Different factors are involved at each stage within the overall constraints of optimum reservoir penetration. Most directional wells are drilled from multiwell installations, platforms, or drillsites. Minimizing the cost or environmental footprint requires that wells be spaced as closely as possible. It has been found that spacing on the order of 2 m (6 ft) can be achieved. At the start of the well, the overriding constraint on the well path is the presence of other wells.
One of the main uncertainties when designing polymer floods is the polymer injectivity, an important parameter that can affect the economics of the process. Reservoir simulation can be used to forecast injectivity, but the process is not straightforward and can be affected by grid size and other factors. Analytical methods are also available for that purpose, but they are considered too simplistic to deal with realistic reservoir conditions. The aim of this paper is to show that this is not the case and that simple analytical tools can be accurate and of great help to predict or history match polymer injectivity.
The analytical method has been developed by Lake in his classical textbook on Enhanced Oil Recovery, but few applications are documented in the literature. This paper will review the method and corresponding equations before presenting several actual field cases of injectivity in polymer flood pilots or tests from several countries that have been matched analytically.
Although it has not been used very often, the method has been found to give very good results in most of the field cases tested in a variety of situations; these cases will be presented along with recommendations on how to apply the method and a discussion of the results. Sensitivities to the various parameters will also be presented. Once the equations are programmed in a spreadsheet, the matching process takes only a few minutes and it is easy to run various scenarios and sensitivities.
Polymer injectivity remains one of the less understood and less predictable aspects of polymer flood projects. This paper will encourage engineers who are planning such projects to use simple yet accurate analytical tools before embarking in more complex and time-consuming reservoir simulations.
AlSofi, Abdulkareem M. (Saudi Aramco) | Wang, Jinxun (Saudi Aramco) | AlBoqmi, Abdullah M. (Saudi Aramco) | AlOtaibi, Mohammed B. (Saudi Aramco) | Ayirala, Subhash C. (Saudi Aramco) | AlYousef, Ali A. (Saudi Aramco)
The synergy between various enhanced-oil-recovery (EOR) processes has always been raised as a potential optimization route for achieving a more-economic and more-effective EOR application. In this study, we investigate the possible synergy between polymer and smartwater flooding for viscous-oil recovery in carbonates. Although the potential for such synergy has been suggested and researched in the literature, we investigate this possibility in a more-realistic framework: part of the development of an EOR portfolio for a slightly viscous Arabian heavy-oil reservoir. In this work, we study the possible synergy between smartwater and polymer flooding by performing rheological, electrokinetic potential (ζ-potential), contact-angle, interfacial tension (IFT), and recovery experiments.
Rheological tests, as expected, demonstrated the possibility of achieving the same target viscosity at lower polymer concentrations. With smartwater, the polymer concentration required to achieve a target viscosity of 11 mPas was found to be one-third lower than that with normal high-salinity injection water. Electrokinetic-potential and contact-angle results demonstrated that polymer presence has negligible to slightly favorable effect on wettability alteration induced by smartwater. On synthetic calcite surfaces, polymer showed negligible effect, whereas on reservoir-rock surfaces, polymer resulted in further reduction in contact angles beyond that obtained with smartwater.
Coreflooding experiments conducted at reservoir conditions with finite smartwater/polymer slugs—besides yielding comparable performance to surfactant/polymer flooding—demonstrated the enhanced performance of smartwater/polymer compared with either of these individual processes. A combined smartwater/polymer process was able to recover substantial additional oil—6.5 to 9.9% original-oil-in-core (OOIC)—above that obtained with either of the two processes when applied independently. Ultimate recoveries from the application of smartwater/polymer (70% OOIC) were quite comparable to, and actually slightly higher than, that of surfactant/polymer (67% OOIC). However, in terms of the remaining oil in core (ROIC) after polymer flooding, both processes (smartwater/polymer and surfactant/polymer) exhibited quite similar incremental recoveries of 20.6 and 20.5% OOIC, respectively.
The results of this work clearly demonstrated the potential synergy between smartwater and polymer flooding—beyond that of the well-established polymer-viscosity enhancement—for a realistic scenario. The additive effect of smartwater was successfully shown to combine with polymer to increase oil recovery, in addition to lowering the polymer concentration. This favorable synergy will reduce chemical-consumption costs and improve recovery to enhance EOR-project economics.
