Preformed Particle Gel-Enhanced Surfactant Imbibition for Improving Oil Recovery in Fractured Carbonate Reservoirs

Oil recovery from naturally fractured carbonate reservoirs has always been a challenging task because of two inherent features, (1) Fracture networks which aggravate the effectiveness of water or chemical flooding and (2) Oil-wet matrix which limits the capillary imbibition process that governs the recovery in the fractured reservoirs. To overcome these challenges, we propose a technique that combines two existing enhance oil recovery (EOR) methods. Millimeter-sized preformed particle gels (PPGs) treatment along with surfactant imbibition. This coupled method can improve the imbibition process by providing fast transport mechanism for the surfactant to the oil-wet matrix which will accelerates the recovery rate. The coupled injection of PPGs and surfactant will result in a higher injection pressure gradient in the reservoir because of the high flow resistance resulting from the gel particles. Which will generate an additional force to divert surfactant into the matrix area thus forced imbibition can be realized. The combination of PPG treatment and surfactant imbibition can be a viable EOR process that will provide more cost-effective method for improving oil recovery while reducing water production in naturally fractured reservoirs if the PPG and surfactant were chosen appropriately

Investigate the Rheological Behavior of High Viscosity Friction Reducer Fracture Fluid and its Impact on Proppant Static Settling Velocity

The recent and rapid success of using high viscosity friction reducers (HVFRs) in hydraulic fracturing treatments is due to several advantages over other fracture fluids (e.g. linear gel), which include better proppant carrying capability, induce more complex fracture system network with higher fracture length, and overall lower costs due to fewer chemicals and less equipment on location. However, some concerns remain, like how HVFRs rheological properties can have impact on proppant transport into fractures. The objective of this study is to provide a comprehensive understanding of the influence the rheological characterization of HVFRs have on proppant static settling velocity within hydraulic fracturing process. To address these concerns, comprehensive rheological tests including viscosity profile, elasticity profile, and thermal stability were conducted for both HVFR and linear gel. In the steady shear-viscosity measurement, viscosity behavior versus a wide range of shear rates was studied. Moreover, the influence of elasticity was examined by performing oscillatory-shear tests over the range of frequencies. Normal stress was the other elasticity factor examined to evaluate elastic properties. Also, the Weissenberg number was calculated to determine the elastic to viscous forces. Lastly, quantitative and qualitative measurements were carried out to study proppant settling velocity in the fluids made from HVFRs and linear gel. The results of rheological measurement reveal that a lower concentration of HVFR-2 loading at 2gpt has approximately more than 8 times the viscosity of linear gel loading at 20ppt. Elastic measurement exposes that generally HVFRs have a much higher relaxation time compared to linear gel. Interestingly, the normal stress N1 of HVFR-2, 2gpt was over 3 times that of linear gel loading 20ppt. This could conclude that linear gel fracture fluids have weak elastic characterization compared to HVFR. The results also concluded that at 80 C° linear gel has a weak thermal stability while HVFR-2 loses its properties only slightly with increasing temperature. HVFR-2 showed better proppant settling velocity relative to guar-based fluids. The reduction on proppant settling velocity exceed 75% when HVFR-2 loading at 2gpt was used compared to 20ppt of linear gel. Even though much work was performed to understand the proppant settling velocity, not much experimental work has investigated the HVFR behavior on the static proppant settling velocity measurements. This paper will provide a better understanding of the distinct changes of the mechanical characterization on the HVFRs which could be used as guidance for fracture engineers to design and select better high viscous friction reducers

Hydrochloric Acid Applications to Improve Particle Gel Conformance Control Treatment

Millimeter-sized (10 μm~mm) particle gels have been used widely to control water flow through super-high-permeability zones and fracture zones in mature oil fields. During particle gel extrusion into target zones, the gel can form a cake on the surface of low-permeability, unswept formations. This cake reduces the effectiveness of conformance control as well as the amount of oil that can be recovered from unswept oil formations. Thus, we evaluated the effectiveness of using hydrochloric acid (HCL) to remove gel cakes induced during conformance-control treatments. The interactions between HCL and particle gels were evaluated to understand the swelling, deswelling, and the gel strength after adding acid. A Hassler core holder was then used to determine the core permeability after gel and acid treatments. Gels swollen in brine concentrations of 0.05%, 1%, and 10% were injected into a sandstone core having a variety of permeabilities. Brine was then injected in cycles through the gel into the core. The core permeability was measured after gel particle injection and after the core surface with the gel cake was soaked in the acid solution for 12 hr. The results indicate that particles swollen in brine concentrations of 0.05% caused more damage than those swollen in higher concentrations of brine. The damage increased as the core permeability increased for all the swollen gels. The results also show that HCL removed the gel cake effectively, and varying HCL concentrations did not exhibit a significant difference in the gel cake-removal efficiency. The gel was found to swell much less in HCL solutions than in brine. After it was deswollen in acid, the gel strengths were measured and found to be higher than those swollen in brine. This work concludes that HCL can be used effectively to mitigate the damage induced by particle gels

