Improve Sweep Efficiency 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.

Potential of polymer’s viscosity and viscoelasticity for accessible oil recovery during low salinity polymer flooding in heterogeneous carbonates

Despite the usual improvement in sweep efficiency during polymer flooding, the polymer’s viscoelastic characteristics were reported to contribute to residual oil recovery in sandstone reservoirs at high flux conditions. In carbonate reservoirs, besides high-salinity, high-temperature, and non-water-wet nature, heterogeneity is a key variable that may impair the viscoelastic fluid flow in the porous media and recovery performance. However, no attempts were made to study the polymer’s viscoelastic influence on residual oil recovery in heterogeneous carbonate formations and the objective of this paper is to systematically examine the recovery performance of high molecular weight viscoelastic sulfonated polymer (AN-125-SH) in comparison to viscous xanthan gum polymer with the low salinity injection water of 5957 ppm total dissolved solids (TDS) in heterogeneous outcrop carbonate rocks at fluxes ranging from shear thinning to shear thickening using the combination of bulk shear rheometry, NMR, single-phase in-situ studies and two-phase core flooding experiments.Nuclear magnetic resonance (NMR) imaging ensured that the chosen cores are characterized with similar pore-size distribution. The steady-shear rheological experiments showed that 2500 ppm AN-125-SH polymer exhibits a lower viscosity at the lower shear rate and an early shear thickening (indicating higher non-linear viscoelasticity) than 2000 ppm xanthan gum. Then single-phase flow experiments are conducted using two polymer systems to determine the desired flux rates before the eventual multi-rate two-phase core flood experiments. Core flooding results revealed following an extensive secondary water flooding, at the shear thinning flux of 4 ft/day, 2000 ppm high viscous xanthan gum injection leads to an incremental recovery factor of 8.3 % with the generated pressure gradient of 20.48 psi/ft compared to 3.6 % recovery obtained using 2500 ppm AN 125-SH polymer with a pressure gradient of 16.2 psi/ft. However, at shear thickening fluxes of 20 ft/day and 30.5 ft/day, the higher elastic polymer enhanced the recovery by 3.3 % and 1.2 %, respectively. Conversely, the less elastic xanthan gum showed minimal to no incremental recovery at these fluxes.The novel findings of this work convey that the viscosity of xanthan gum provides a comparative advantage over the viscoelasticity of synthetic sulfonated polymers on oil recovery at relatively low fluxes in the studied heterogeneous formation at low salinity conditions.

The impact of chelating agent pH on the stability and viscosity of CO2 foam under harsh reservoir conditions

The injection of CO2 foam into the carbonate reservoir for enhanced oil recovery (EOR) has attracted special interest in the last decades; nevertheless, the understanding of the effect of liquid solution chemistry on foam stability at high temperatures and salinities is limited. Hence, this paper fully investigates the effect of chelating agents L-glutamic acid-N, N-diacetic acid (GLDA) pH, and hydrochloric acid (HCl) on the stability and viscosity of generated CO2 foam for heterogeneous carbonate formation under reservoir conditions. In this paper, Duomeen TTM and Armovis VES surfactants were utilized due to their capabilities to produce viscous CO2 foam under harsh conditions. The foamability, foam stability, and foam structure were studied at 100 °C and 1000 psi using a high-temperature and high-pressure (HPHT) foam analyzer. The measurement of CO2 foam viscosity was determined at 100 °C, 1000 psi, and 70 % foam quality using the HPHT foam rheometer. Rheology experiments and dynamic light scattering investigated the micelle’s size or aggregation behavior of surfactants. The obtained results showed that the Duomeen TTM generated unstable foam; however, foam stability and foamability improved with the decrease in GLDA pH. Armovis VES showed excellent CO2 foam performance, where the foam half-life time of Armovis VES systems was 240 min. The liquid drainage and bubble coarsening were delayed due to the formation of the viscoelastic liquid phase. The foamability of Armovis VES was improved as the GLDA pH decreased. Furthermore, the addition of HCl to Armovis VES solution presented the highest foamability. The outcomes of the HPHT foam analyzer and HPHT viscometer proved that as the pH of Armovis VES solution decreased, higher foamability was produced. The highest foam viscosity was obtained using the synergic effect of 0.5 wt% Duomeen TTM and 0.5 wt% Armovis VES (39 cp at 100/s). In comparison, 1 wt% Armovis VES presented the lowest foam viscosity (30 cp at 100/s). The outcomes of this research can provide insight into the effect of chemistry on CO2 foam and extend its application in oilfield development. This work broadens the design of novel CO2 foam formulation, leading to the improvement of sweep efficiency in CO2-EOR methods and enhance the gas trapping in carbon storage.

