Viscous Oil Reservoirs Research Articles

Non-thermal recovery of a viscous oil with a surfactant-polymer process

The goal of this work is to improve recovery of a viscous oil reservoir at 70 °C using a non-thermal process. Polymer floods can improve sweep efficiency, but leave behind a residual oil saturation. A surfactant-polymer flood has the potential to improve both the sweep as well as the displacement efficiency. Phase behavior experiments with the viscous oil, water and surfactants were conducted to identify surfactants. 1D and 2D sandpack displacements were conducted to evaluate the efficacy of the process. Phase behavior experiments showed Winsor type I behavior with a low interfacial tension using a single surfactant, but not ultralow tension. Water flood recovered about 50% OOIP and reduced the oil saturation to about 45% in 1D floods. The subsequent SP flood increased the cumulative oil recovery to 99% in sandpacks when the viscosity of chemical slugs exceeded the oil viscosity. When the permeability decreased (as in a Bentheimer core), the oil recovery decreased to about 86%. Secondary SP floods also recovered most of the oil and faster than tertiary floods. Reduction of polymer concentration (and viscosity to about 1/4th of the oil viscosity) reduced the oil recovery, especially in 2D sandpack floods. Decrease in interfacial tension increased the requirement of polymer concentration to maintain flood front stability. This flood demonstrates the effectiveness of Winsor type I SP formulation for viscous oil, high permeability reservoirs. Such a SP process would reduce the carbon footprint of viscous oil recovery compared to that of thermal processes.

Bridging the performance gap between passive and autonomous inflow control devices with a hybrid dynamic optimization technique integrating machine learning and global sensitivity analysis

Wells equipped with flow control devices across their completion intervals have become a proven field development option for geologically complex and/or viscous oil reservoirs. Such wells increase oil recovery, reduce water and gas production, minimize the need for well workover operations, and subsequently lower the wells' carbon footprint. The uncontrolled types of inflow control devices include early-generation passive inflow control devices (ICDs) and later-generation autonomous inflow control devices (AICDs). The superior performance of AICDs over ICDs in managing water and gas production, as well as enhancing the overall well and reservoir performance has been demonstrated in multiple research and case studies. This superiority stems from the AICDs’ ability to self-adjust and increase their flow resistance when undesired fluids (i.e., water and/or gas) flow through them. While ICDs lack this self-adjusting feature, they are more affordable and more readily available on the market.This study aims to reduce the performance gap between passive and autonomous inflow control devices by developing a hybrid dynamic optimization technique. This approach integrates a metaheuristic algorithm, machine learning, global sensitivity analysis, and correlation measures to facilitate the optimization problem by identifying the high-impact control variables. Next, the proposed workflow finds the necessary adjustments to the original well completion design by modifying the high-impact control variables during the optimization process. This results in a modified well completion design that is less influenced by the type of inflow control device (passive or autonomous), thereby bridging the performance gap between these two completion types.The study employs a benchmark ‘Egg field’ model, featuring two multilateral wells (MLWs) producing under a water flooding recovery mechanism. Two different completion designs, utilizing either ICDs or AICDs, are optimized using standard optimization (SO) and the proposed hybrid dynamic optimization techniques. The standard optimization, which employs a standalone Particle Swarm Optimization (PSO) algorithm, highlights, as expected, the superiority of the AICD-based completion, yielding an approximately 13% increase in the net present value (NPV) over the ICD-based completion. However, when applying the hybrid optimization (HO) technique, this difference is significantly reduced to 3.4%. This indicates the potential for the hybrid optimization technique to make ICD-based completions more competitive and economically favourable compared to their AICD-based counterparts.