For heavy oil recovery applications, mobility control is more important than interfacial tension (IFT) reduction and therefore, importance should be given to the recovery of remaining mobile oil by enhanced sweep efficiency. While the relative role of polymer's viscosity and elasticity on capillary-trapped residual light oil recovery has been studied extensively, their role on the sweeping the mobile viscous oil has not been explored. Injectivity is vital for heavy oil recovery applications and polymer selection criteria are done solely based on shear rheology. In this paper, the influence of viscous (shear) resistance and elastic (extensional) resistance of viscoelastic polymer on the mobile heavy oil recovery and injectivity is investigated through the combination of bulk shear/extensional rheology and single phase, and multiphase core flood experiments at typical reservoir flooding rate of 1 ft/day.
Two polymer solutions with different concentration and salinity are selected such that low molecular weight (Mw) polymer (HPAM 3130) provides higher shear resistance than high Mw polymer (HPAM 3630). Extensional characterization of these two polymer solutions performed using capillary breakup extensional rheometer revealed that HPAM 3630 provided higher extensional resistance than HPAM 3130. The results show that the behavior of polymers in extension and shear is completely different. Two multiphase and two single-phase experiments are conducted at low flux rate to investigate the role of extensional viscosity on mobile heavy oil recovery and high flux rates on injectivity. After 1 PV of polymer injections, higher concentration and lower Mw HPAM 3130 contributes to ~17% higher incremental recovery factor over lower concentration and higher Mw HPAM 3630. The core scale pressure drop generated by HPAM 3130 is more than twice the pressure drop generated by HPAM 3630. Under low flux rate conditions at the core scale, shear forces dominate and displacing fluid with higher shear viscosity contribute to better sweep. HPAM 3630 exhibits shear thickening phenomenon and possess the apparent viscosity of ~ 90 cP at the flux rate of ~90 ft/day. Whereas HPAM 3130 continued showing shear thinning and has the apparent viscosity of around ~70 cP at ~ 90 ft/day. This signifies the role of extension rheology on the injectivity at higher flux rates.
Results revealed that while extensional rheological role towards sweeping the mobile heavy oil recovery at low flux is lesser when compared to shear role, its negative role on the polymer injectivity is very significant. Polymer selection criteria for heavy oil recovery applications should incorporate extensional rheological parameters.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Fadli, Eman Hadad (Kuwait Oil Company) | Al-Shati, Fawziya Mohammad (Kuwait Oil Company) | Qubian, Ali (Kuwait Oil Company) | Li, Zhitao (Ultimate EOR Services LLC) | Trine, Eric (Ultimate EOR Services LLC) | Alizadeh, Amir H. (Ultimate EOR Services LLC) | Delshad, Mojdeh (Ultimate EOR Services LLC)
KOC's Umm Gudair/Abduliyah Tayarat reservoir has large oil reserves but is a challenging target due to low formation permeability and high oil viscosity. This study is focused on feasibility assessment of hybrid thermal and chemical methods incorporating both laboratory and simulation results.
A recent updated static geological model for West Kuwait fields was used as the basis to generate a full-field dynamic reservoir model with representative reservoir geometry, heterogeneity, and complexity. Carter-Tracy aquifers were added to model lateral and bottom aquifers. Laboratory data were incorporated to model physiochemical properties. Gridblocks were globally refined to gain better resolution for heavy oil and EOR simulations. The full-field reservoir model was used to systematically study the potentials of hybrid thermal and chemical EOR methods in comparison with conventional waterflood and chemical EOR methods.
Our studies show that in order to produce oil at an economic rate, long horizontal wells on the order of kilometers or horizontal wells stimulated by acidizing, multistage fracturing, or multiple laterals should be deployed. Vertical wells yield low oil production rates due to limited contact areas and severe water coning. Aquifer water intrusion from the west side of reservoir overshadows the bottom aquifer and the edge east side aquifer due to the heterogeneity of reservoir permeability. A sector model was extracted from the full-field Eclipse model and further refined to avoid grid effects in simulation of EOR processes. Simulation results show that hybrid thermal and chemical methods (hot polymer/Surfactant-Polymer/Alkaline-Surfactant-Polymer flood) can effectively increase oil recovery from high-permeability, high-saturation sweet spots of the Tayarat reservoir. With the help of horizontal wells, hot polymer flood shows the best performance after 20 years of oil production and yields more than 30% of incremental oil recovery. Hot Surfactant-Polymer flood shows slightly lower cumulative oil recovery but sustained oil production rates and less production decline in the late stage of the flood. Phase 2 coreflood experiments confirmed that hot polymer flood can effectively enhance oil recovery.