Flow Behavior and Mechanism Insights into Nanoparticle-Surfactant-Stabilized Nitrogen Foam for Enhanced Oil Recovery in the Mature Waterflooding Reservoir.

To solve the problem of poor stability and low enhanced oil recovery efficiency of conventional foam, nanoparticle-surfactant-stabilized nitrogen foam was prepared, and the influence of temperature, salinity, oil content, and pressure on foam performance was systematically investigated. Then, the flow behavior of conventional foam and nanoparticle-surfactant-stabilized foam in porous media was studied. Parallel sand pack flooding and visualization microflooding experiments were performed to investigate the enhanced oil recovery ability of nanoparticle-surfactant-stabilized foam from core-scale to pore-scale. Results showed that the nanoparticles can improve foam performance. When the temperature increases from 60 to 100 °C, the foam volume and foam half-life of nanoparticle-surfactant-stabilized foam decrease by 20 and 36%, respectively. The nanoparticle-surfactant-stabilized foam has a good salt resistance. The oil content limit value of the foam performance is 15%. With the increase of pressure, the foaming performance and foam stability are enhanced obviously. Compared with conventional surfactant-stabilized foam, the nanoparticle-surfactant-stabilized foam can have better plugging and expansion of the swept volume capacity. The micromodel flooding results are consistent with the parallel sand pack flooding results. Compared with conventional surfactant stabilized foam, nanoparticle-surfactant-stabilized foam has better enhanced oil recovery ability than conventional surfactant-stabilized foam due to its higher foaming ability, foam stability, and sweep efficiency improvement ability.

Polyetheramine enhanced biosurfactant/biopolymer flooding for enhanced oil recovery

The application of conventional alkali, surfactant and polymer in alkali/surfactant/polymer (ASP) flooding has exposed the inherent shortcomings of pollution and damage to reservoirs. Hence, finding new environmentally friendly alternatives is essential for the sustainable development of ASP flooding. In this paper, we proposed a novel ternary combination utilizing organic alkali polyetheramine, biosurfactant, and biopolymer as alternative chemical agents for ASP flooding. Specifically, the ASP system composed of polyetheramine D230, biosurfactant sophorolipid (SL) and biopolymer welan gum (WLG) exhibited excellent potential in improving oil recovery. The interfacial tension measurements proved that D230 could react with organic acids in crude oil to generate surface-active soaps, which cooperated with SL to reduce the oil–water interfacial tension to 10−2 mN/m. The rheological measurements demonstrated that the addition of D230 could increase the viscosity of low concentration WLG solution, but this phenomenon gradually disappeared with the rise of WLG concentration. Even at higher WLG concentration, D230 only caused a slight decrease in system viscosity, which facilitated the improvement of sweep efficiency. Emulsification and contact angle measurements indicated that D230/SL blend had outstanding emulsifying ability and successfully altered the quartz surface from oil-wet to water-wet. Core flooding experiments and micromodel experiments showed that the D230/SL/WLG system significantly enhanced oil recovery by 22.66 %, which was attributed to the high viscosity, low interfacial tension, excellent wettability reversal and emulsifying abilities of the system. The economic benefit assessment indicated that this ASP system has the potential to be economic, rendering it profitable even during periods of low oil prices. Furthermore, the EC50 value of 52,600 mg/L for D230/SL/WLG demonstrated its environmental friendliness.