Effect of Temperature on Two-Phase Gas/Oil Relative Permeability in Viscous Oil Reservoirs: A Combined Experimental and History-Matching-Based Analysis

Summary Thermal enhanced oil recovery (TEOR) is the most widely accepted method for exploiting the heavy oil reservoirs in North America. In addition to improving the mobility of oil due to its viscosity reduction, the high temperature down in the hole due to the injection of the vapor phase may significantly alter the fluid flow performance and behavior, as represented by the relative permeability to fluids in the formations. Therefore, in TEOR, the relative permeabilities can change with a change in temperature. Also, there is no model that accounts for the change in temperature on two-phase gas/oil relative permeability. Further, the gas/oil relative permeability and its dependence on temperature are required data for the numerical simulation of TEOR. Very few studies are available on this topic with no emerging consensus on a general behavior of such effects. The scarcity of such studies is mostly due to experimental problems to make reliable measurements. Therefore, the primary objective of this study was to overcome the experimental issues and investigate the effect of temperature on gas/oil relative permeability. Oil displacement tests were carried out in a 45-cm-long sandpack at temperatures ranging from 64°C to 210°C using a viscous mineral oil (PAO-100), deionized water, and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to interpret the relative permeability curves for gas/heavy oil systems using the experimentally obtained displacement results. We noted that at the end of gasflooding, the “final” residual oil saturation (Sor) still eluded us even after several pore volumes (PVs) of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. The complete two-phase gas/heavy oil relative permeability curves are inferred with a newly developed systematic history-matching algorithm in this study. This systematic history-matching technique helped us to determine the uncertain parameters of the oil/gas relative permeability curves, such as the two exponents of the Corey equation (No and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted, except these four parameters (i.e., Corey exponents, true residual oil saturation, and gas endpoint relative permeability) were interpreted from simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.

Enhanced oil recovery method for highly viscous oil reservoirs based on in-situ modification of physico-chemical properties

The demand for hydrocarbons has grown substantially over the past decades and continues to do so. Thus, according to OPEC, the oil demand is expected to increase by 16.4 million barrels per day up to 2040, whereby, if in 2021 the daily hydrocarbon consumption was 99.2 mln barrels per day, by 2040 this figure will rise to 109.4 mln barrels per day. Researchers are of course trying to cope with the increasing demand for hydrocarbon energy carriers year on year by using increasingly innovative exploitation and development techniques. However, despite the prospects of these technologies, they do not entirely solve the problem. In this respect, improving the efficiency of heavy oil field development is the more realistic alternative. Today the most actual methods of heavy oil field development are the technologies aimed at in-situ modification of physical and chemical properties of oil. However, these methods still have a number of drawbacks that impede their wide commercial application. Keywords: heavy oil; enhanced oil recovery; in-situ combustion; thermal EOR; catalytic EOR.

Reinjection of Produced (Sheared) Polymer in a Canadian Viscous Oil Reservoir: Considerations to Improve Economics and Reduce Carbon Footprint

Summary Chemical enhanced oil recovery (EOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer makes this technology very expensive and challenging to implement in the field. In the majority of cases, polymer flooding alone has proved to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, a challenging economic environment has operators looking for added economic and sustainable savings. The possibility of reinjection of produced (sheared) polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery, thus offering a subsequent reduction in produced water (PW) treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in the presence of produced fluid containing residual polymer. The initial fluid-fluid testing and laboratory characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions—freshly made and combinations with residual produced polymer. Based on field observations and laboratory measurements, a 10 to 15% reduction in fresh polymer loading could be achieved through the reutilization of water containing residual polymer in these specific field conditions. Note, this case study involved produced polymer that was degraded through progressive cavity pumps (PCPs) resulting in only 15 to 20% of the injected viscosity in the produced fluids in addition to thermal and chemical degradations. The monophasic injectivity experiments in both outcrop cores resulted in similar resistance factors (RFs) for fresh polymer and blends with produced water reinjection containing residual polymer (PWcRP) solution, establishing the robustness of this blending system. Oil recovery experiments also resulted in similar oil displacement behavior [approximately 30 to 40% oil originally in place (OOIP) after 0.5 pore volumes (PV) waterflood] for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10 to 15% polymer loading reduction.