In summary, this research study identified sweet spots for oil recovery and EOR applications in the challenging Tayarat reservoir and demonstrated the potential of producing significant amount of oil with appropriate IOR (e.g., extended reach horizontal wells, multistage fractures, stimulation, etc.) and EOR (e.g., hybrid thermal and chemical methods) techniques.
Application of polymer flooding technique under extreme reservoir conditions (~120°C and 167000 ppm) is still of great concern. In high temperature and high salinity (HTHS) reservoirs, the commonly used polymers for improved oil recovery purposes are ineffective due to chemical degradation and poor injectivity. Therefore, the aim of this paper is to screen partially hydrolyzed polyacrylamide (HPAM) base polymers in order to find suitable polymer for a targeted HTHS carbonate reservoirs.
Polymer screening study was carried out on three new NVP-HPAM base polymers to identify a potential candidate which can withstand harsh reservoir conditions. Initially, a comprehensive rheological study was conducted at various polymer concentrations (1000-4000 ppm) and brine salinities to investigate the effectiveness of the polymers. Then, thermal stability test was conducted at anaerobic condition and 120°C for three months. Finally, injectivity test was conducted with the best polymer and in the absence of oil at 120°C and formation salinity (167000 ppm). The experiment was done by sequential injection of 3 polymer concentrations (3000, 1500, and 750 ppm). Parameters such as resistance factor, residual resistance factor, insitu rheology, and apparent shear rates were investigated during the experiment.
Results from the rheometric studies showed that all three polymers have acceptable initial viscosifying properties at ambient temperature and shear thinning behaviors within shear rate range of 1-100 s-1. The results also indicated that polymer viscosities dropped with increase in temperature and salinity. However, they still showed good resistance up to 167000 ppm and 120°C. The thermal stability test for the potential polymer showed better stability and retained more than 90% of its initial viscosity after the ageing period. Whilst injecting at 3000 ppm, the resistance factor (RF) was between 20-10 (at different flowrates). During 1500 ppm and 750 ppm, the RF were in the range of 14-6.5 and 5-2.7 respectively. At low flowrates (0.05-1.0 cc/min) of polymer injection, shear thinning behavior was observed. Whereas, shear thickening behavior at high flowrates was observed at all concentrations. Finally, the residual resistance factor (RRF) recorded for the injectivity experiment was found to be 6.17.
The potential polymer showed promising results for its application in heterogeneous carbonate reservoir with higher temperature and salinity of 120°C and 167,000 ppm respectively. The study also leads to better understanding of polymer flow behavior in high temperature high salinity carbonate reservoirs.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
Very few papers describe waterflood projects in heavy oil reservoirs, and even less that involve the use of horizontal injectors and producers. A few years ago, Beliveau presented a review of waterfloods in viscous oil in several pools mostly in Canada and demonstrated that excellent results can be obtained in most cases, but he mostly focused on pools with vertical wells. The purpose of this paper is to present results of several heavy oil waterfloods in Canada that use horizontal producers and injectors.
The production performances of eight heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. The overall performances of each flood will be discussed and compared to other heavy oil pools where waterflood is implemented with vertical wells. In addition, more detailed analyses will be performed in some patterns to better evaluate the impact of bottom water, well length, spacing and other factors on the flood performances.
As could be expected, water breakthrough is generally fast, within a few months from the beginning of injection; but more surprisingly, Water Oil Ratio can often remain stable for long periods of time. Ultimate recovery is expected to vary from a few percents OOIP to over 20%OOIP. Similarly, to waterfloods with vertical wells, a large portion of the reserves can be recovered while producing at high Water Oil Ratio.
This paper will present results of several waterfloods in heavy oil reservoirs in Canada which use horizontal wells. There are very few such field cases in the literature thus the information provided will be of interest to engineers who are considering waterflood as a follow-up to primary production in heavy oil reservoirs developed with horizontal wells.