Low-salinity water flooding by a novel hybrid of nano γ-Al2O3/SiO2 modified with a green surfactant for enhanced oil recovery

This paper introduces a hybrid enhanced oil recovery (HEOR) method that combines a low-salinity water flooding (LSWF) and nanoparticles (NPs) stabilized with a green surfactant. We experimentally investigated the use of combinations of silica (SiO2) and gamma alumina (γ-Al2O3) nanohybrids stabilized with Gum Arabic (GA) at different water salinities. Nanofluids (NFs) were prepared by dispersing γ-Al2O3 and SiO2 NPs (0.1 wt%) in deionized water (DW), synthetic seawater (SSW), 2, 5, and 10 times diluted samples of synthetic seawater (in short 2-DSSW, 5-DSSW and 10-DSSW, respectively). The challenge is that NPs become unstable in the presence of cations in saline water. Moreover, an attempt was made to introduce NFs with high stability for a long period of time as the optimal NFs. The effects of temperature on the behaviour of optimal NFs in the presence of different base fluids, distinct mass ratios of γ-Al2O3/SiO2 and various concentrations of surfactant were analysed via interfacial tension (IFT) and viscosity measurements. The results of the viscosity measurement showed that with increasing temperature, the NPs dispersed in DW had lower viscosity than NPs dispersed in various salinities. However, the IFT measurement for NPs dispersed in different base-fluids revealed that with increasing temperature and presence of cations in saline water, IFT values decreases. Although, the minimum IFT for hybrid nanofluid (HNF) γ-Al2O3/SiO2 modified with GA and dispersed in 10-DSSW was reported 0.99 mN/m. Finally, according to the micromodel flooding results, in oil-wet conditions, the highest oil recovery for combination γ-Al2O3/SiO2 modified with GA and dispersed in 2-DSSW was reported 60.34%. It was concluded that NFs modified with GA could enhanced applicability of LSWF via delay in breakthrough time and improving sweep efficiency.

Pore-scale flooding experiments reveal the thermally regulated flow fields of the curdlan solution

Polymers can enhance oil recovery depending on viscoelasticity. In a field, during polymer flow through porous strata, continuous shear forces result in severe viscosity loss. However, polymers with great shear resistance result in limited migration distance. One solution to the above dilemma is to regulate viscosity, which enables a polymer to migrate long distances through pores with low viscosity and subsequently maintain high viscosity in deep reservoirs. The viscosity of curdlan can be regulated by changing temperature. By curdlan, we mean a biopolymer that shows applications in food industry. However, regarding oil reservoirs, it is unclear whether curdlan viscosity can be effectively regulated in pores. To reveal the feasibility of curdlan viscosity regulation to enhance oil recovery, flooding experiments combined with micro-particle image velocimetry were conducted in a two-dimensional pore network to investigate flow fields of curdlan solutions (0.25%, 0.5%, 1%, and 2%, w/v) at different temperatures (40, 65, and 85 °C). As a result, at 40 °C, curdlan solution (0.25%) easily migrated with low viscosity loss and low adsorption [88.3% original throat diameter (OTD)], and the mobility of curdlan was higher than hydrolyzed polyacrylamide. After heating (65 °C), the viscoelasticity, adsorption (55.1% OTD), and flow resistance (injection pressure, 2.2–8.8 kPa) of curdlan increased, and the greater adsorption capacity of curdlan than xanthan gum led to a more homogeneous flow field [average velocity ratio (Rm), from 2.6 to 1.1]. Since a homogeneous flow field indicated better sweep efficiency, curdlan regulated by temperature could achieve both long-distance migration and improved sweep efficiency in deep strata. These results suggested that viscosity regulation by curdlan could potentially improve oil recovery in water-flooded reservoirs.

Maximizing the capacity and benefit of CO2 storage in depleted oil reservoirs

Sequestering CO2 in depleted oil reservoirs provides one of the most appealing measures to reduce greenhouse gases (GHG) concentration in the atmosphere. The remaining liquids after enhanced oil recovery (EOR) processes, including residual oil and remaining water, lead to the main challenges to this approach. How to effectively evacuate a depleted oil reservoir by recovering not only residual oil but also remaining water is a critical consideration for this type of CO2 sequestration. This paper presents conceptual investigations concerning the methods which effectively evacuate depleted oil reservoirs from both the displacement efficiency and the sweep efficiency points of view. To improve the displacement efficiency, surfactant slug and solvent slug injection was examined using a core scale numerical model. Investigations regarding improving sweep efficiency, such as horizontal well pattern infilling and foam injection, were carried out based on a typical row well pattern. Simulation results showed that surfactant slug which modified the relative permeability and capillary pressure remarkably reduced both residual oil saturation and remaining water saturation. A CO2 slug injected before surfactant slug can help improve the oil recovery. Solvent enriched CO2 slug also remarkably reduced the residual oil saturation to as low as 2%. Horizontal well pattern infilling had great advantage for thick or inclined reservoirs, and foam slug injection greatly improved CO2 storage capacity in thin reservoirs by improving the sweep efficiency. Maximum mobility reduction (MRF) is the most important parameter to maximize the storage capacity and the benefit. The variation of CO2 storage capacity along with CO2 slug size. Larger foam slug size will play a better storage performance. The conceptual simulation investigations confirmed that depleted oil reservoirs can be effectively evacuated for CO2 storage. Depleted oil reservoirs with maximum evacuation are the best candidates for CO2 sequestrations.