Elucidation of the mechanistic aspects of chemical EOR in viscous oil systems

Chemical enhanced oil recovery techniques have been suggested as efficient alternatives to thermal methods in many thin/small viscous oil reservoirs in western Canada. These acidic oil reservoirs have been screened as good candidates for alkaline (A) and surfactant (S) floods. In this study, sand-pack core flooding experiments and pore-scale microfluidic tests were designed to give some new insights on the mechanisms of AS floods augmented with polymer (P) solutions in viscous oil systems.Viscous oil samples from Luseland field (14,850 mPa s at 25 °C) was used in all the experiments. The most efficient chemical generates ultralow interfacial tension, 0.002 mN/m, producing low viscosity type II (+) emulsion (740 mPa s, which is much lower than the viscosity of originating oil). The two pore volumes injection of this cocktail results in around 20% OOIP incremental oil recovery, which is almost doubled after injecting two pore volumes of extended water. The core effluents were all low viscosity oil in water emulsions, consistent with observations in batch mixing experiments. The incremental oil recovery to ASP flood is almost twice the recovery obtained in the polymer flood with nearly 4.5 times larger pressure build-up across the core. These observations suggest that the main mechanism is emulsification and oil entrainment rather than improvement in sweep efficiency.These speculated mechanisms based on the core scale observations were verified through the results of the microfluidic experiments. ASP solution can efficiently penetrate the residual ganglia or the edge of the water channels from which oil can be efficiently stripped. This oil is easily entrained in the form of low viscosity oil in water emulsions. Our results emphasize the critical role of polymer in the cocktail. In the absence of polymer, AS cannot efficiently penetrate the residual viscous oil leading to only a minuscule improvement in oil recovery.

Pressure Modification or Barrier Issues during Polymer Flooding Enhanced Oil Recovery

Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drops from the injection well to the polymer front may act as a pressure modification or barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity. This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Analytical and numerical methods are used to address this issue. We examine the relevance of the pressure modification concept for a wide variety of circumstances, including oil viscosities ranging from 10 cp to 1650 cp, vertical wells versus horizontal wells, single versus multiple layered reservoirs, permeability contrast, and crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multizoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors intervene. For multizoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. This work is particularly relevant to viscous oil reservoirs where polymer viscosities are substantially lower than the oil viscosity.

Application of “oil-phase” microbes to enhance oil recovery in extra heavy oil reservoir with high water-cut: A proof-of-concept study

Microbial enhanced oil recovery (MEOR) is an important tertiary recovery technology to recover oil, especially heavy oil, from reservoirs. However, MEOR often fails to achieve satisfactory oil recovery in the field applications because of utilization of unsuitable microorganisms and nutrients. Recent studies proved the existence of microbes inside oil (“oil-phase” microbes) and their potential for application in MEOR. To validate this concept, we isolated microbes from the “oil-phase” of crude oil samples. With them, a synthetic four-member microbial consortium K, was selected to use in an experiment of core flooding, which showed a beneficial capacity for improving oil recovery. Furthermore, the consortium K and nutrients were applied in a field trial of microbial huff and puff in an extra heavy oil recovery. Results demonstrated the incremental cumulative oil production of two high water-cut (99%) shut-in wells reached 1078.8 t and 791.6 t, respectively, with the effective period of 14 months, while the viscosity of heavy oil had significantly declined decreased by 50%. In conclusion, our findings clearly demonstrate that the great potential of a novel methodology to use indigenous “oil-phase” microbes as seedbanks for improving oil recovery in extremely viscous oil reservoirs with high water-cut.