Loubens, R. de (Total S.A.) | Vaillant, G. (Total S.A.) | Regaieg, M. (Geoscience Research Centre, Total E&P UK) | Yang, J. (Geoscience Research Centre, Total E&P UK) | Moncorgé, A. (Geoscience Research Centre, Total E&P UK) | Fabbri, C. (Total E&P Nigeria) | Darche, G. (Total S.A.)
The saturation distribution after unstable water flooding into highly viscous oil may have a decisive impact on the efficiency of tertiary polymer flooding, in particular due to hysteresis effects associated with oil banking. In this work, we model water flood and tertiary polymer flood experiments performed on Bentheimer sandstone slabs with heavy oils of about 2000 cP and 7000 cP, and compare the numerical results with experimental production, pressure and X-ray data.
The unstable water floods are initially simulated in 2D with our parallel in-house research reservoir simulator using a high-resolution discretization. In agreement with existing literature, we find that Darcy-type simulations based on steady-state relative permeabilities - inferred here from a 3D quasistatic pore network model (PNM) - cannot predict the measured water flood data. Even qualitatively, the viscous fingering patterns are not reproduced. An adaptive dynamic pore network model is then applied on a 2D pore network constructed from the statistics of the 3D network. If the fingering patterns simulated with this 2D PNM are qualitatively in good agreement with the experimental data, a quantitative match cannot be obtained due to the limitations of 2D modeling. Although 3D dynamic PNM at the slab scale would currently lead to prohibitively high computational cost, it has the potential to address the deficiencies of continuum models at highly unfavorable viscosity ratio.
For the tertiary polymer floods characterized by a much more favorable mobility ratio, Darcy-type modeling is applied and history matching is conducted from the end of the water floods. We find that unless hysteresis due to oil banking is accounted for in the relative permeability model, it is not possible to reconcile the experimental data sets. This hysteresis phenomenon, associated with oil invasion into previously established water channels, explains the rapid propagation of the oil bank. For the considered experiments, a simultaneous history match of good quality is obtained with the production and pressure data, and the simulated 2D saturation maps are in reasonable agreement with X-ray data.
This paper addresses the challenges in modeling highly unstable water flooding, using both a conventional Darcy-type simulator and adaptive dynamic PNM, by confronting the simulated results with experimental data including saturation maps. It also highlights the important role of relative permeability hysteresis in the tertiary recovery of viscous oils by polymer injection.
Luo, Haishan (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Unstable floods and resulting viscous fingers remain a big challenge for reservoir simulation as the gridblock size is usually many orders larger than the viscous finger wavelength. This problem becomes especially pronounced with increasing applications of polymer and other chemical floods in the development of heavy oil reservoirs. Traditional reservoir simulators do not consider sub-grid viscous fingering effects and tend to overestimate the waterflood oil recovery. Using extremely fine grid models with centimeters size is unrealistic for field-scale simulations.
While some researchers disregard viscous fingering by claiming that channeling dominates at the large scale for heterogeneous reservoirs, they miss the existence of viscous fingering at the small scale, which affects the displacement efficiency. To overcome this limitation, an effective-fingering model was developed to upscale fingering effects. The model divides each gridblock into three dynamic regions: two-phase flow, single phase oil flow, and bypassed-oil regions. Model parameters represent the maximum fraction of viscous fingering and the growth rates of different regions, which are used to modify flow functions. Model parameters from history match of a set of laboratory experiments show clear power-law correlations with a dimensionless viscous finger number, a function of viscosity ratio, velocity, permeability, interfacial tension, and core cross-sectional area.
The correlation was achieved in the lab scale by considering homogeneous cores, and we extended it further to the field scale by performing high-order spatial accuracy numerical simulations at the intermediate scale using fine gridblock sizes roughly the same as that of the core. Geostatistical realizations of the permeability field were generated with various variances and correlation lengths. In a statistical way, we were able to quantify the viscous finger number valid for a gridblock at the field scale affected by various heterogeneities using the effective-fingering model. We also observed that channelized permeability distributions increase the viscous finger number drastically, showing the important role of channeling in such cases. This new model was applied to a field case with high heterogeneity undergoing water/polymer floods. We observed that the oil recovery was improved by the polymer slug because of the enhancement in both local displacement efficiency and sweep efficiency.
In summary, we developed an upscaling model that provides a fresh-new insight on how to simulate unstable water/polymer floods at the field scale, which effectively accounts for the interplay of viscous fingering and channeling.