Numerical study of the mechanisms of nano-assisted foam flooding in porous media as an alternative to gas flooding

Oil reservoirs are nearing maturation, necessitating novel enhanced oil recovery (EOR) techniques to meet escalating global energy demands. This demand has spurred interest in reservoir production analysis and forecasting tools to enhance economic and technical efficiency. Accurate validation of these tools, known as simulators, using laboratory or field data is pivotal for precise reservoir productivity estimation. This study delves into the application of nanoparticles in foam flooding for mobility control to improve sweep efficiency. Foam generation can occur in-situ by simultaneous injection of surfactants and gas or through pre-generated foam injection into the reservoir. In this work, a series of systematic simulations were run to investigate how much injected fluids can reduce gas breakthrough while also increasing oil recovery. Subsequently, we analyzed the most effective optimization strategies, considering their economic limits. Our primary objective is to numerically model nanofoam flooding as an innovative EOR approach, synergizing foam flooding mechanisms with nanotechnology benefits. In this work, modeling of nanoparticles in foam liquid was represented by the interfacial properties provided to the injection fluid. Additionally, we simulated Water-Alternating-Gas (WAG) injection schemes across various cycles, comparing their outcomes. Our results showed that nanofoam injection achieved a higher recovery factor of at least 38% and 95% more than WAG and gas injections, respectively. The superior efficiency and productivity of foam injection compared to WAG and gas injection suggest an optimal EOR approach within the scope of our model. These simulated optimization techniques contribute to the future development of processes in this field.

Assessment of World’s First Two Polymer Injectivity Tests Performed in Two Giant High-Temperature/High-Salinity Carbonate Reservoirs Using Single-Well Simulation Models and Pressure Falloff Tests Analysis

Summary Polymer flooding is a mature enhanced oil recovery (EOR) technology that has been widely implemented around the world for more than 60 years. Polymer flooding mostly targets medium- to high-permeability sandstone reservoirs with moderate salinity, hardness, and temperatures. However, in the last few years, the envelope of polymer flooding has been expanded to harsher reservoir conditions of high-temperature and high-salinity mixed-wet to oil-wet heterogeneous carbonate reservoirs. Development of novel polymers and innovative field application concepts has allowed for the reconsideration of polymer-based EOR as a promising technology to improve sweep efficiency for these challenging reservoirs. Polymer injectivity is one of the key challenges for polymer flooding projects and requires a rigorous derisking program that includes laboratory and field testing. A comprehensive laboratory program was designed to assess and investigate polymer thermal stability, polymer rheology in porous media, adsorption, and injectivity using reservoir core samples. In addition, two polymer injectivity tests (PITs) were performed in two giant light oil (0.3 cp) carbonate reservoirs in onshore Abu Dhabi under harsh conditions of high salinity (>200 g/L), high divalent ions (>20 g/L), high temperature (>250°F), and H2S concentration of up to 40 ppm. The polymer used during the two PITs (PIT 1 2019 and PIT 2 2021) is a new generation of EOR polymer (SAV 10) with high 2-acrylamido-tertiary-butyl sulfonic acid content that was specifically developed to tolerate such harsh conditions. This paper is focused on the interpretation of the PITs and lessons learned for future polymer-based EOR projects. The detailed data acquired in both tests were used to evaluate the polymer injectivity at representative field conditions and in-depth mobility reduction. The PITs together with the extensive laboratory studies are part of a thorough derisking program for the upcoming world’s first innovative hybrid EOR multiwell pilots—simultaneous injection of miscible gas and polymer (SIMGAP) and simultaneous injection of water and polymer (SIWAP). Both PITs are composed of three stages that include a multirate waterflood baseline, polymer injection using different rates, and polymer concentrations followed by extended chase waterflooding. In addition, a sequence of multiple pressure falloff (PFO) tests was acquired during the PIT executions and analyzed to obtain the required uncertainty parameters for the history-matching exercise. Polymer preshearing was considered as part of both PIT programs with the aim to homogenize the polymer molecular weight distribution and reduce possible shear-thickening effects near the wellbore as per laboratory measurements. Two single-well 3D simulation models were built to incorporate the information from polymer laboratory studies and to interpret the large field data sets acquired during the PITs. Lessons learned from PIT 1 allowed us to optimize the PIT 2 design program and achieve better understanding of polymer characteristics. The interpretation of the pressure transient analysis (PTA) of the PFO tests and the 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of the future SIWAP and SIMGAP interwell pilots.