Experimental Investigation of Polymer-Induced Fouling of Heater Tubes in the First-Ever Polymer Flood on Alaska North Slope Part II

Summary A polymer flood pilot has been ongoing in the Schrader Bluff viscous oil reservoir at Milne Point on the Alaska North Slope. The results from the pilot are encouraging. However, a major concern of the operator is the influence of polymer on the production system after breakthrough, especially the fouling in heat exchangers. This work applies a multiexperimental approach to study the severity of polymer-induced fouling in both dynamic and static states of produced fluids to determine safe operating conditions. Dynamic scale loop (DSL) tests were conducted to study fouling due to polymer at different skin temperatures (165–350°F) in a dynamic state of fluid flow where the fluids’ flow mimics the residence time of fluids in the heat exchanger of the field pilot. Static deposit tests were also conducted at similar skin temperatures of 165–250°F using a novel experimental apparatus designed and built in-house. It was found that at higher skin temperatures of 250–350°F, tube blocking was observed in the DSL tests, whereas the tests at 165–200°F did not show any tube blocking, even in a more extended test period. The deposit test showed that the deposit rate generally increases with skin temperature, and the presence of polymer aggravates the fouling. The copper tube performs best when the skin temperatures are 165–200°F, while the stainless steel tube performs best at a skin temperature of 250°F. These experiments also manifested the influence of the cloudpoint of the solution as the deposit rate increased significantly when the skin temperature was higher than the solution cloudpoint. The study provides a source of practical guidance to the field operations.

Impact of Polymer Rheology on Gel Treatment Performance of Horizontal Wells with Severe Channeling

Summary Gel treatment has been a cost-effective method to control the conformance of a reservoir with severe heterogeneity problems. The water channels in such reservoirs can be classified as open fractures or high permeability porous media with pore-throat network. Many simulation studies have been conducted to discuss gel treatment performance for conformance control. However, nobody considered the polymer rheology difference in open fractures and porous media in simulation. Previous simulation studies also ignored the residual resistance factor as a function of rock permeability rather than a constant parameter. In this study, a conceptual simulation model was established to simulate the linear flow system for the reservoir with horizontal wells considering the two factors mentioned above. The results demonstrate that the gel treatment always provides the better placement results in the open fracture type channel than pore-throat network type channel. Moreover, it is very necessary to consider residual resistance factor as a function of permeability, which is based on the experimental results and can provide much greater plugging efficiency in the higher permeable channels than constant residual resistance factor. Sensitivity analysis studies and multifactor analysis indicate that increasing oil viscosity and permeability ratio has a strong positive influence on conformance control results, which indicate in-situ gel treatment can be better applied in heavy or viscous oil reservoirs with fracture-like channels. Besides, the results also indicate that in reservoirs with severe channeling problem where channel velocity was high, the differences of gelant placement and profile improvement in models with two different types of channels could be enlarged greatly.

Evaluation of Chemical Application as Pilot to Improve Oil Production from High Viscous Oil in Sandstone Reservoir

Chemical injection stimulation is one of worldwide proven technologies for viscosity reduction and mobility enhancement. The principle mechanism is to reduce heavy oil viscosity by injecting of active chemical agent solution into reservoir as huff and buff practice, the agent solution is act at near wellbore area by remove plugging of heavy organic material, Energy support due to large quantity of stimulation liquid being injected into the formation, viscosity reduction by emulsification and micro-emulsion which will greatly enhance oil mobility; therefore, accelerate oil recovery and reduce interfacial tension (IFT); therefore, increase oil recovery. as global oil industry many technologies introduced to Sudanese oil fields such as chemical which had been implemented in 2018 to increase oil production by developing high viscous oil reservoirs. The pilot was done in two wells in Moga and Fula fields; they are located at southern part of western escarpment trend of Fula sub-basin, Main oil-bearing distributes in Aradeiba, Bentiu and Abu Gabra formations. Bentiu formation was selected for pilot, it is consolidated medium productive sand stone reservoir as per well test interpretation productivity index is 0.05 to 0.2 bbl/day/psia, PVT features: low bubble point pressure, low gas oil ratio (GOR), viscosity at initial pressure between 396–5902 mPa.s and 8986–13880 mPa.s at surface pressure and 29°C, permeability lab test results show strong heterogeneity formation. This paper discusses the chemical injection as enhanced oil recovery (EOR) application in block-6, investigate and evaluate pilot results, then discuss lesson learned from this pilot. Basic reservoir engineering principles and lab test result had been used to calculate production and reservoir parameters before and after implementation. The results of first well shows instantaneous downhole fluid level (DFL) raising about 129 m and remain stable while same pump speed was maintained after the chemical injection, the water cut dropped from 64% to 42% and Oil rate jumped from 95 BOPD to 204 BOPD. second well shows bad performance post the chemical injection and the oil rate decreased from 60 to 40 BOPD and WC increased from 70% to 93% due to well located in the down dip close to OWC and strong reservoir pressure support.

