for the displacement. Low salinity waterflooding improves pore scale displacement efficiency by changing the wettability of the reservoir rocks toward more water-wet. Reduced salinity water is often used in polymer injection to reduce hydrolysis however the water salinity in this case is typically higher than that needed to obtain a true low salinity effect. This paper describes the outcomes of a systematic study into the potential benefits of combined polymer-low salinity waterflooding versus polymer-high salinity waterflooding, polymer-reduced salinity waterflooding and conventional waterflooding.
Numerical simulation, validated against analytical solutions, was used to evaluate the relative performance of these processes. The impacts of layering and reservoir heterogeneity were investigated using two-dimensional (2D) and three-dimensional (3D) reservoir models. Sensitivity studies of injected water salinity and the start time of injection were carried out in each of these models. Outcomes were compared against the recoveries and water cuts predicted using a one-dimensional (1D) analytic solution for the EOR processes to evaluate the impact of sweep versus displacement efficiency on incremental oil recovery and water cut.
Combined polymer-low salinity waterflooding shows an improvement in recovery and reduction in water cut compared with the other EOR processes in all cases. We show this is partly due to improving the fractional flow (increasing shock front saturation) but is also due to both the leading and trailing shock fronts in polymer-low salinity waterflooding being more stable than in the other EOR processes, reducing the possibility of viscous finger growth and thus increasing performance. The highest incremental oil recovery is observed when the injected water salinity in the combined polymer-low salinity waterflooding is reduced to below the low salinity threshold. It is clearly beneficial to reduce the water salinity to this low level rather than just to a salinity where hydrolysis is prevented. The injection of the combined EOR technique in tertiary mode, particularly at 75% water cut after performing high salinity waterflooding, exhibits an incremental oil recovery of between 15 and 42% and a reduction in water cut of between 11 and 48% at 1.0 pore volume injected (PVI).
This is the first systematic investigation into the performance of combined polymer-low salinity waterflooding compared with conventional waterflooding, low salinity waterflooding, and polymer flooding with reduced salinity water. It provides a clear insight into the benefits of combined EOR process justifying the need for field scale pilots and further laboratory studies.
Polymer Flooding has been shown to increase oil production. The reason for increasing oil production is acceleration along flow paths but also flow diversion from higher permeability to lower permeability areas. Tracer tests performed in the 8 TH Reservoir in Austria prior, during and after polymer flooding show that the flow system dramatically changed. The connected volumes from injector to producer as well as the flow heterogeneity were influenced and substantial incremental oil produced. A number of tracer tests were performed in the pilot area of a polymer flood at various times. In addition, pressure data and polymer rheology was analyzed.
The tracer results were used to calculate flow pattern, dynamic Lorentz coefficient and connected volumes. Pressure data were used in combination with geomechanical modelling to investigate the injection regime (matrix or fractures). The interpretation of the data was combined with the determination of incremental oil production based on simulation. The tracer tests reveal the dramatic changes in flow patterns, connected volume changes by more than a factor of three occurred and the Lorentz coefficient indicating the heterogeneity of flow changed by more than a factor of two. The injection regime changed from injection under matrix conditions prior to polymer flooding to injection under fracturing conditions during polymer injection and back to injection in matrix conditions during chase water injection.
The reason for the changes in injection conditions is the near-wellbore viscoelastic rheology of the High Molecular Weight Polymers which were used. The growth of fractures leads to additional alteration of flow paths. The design of polymer flooding needs to take into account that flow paths are not only changed due to the reduction in water relative permeability resulting from polymer adsorbing to the rock and the increased viscosity of the injected fluid but also owing to changes in injection regime. The changes in injection regime might lead to early breakthrough of chase water as it might not flow along the same paths as the polymer solution.