Scope of Implementation of Low Salinity Nanofluid to Improve Oil Recovery in a Part of the Hapjan Oil Field of Upper Assam Basin

The application of nanoparticles in the field of Enhanced Oil Recovery (EOR) has been an emerging technology in recent years. Earlier studies have shown that the nanofluids containing nanoparticles (NPs) of average size (<100 nm) can enhance the oil recovery through wettability alteration of rock, reduction of mobility ratio, reduction of oil-aqueous solution interfacial tension (IFT), reduction of sand production and improvement of sweep efficiency. Low Salinity Waterflooding (LSW) has been utilized as a promising EOR method in the last two decades. Recent studies have found that nanoparticle-assisted LSW embraces both nanoparticles and ions as EOR agents in the injection brine. This study investigates the scope of implementation of the low salinity nanofluid EOR using silica nanoparticles to improve oil recovery in the Tipam Reservoir Sandstone of the Hapjan Oil Field of Upper Assam Basin, India. The analysis of the reservoir brine, reservoir rock and crude oil shows the presence of divalent cations (Ca2+ and Mg2+), clay minerals (Illite and Smectite) and polar compounds (Asphaltene and Resin) respectively. The presence of the divalent cations, clay minerals and polar compounds in the Crude Oil/Brine/Rock system of a sandstone reservoir is the prerequisite for implementing low salinity nanofluid EOR. The study shows that the low salinity nanofluids can shift the wettability of the rock to a more water-wet state. It is also observed that the silica nanoparticles can increase the nanofluid viscosity and reduce the oil-nanofluid IFT, which can improve the recovery of oil. The experimental results show that the study area has great potential for the low salinity silica nanofluid EOR to improve oil recovery.

Foam formation during drainage of a surfactant solution in a microfluidic porous medium model

Foam has been shown to have great potential to significantly improve sweep efficiency during gas injection in oil recovery, remediation of contaminated sites, gas storage, and acidification processes. The gas mobility reduction largely depends on the generation and stability of lamellae in the pore space that traps the gas phase. Most available analyses focus on foam formation during the co-injection of gas and liquid phases at different fractional flow (foam quality) or flow of foam formed before being injected in the porous media. During surfactant-alternating-gas (SAG) injection, foam is formed as the aqueous phase is displaced by the gas slug that follows. The dynamics of lamellae formation and their stability are different from that of a co-injection process, since the amount of surfactant available to stabilize the gas-liquid interfaces is fixed as fresh surfactant solution is not injected together with the gas phase. This work studies foam formation during the drainage of a surfactant solution by gas injection at a fixed flow rate. A transparent microfluidic model of a porous medium is used in order to enable the correlation of pore-scale phenomena and macroscopic flow behavior. The results show that the maximum number of lamellae increases with surfactant concentration, even much above the critical micelle concentration (CMC). The availability of surfactant molecules needed to stabilize newly formed gas-liquid interfaces rises with concentration. The higher number of lamellae formed at higher surfactant concentration leads to stronger mobility reduction of the gas phase and longer time needed for the gas to percolate through the porous medium.