Tectonic aspects of super-viscous oil deposits formation and placement within the Volga-Ural anteclise

The article discusses the tectonics and developmental features of the Volga-Ural anteclise during the Baikalian, Caledonian, Hercynian and Alpine tectogenesis cycles. In this paper, particular attention is paid to stages and directional development during the evolution of geological structures. The main factors of the formation and destruction of Permian viscous oil and natural bitumen reservoirs are presented in the provisions of oil ontogenesis. It was noted the cyclical nature of these phenomena. Keywords: Volga-Ural anteclise; super-viscous oil; tectonic; reservoir; oil.

An Experimental Study of Improving Viscous Oil Recovery by Using Hybrid Enhanced Oil Recovery Techniques: A Case Study of Alaska North Slope Reservoir

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

Effect of water injection on subsequent polymer floods in viscous oil reservoirs

Waterfloods (WF) in viscous oil reservoirs (>100 cp) are unstable and usually bypass a large amount of oil. Polymer floods (PF) often follow waterfloods and improve oil recovery through improved sweep efficiency. This study examines the effect of prior waterflood on the subsequent polymer flooding. The displacement of a viscous oil by water and polymer solution is studied in a custom-built 2D porous medium. Floods are conducted at the interstitial velocity of 1 ft/day with the oil viscosity (μo) of 390 cp at 25 °C. The extent of waterflood beyond the water breakthrough (WBT) is varied from 0 to 0.5 injected pore volume (PV). Polymer injection after the waterflood displaces the oil which further pushes the brine in the established water fingers and is reflected in a decrease in the water cut down to 0–0.3. After dewatering of the fingers, the polymer solution displaces the oil across the whole cross-section. The final recoveries range from 73 to 83 % of the original oil in place (OOIP). Injecting the viscous solution at earlier stages results in earlier production, higher crest of oil cut (fo) and slightly higher cumulative oil production (NpD). This work can help engineers optimize the strategy of polymer flooding in viscous oil reservoirs.

Steam alternating non-condensable gas injection for more heavy oil recovery

Recent studies and field operations show that co-injection of steam and non-condensable gas could reduce the steam-oil ratio significantly, which means the steam and gas push process (SAGP) could be more environmentally friendly than the conventional steam-assisted gravity drainage (SAGD) process. However, this modification may eventually cause a drop in the cumulative volume of produced oil. In this paper, we develop a technique to overcome the adverse impact of SAGP on the final oil recovery: this technique employs alternate steam and a mixture of steam and non-condensable gas injection into the viscous oil reservoir to take advantage of a high steam chamber volume, pushing pressure at the reservoir top and lower heat loss to overburden rocks, simultaneously. The technique (so-called SANG) is examined numerically in a reservoir with average properties from Athabasca, and the results are compared to the conventional SAGD and SAGP. Effects of changing reservoir properties and operating conditions on the performance of the SANG together with a cost-benefit analysis and CO2 emissions are elucidated. Based on the results, the SANG would effectively improve the performance of the thermal gravity process within viscous oil reservoirs and, provided it is validated, it can replace the conventional SAGD and SAGP.