A new insight on relative permeability modifier as conformance control in carbonate reservoir

The primary issue of high-water cuts in exploiting carbonate fields poses significant challenges and requires an immediate solution. The approach to tackle the root cause of this problem is reservoir conformance control. Conventional conformance control treatments, such as polymer-based materials, are ineffective and incompatible with the unique properties of carbonate reservoirs. Textural heterogeneity in carbonate leads to heterogeneity in the distribution of storage and flow properties that may govern changes in saturation patterns. The percolation of gas-water flow in carbonate highly depends on the pore structure. Conformance control refers to managing fluid movement within a reservoir to optimize production and reduce unwanted fluid production. The major challenge of water conformance control for carbonates using chemical treatment is the compatibility of the polymer system with the rock and fluid settings. This paper reviews current research on conformance control methods, including chemical and mechanical techniques. The effectiveness of various conformance control methods was evaluated based on their ability to improve sweep efficiency, reduce water production, and increase hydrocarbon recovery in different reservoir types. The review also discusses the challenges of implementing conformance control techniques, such as formation damage and fluid mobility issues. Overall, the paper concludes that successful implementation of conformance control strategies requires a thorough understanding of reservoir characteristics and planning to ensure optimal results. The findings of this study provide valuable insights into developing effective conformance control techniques that can improve hydrocarbon recovery and optimize reservoir performance. The results of this study provide critical insight into using efficient and operationally low-risk materials to reduce water cuts in the strong water drive carbonate reservoir.

Modeling Microscale Foam Propagation in a Heterogeneous Grain-Based Pore Network with the Pore-Filling Event Network Method

Foam flooding is an efficient and promising technology of enhanced oil recovery that significantly improves sweep efficiency of immiscible displacement processes by providing favorable mobility control on displacing fluids. Although the advantages in flexibility and efficiency are apparent, accurate prediction and effective control of foam flooding in field applications are still difficult to achieve due to the complexity in multiphase interactions. Also, conventional field-scale or mesoscale foam models are inadequate to simulate recent experimental findings in feasibility of foam injection in tight reservoirs. Microscale modeling of foam behavior has been applied to further connect those pore-scale interactions and mesoscale multiphase properties such as foam texture and the relative permeability of foam banks. Modification on a microscale foam model based on a pore-filling event network method is proposed to simulate its propagation in grain-based pore networks with varying degrees of heterogeneity. The impacts of foam injection strategy and oil-weakening phenomena are successfully incorporated. Corresponding microfluidic experiments are performed to validate the simulation results in dynamic displacement pattern as well as interfacial configuration. The proposed modeling method of foam propagation in grain-based networks successfully captures the effects of lamellae configurations corresponding to various foaming processes. The results of the simulation suggest that the wettability of rock has an impact on the relevance between reservoir heterogeneity and the formation of immobile foam banks, which supports the core idea of the recently proposed foam injection strategy in tight oil reservoirs with severe heterogeneity, that of focusing more on the IFT adjustment ability of foam, instead of arbitrarily pursuing high-quality strong foam restricted by permeability constraints.

Flood Management: Solving Conformance or Sweep Efficiency Problems—Part 4: Solution Performance Analysis

The first three articles in this series have discussed problem identification, problem understanding; solution design, execution, and performance; and benefit methods and techniques that should help in our efforts to improve the solution success rate, but we still have further improvements to make. Part 4 provides an overview of ongoing research and recent technology improvements focused on improving sweep efficiency or conformance solutions taking place in both academia and the service industry within the US. This article does not review efforts taking place inside oil production companies or national oil companies as that work is generally not publicized until completed. Before we start this review, let’s capture some thoughts that were expressed by several department chairs and other leaders in the industry. There is a common feeling that the level of research activity on all conventional oilfield recovery problems has suffered from a change in interest and funding over the past 10 to 15 years. Research on conformance or sweep efficiency problems is a subset of conventional oilfield recovery issues and thus has also suffered from this reduced interest. Instead, a significant rise of unconventional oilfield recovery needs and focus on greenhouse gases (GHG), carbon footprint, and the energy industry transition has shifted the priorities at many universities, governments, and service providers. This shift in efforts has resulted in a significant redistribution of resources that were once focused on conventional oilfield recovery issues. The number and types of conventional oilfield recovery problems has not changed; if anything, they continue to grow, but the addition of unconventional resources and their unique character, along with the push for studies on GHG, carbon footprint, and energy transition without a corresponding increase in funding and manpower has diluted our ability to respond as an industry to these needs. This perspective is offered as a simple observation of conditions that exist in the energy research arena. No judgment is made on the appropriateness of this change or the overall situation. Simply be aware that as an industry we have many challenges to face in the future and some will suffer as others are prioritized. As a result of this and some other reasons, several universities such as Colorado School of Mines, Louisiana State University, Penn State, Stanford University, University of Houston, University of Southern California, The University of Tulsa, and University of Wyoming are not reporting any active or current efforts on conventional asset sweep efficiency or conformance solution research. This does not mean that all interest in these technologies has been lost, only that no current research activities are underway. This is unfortunate, but I believe it is representative of this industry shift. Now, back to the primary focus of this article.

A novel foam process with CO2 dissolved surfactant for improved sweep efficiency in EVGSAU field

A successful CO2-foam gas conformance enhancement technology pilot has operated at the East Vacuum Grayburg San Andres Unit (EVGSAU) since Jan 2018 by ConocoPhillips in cooperation with Dow. In early 2020, the scope of the pilot was expanded from one pattern to three patterns. The expansion phase was implemented to evaluate scalability of this technology to patterns with diverse conformance issues and productivity inefficiencies. Severe vertical and areal conformance issues were initially identified in these patterns, resulting in early gas breakthroughs and poor oil sweep efficiencies. Due to economic success of the first phase, the same surfactant with high foaming tendencies, high gas solubility, and low adsorption characteristics was implemented in the new patterns.The first phase of foam implementation on an inverted pattern showed a complete elimination of out-of-zone injection, redistribution of CO2 into previously un-swept flow intervals, and oil production uplift.In contrast to this first pattern, the gas injectivity was reduced by 20–50% after only two foam cycles in the new patterns. Based on injection profile logs (IPL), no out-of-zone injection was identified before the surfactant injection for the two new patterns, which can be the reason for such rapid injectivity responses. Similar to the first pattern, deep conformance corrections were confirmed as gas was redirected from highly connected producers to other producers within the new patterns. A lower surfactant dosage was applied to one of the new patterns to optimize chemical consumption, while sustaining the performance. The surfactant concentration was also reduced in the first pattern to study the effect of a lower dosage on a known performing pattern. During the foam implementation, the gas to water ratio (GWR) at the pattern injectors was increased to maintain the patterns at the baseline total fluid throughput. This adjustment resulted in more than a 50% reduction in water consumption and a 17% improvement in gas utilization. Overall, a sustainable increase in oil production rate (∼35% over the baseline for the last two years) was achieved in the three foam patterns. This robust solution of gas conformance enhancement required ∼2 lbs. of foaming material per barrel of incremental oil produced, which confirms economic success and commercial viability of the foam technology for a full field-scale implementation.The application of this foam technology has potential to extend the life of a mature asset like EVGSAU by arresting the historical decline in the oil production rate. Reduction in energy and water consumption per barrel of oil produced make the CO2-EOR process more sustainable and strengthen its potential in carbon capture, utilization and sequestration (CCUS) application.

A New 3D Mathematical Model for Simulating Nanofluid Flooding in a Porous Medium for Enhanced Oil Recovery.

Two-phase Darcy's law is a well-known mathematical model used in the petrochemical industry. It predicts the fluid flow in reservoirs and can be used to optimize oil production using recent technology. Indeed, various models have been proposed for predicting oil recovery using injected nanofluids (NFs). Among them, numerical modeling is attracting the attention of scientists and engineers owing to its ability to modify the thermophysical properties of NFs such as density, viscosity, and thermal conductivity. Herein, a new model for simulating NF injection into a 3D porous media for enhanced oil recovery (EOR) is investigated. This model has been developed for its ability to predict oil recovery across a wide range of temperatures and volume fractions (VFs). For the first time, the model can examine the changes and effects of thermophysical properties on the EOR process based on empirical correlations depending on two variables, VF and inlet temperature. The governing equations obtained from Darcy's law, mass conservation, concentration, and energy equations were numerically evaluated using a time-dependent finite-element method. The findings indicated that optimizing the temperature and VF could significantly improve the thermophysical properties of the EOR process. We observed that increasing the inlet temperature (353.15 K) and volume fraction (4%) resulted in better oil displacement, improved sweep efficiency, and enhanced mobility of the NF. The oil recovery decreased when the VF (>4%) and temperature exceeded 353.15 K. Remarkably, the optimal VF and inlet temperature for changing the thermophysical properties increased the oil production by 30%.