Experimental Microemulsion Flooding Study to Increase Low Viscosity Oil Recovery Using Glass Micromodel

The growing demand for clean energy can be met by improving the recovery of current resources. One of the effective methods in recovering the unswept reserves is chemical flooding. Microemulsion flooding is an alternative for surfactant flooding in a chemical-enhanced oil recovery method and can entirely sweep the remaining oil in porous media. The efficiency of microemulsion flooding is guaranteed through phase behavior analysis and customization regarding the actual field conditions. Reviewing the literature, there is a lack of experience that compared the macroscopic and microscopic efficiency of microemulsion flooding, especially in low viscous oil reservoirs. In the current study, one-quarter five-spot glass micromodel was implemented for investigating the effect of different parameters on microemulsion efficiency, including surfactant types, injection rate, and micromodel pattern. Image analysis techniques were applied to represent the phase saturations throughout the microemulsion flooding tests. The results confirm the appropriate efficiency of microemulsion flooding in improving the ultimate recovery. LABS microemulsion has the highest efficiency, and the increment of the injection rate has an adverse effect on oil recovery. According to the pore structure’s tests, it seems that permeability has little impact on recovery. The results of this study can be used in enhanced oil recovery designs in low-viscosity oil fields. It shows the impact of crucial parameters in microemulsion flooding.

An analytical tool to forecast horizontal well injectivity in viscous oil polymer floods

Injection rate is a key factor for successful polymer floods of viscous oil reservoirs. Injectivity during polymer flooding is lower compared to waterflooding due to the viscosity of polymer solution. Accurate estimation of injection rate/pressure build-up due to polymer injection is essential to evaluation and design of polymer flood projects. Typically, a short-term polymer injectivity test is performed on a single well, but it is hard to extrapolate future behavior of polymer injectivity because the tests are often too short. Reservoir simulation can be used to forecast injectivity, but the grid size and radial flow often affect the calculated injectivity. Analytical methods provide simple and quick ways to estimate injectivity using realistic reservoir conditions. The goal of this work is to develop an analytical tool and demonstrate its applicability by comparison with field data. An analytical solution is developed for the injectivity of horizontal wells in polymer floods in viscous oil reservoirs. The analytical solution is validated by comparing it to a numerical field-scale box model simulation. The pressure profiles are calculated using spreadsheets and compared against the data from several fields with increasing degrees of complexity. In each case, the analytical-spreadsheet method provides close matches of injection pressure data. This analytical tool can be used for preliminary design of polymer floods before getting into more complex and time-consuming reservoir simulations. • Developed an analytical solution for injectivity in viscous oil polymer floods. • Compared the analytical solution to numerical simulation with grid refinement. • Compared analytical solution to field data from 5 wells. • Novel tool to design and optimize polymer floods in viscous oil reservoirs.

Contribution of water-in-oil emulsion formation and pressure fluctuations to low salinity waterflooding of asphaltic oils: A pore-scale perspective

During the low salinity waterflooding (LSWF) of a viscous asphaltic oil reservoir, fluid-fluid interactions have a large influence on the fluid flow, pore-scale events, and thus oil recovery efficiency and behavior. In-situ water-in-oil (W/O) emulsion formation is a consequence of crude oil and brine interfacial activities. Despite the published studies, the pore-scale mechanisms of W/O emulsion formation and the role of injected brine salinity, injection rate, and pore-scale heterogeneity on emulsion formation and stability requires a deeper understanding. To address these, a series of static and dynamic micro-scale experiments were performed. The salinity dependent oil-brine interactions were characterized using interfacial tension (IFT) measurements, brine pH measurement, Fourier-transform infrared spectroscopy (FTIR), and W/O emulsion analysis. The results of static experiments showed that regardless of brine salinity, W/O emulsion does not form spontaneously and shear force is required. However, the microfluidic LSWF experiments revealed considerable formation of W/O emulsions and water-breakup. This was concomitant with fluctuations in the differential pressure. The pressure fluctuation was intensified as salinity was reduced, but was highest at the lowest IFT. Moreover, the severity of emulsion formation was intensified at lower rates and by increasing the pore-scale heterogeneity. Two principal mechanisms of W/O emulsion and water-breakup were identified: water snap-off, and water shortcut. The high viscosity of the asphaltic oil intensifies the former mechanism. While the latter is formed in water-wet regions and via movement of the waterfront through the thin layer of connate water. Emulsion division and rupture are two additional/axillary mechanisms leading to further break-up of the water phase. Emulsion formation leads to pore-scale flow diversion which in addition to other mechanisms contributes to improving oil recovery by LSWF. The novel insights gained in this study contribute to a better understanding of LSWF as well as other water-based EOR methods in viscous asphaltic oil reservoirs.

Optimal Wellbore Placement of a Penta-Lateral Well in the Schrader Bluff Reservoir, North Slope, Alaska

Summary A significant oil resource exists within the Schrader Bluff and stratigraphic equivalent West Sak reservoirs located on the central North Slope of Alaska. The Schrader Bluff resource is under development in the Kuparuk River Unit, Milne Point, and within the Prudhoe Bay Unit. These areas have developed reservoirs with oil viscosities up to 200 cp under waterflood and viscosity-reducing miscible gas injection. A grass roots penta-lateral gas-lifted producer was drilled and completed to unlock untapped oil in the northern portion of the Polaris S-Pad Schrader Bluff viscous oil reservoir in Prudhoe Bay, Alaska. This producer was the first multilateral well drilled in the Orion and Polaris Schrader Bluff reservoirs in ≈8 years. The team worked to unlock surface and subsurface opportunities, delivering a substantially lower cost of access than planned. Production rate from Schrader Bluff reservoir wells has a positive correlation with contacted net sandstone. Optimal well placement in each of the five laterals was key to the delivery of a successful project. A novel approach to geosteering was used to maximize net sandstone exposure, utilizing deep azimuthal resistivity and real-time user-guided multilayered inversion modeling.

Experimental Investigation of Polymer-Induced Fouling of Heater Tubes in the First-Ever Polymer Flood Pilot on Alaska North Slope

Summary Polymer flooding is being pilot tested for the first time in the Schrader Bluff viscous oil reservoir at the Milne Point Field on Alaska North Slope (ANS). One of the major concerns of the operator is the impact of polymer on the oil production system after polymer breakthrough, especially the polymer-induced fouling issues in the heat exchanger. This study investigates the propensity of polymer fouling on the heater tubes as a function of different variables, with the ultimate goal of determining safe and efficient operating conditions. A unique experimental setup was designed and developed in-house to simulate the fouling process on the heating tube. The influence of heating tube skin temperature, tube material, and polymer concentration on fouling tendency was investigated. Each test was run five times with the same tube, and in each run, the freshly prepared synthetic brine and polymer solution was heated from 77°F to 122°F to mimic field-operating conditions. The heating time and fouling amount were recorded for each run. Cloud point measurement has also been conducted to find the critical temperature at which the polymer in solution becomes unstable and precipitates out. The morphology and composition of the deposit samples were analyzed by environmental scanning electron microscopy (ESEM) and X-ray diffraction (XRD), respectively. It was found that the presence of polymer in produced fluids would aggravate the fouling issues on both carbon steel and stainless steel surfaces at all tested skin temperatures. Only higher skin temperatures of 250°F and 350°F could cause polymer-induced fouling issues on the copper tube surface, and the fouling tendency increased with polymer concentration. At the lower skin temperatures of 165°F, no polymer-induced fouling was identified on the copper tube. A critical temperature that is related to the cloud point of the polymer solution was believed to exist, below which polymer-induced fouling would not occur and only mineral scale was deposited but above which the polymer would aggravate the fouling issue. The cloud point of the tested polymer solution was determined to be between 220°F and 230°F. From a practical safer design standpoint, we recommend a value of 220°F for operational purposes on the pilot site. The heating efficiency of the tube would be decreased gradually as more fouling material accumulates on its surface. If polymer precipitated and deposited on the surface, it would bond to the mineral crystals to form a robust three-dimensional network structure, resulting in a rigid polymer-induced fouling. The study results have provided practical guidance to the field operator for the ongoing polymer flooding pilot test on ANS.