Experimental studies on effectiveness of graphene oxide nanosheets dispersion in water/aqueous PHPA for enhanced oil recovery

Nanoparticle application in enhanced oil recovery is emerging as a novel technology because of their unique characteristics, viz. reduction of IFT, wettability alteration, and stable dispersion in injection water and aqueous polymer solution. In the present study, graphene oxide nanosheets (GONs) are synthesized by modified Hummer's method. The nanosheets are characterized by FTIR, XRD and UV–vis spectroscopy analysis. The size of the nanosheets was confirmed by the AFM and HR-TEM imaging. The stability of nanofluid (NF) with dispersed GONs in the aqueous solution was confirmed by Turbiscan stability analysis, DLS studies and zeta-potential values (less than −34 mV). The experimental research reveals that NF alters the wettability of intermediate oil-wet sandstone reservoir rock with a reduction of contact angle from 112.4° to 17.2°. Further, it is observed that the IFT between oil (decane) and deionized water decreases from 42.34 mN/m to 32.76 mN/m for the NF system. It has been observed that the synthesized GONs can emulsify crude oil, which is also an important mechanism of EOR. The rheological studies show that GONs enhance the viscosity and viscoelastic properties of partially hydrolyzed polyacrylamide (PHPA) polymer. GONs form a robust three-dimensional network structure facilitated by hydrogen bonding with the PHPA polymer chain, which leads to the improvement of sweep efficiency. The core flooding experiment demonstrates that the incremental oil recovery over the conventional water flooding by GONs dispersed in the PHPA polymer with flooding is significantly higher (26% of original oil in place) than that of individual NF and polymer flooding.

Water alternative gas (WAG) optimization for a heterogeneous Brazilian pre-salt carbonate reservoir

Abstract Water alternating gas (WAG) is a cyclical process that involves alternating water and gas injections with the primary goal to improve sweep efficiency by maintaining initial high pressure, slowing water and gas breakthrough, and lowering oil viscosity. The objective of this work is to apply and optimize a WAG strategy on a carbonate field with light oil, compare it to the initially planned water-flooding strategy, and investigate the capability of WAG to improve field production. In this research, a compositional reservoir simulator was used to model a WAG process by injecting produced gas into the reservoir, using the same well structure as an optimized water-flooding strategy. Subsequently, a WAG strategy was created, optimizing the number and locations of wells, to facilitate a comparative analysis of the two recovery methods. The WAG optimization involved a detailed assessment of variables such as bottom hole pressure (BHP), WAG cycle duration, maximum gas oil ratio (GOR), and well positioning, to achieve a high net present value (NPV). The study focuses on the application of WAG optimization modeling in unconventional reservoirs, specifically pre-salt carbonate reservoirs, and investigates its implications on production strategy and forecast, emphasizing its potential for maximizing NPV and oil recovery in a recently producing field. The results showed that WAG improved reservoir performance when compared to water injection and produced a greater amount of oil. This solution showed potential to be tested under uncertainties (reservoir heterogeneity, faults, fractures, karsts, vugs, etc.) as future steps.

Research and simulation study of different technological processes of miscible CO2 water alternating gas injection

One of the most commonly used methods for EOR in recent years is the water-alternating-gas (WAG) method, WAG injection is an oil recovery method aiming to improve displacement ratio, sweep efficiency and adjust the alignment of displacement in different layers to improve oil recovery and pressure maintenance. The main mechanism of it is 1) bettering the mobility control, 2) improvement of sweep efficiency (comparing to gas methods) and 3) the displacement efficiency (comparing to waterflooding). Many studies have been done in the past, but due to the increasing hard-to-recover field and facing difficulties during the production, the traditional WAG is facing problems that need to be coupled with. Implementation of new combinational methods and changes in the injection process to meet the needs have been developed during the last two decades. In this study, a simulation investigation has been done to compare proposed changes in the injection process to find the optimal injection scheme for the high heterogeneity - low permeability field. After analyzing the output of the simulation, the results show that each of the technologies has its advantages and disadvantages, and need to be applied according to the field constraints and requirement. Keywords: water alternating gas (WAG); enhanced oil recovery; reservoir simulation; injection scheme; heterogeneity; permeability.