Increasing Production Flow Rate and overall Recovery from Gas Hydrate Reservoirs using a Combined Steam Flooding-Thermodynamic Inhibitor Technique

When producing from gas hydrate reservoirs using steam flooding, since hydrate dissociation is an endothermic reaction, the heat is used up. This results in a decrease in reservoir temperature which causes the hydrate equilibrium conditions to be established again, thus causing hydrate reformation. This research studies the effect of injecting thermodynamic inhibitors during steam injection on overcoming the problem of hydrate reformation which in turn will increase hydrocarbon recovery significantly from hydrate reservoirs. The reservoir model was built based on data collected from previous models found in the literature. After specifying all parameters for the reservoir, and the hydrate layer, a systematic study was performed in order to assess the use of inhibitors with steam flooding. The production methods studied include depressurization, steam flooding, inhibitor injection including both brine and glycol, and finally the combined steam flooding inhibitor injection method. The conditions for the steam flooding were kept the same during all runs in order to be able to compare them. Results indicated that the use of the thermal stimulation alone without inhibitor managed to increase recovery, however, the problem of hydrate reformation occurred which caused a cessation of production. Using inhibitors alone managed to increase recovery as well, however the recovery increase was much less compared to thermal stimulation. The type of inhibitor also played a role in recovery with the glycol producing the most, followed by the brine. By combining both steam flooding and inhibitor injection, the recovery increased significantly more than what was observed when using each of the methods on its own. To the authors\u27 knowledge, no extensive study has been performed by combining both steam flooding and inhibitor to increase hydrocarbon recovery from hydrate reservoirs. This research can help in improving real field gas hydrate projects by making the overall project much more economic by increasing hydrocarbon recovery

Use of Hydrochloric Acid to Remove Filter-Cake Damage from Preformed Particle Gel during Conformance-Control Treatments

Millimeter-sized (10-mm to mm) preformed particle gel (PPG) has been used to control water flow through superhigh-permeability zones and fracture zones in mature oil fields. When the PPG is extruded into target zones, the gel can form a cake on the surface of low-permeability, unswept formations. This cake reduces the effectiveness of conformance control and the amount of oil that can be recovered from unswept oil formations. Thus, this study evaluated the effectiveness of using hydrochloric acid (HCl) to remove gel cakes induced during conformance-control treatments. The interactions between HCl and PPG were evaluated to understand the swelling, deswelling, and gel strength after adding acid. A Hassler core holder was then used to determine the core permeability after gel and acid treatments. Gels swollen in brine concentrations of 0.05, 1, and 10% were injected into a sandstone core having a variety of permeabilities. Brine was then injected in cycles through the gel into the core. The core permeability was measured after the gel-particle injection and after the core surface of the gel cake was soaked in the acid solution for 12 hours. The results indicate that particles swollen in brine concentrations of 0.05% caused more damage than those swollen in higher concentrations of brine. The damage increased as the core permeability increased for all the swollen gels. HCl removed the gel cake effectively; varying the HCl concentration did not cause a significant difference in the gel-cake removal efficiency. The gel was found to swell much less in HCl solutions than in brine. After the gel was deswollen in acid, the gel strengths were found to be higher than when the gel was swollen in brine. This work concludes that HCl can be used effectively to mitigate the damage induced by PPGs

Laboratory Screening Tests to Further Characterize Low-Salinity Waterflooding in Low-Permeability Sandstone Reservoir

The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The objective of this study was to test the ability of low-salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, interfacial, core flooding, and zeta potential tests. Three key factors were studied: salinity of the injected water, type of salt, and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. Berea sandstone was used in all experiments. Sodium chloride (NaCl) and calcium chloride (CaCl2) were used to prepare the brine. The imbibition test and core flooding results showed that the oil recovery increased as brine concentration decreased for both sodium chloride and calcium chloride. Sodium chloride resulted in higher oil recovery than calcium chloride at a certain salinity in both imbibition and core flooding tests. The oil recovery factor results during the second water flooding cycle (after aging for 24 hrs.) showed more oil recovered during low salinity waterflooding. The stabilized inaction pressure was higher for CaCl2 than NaCl injection at certain flow rate and brine concentrations. Effluent pH values became more basic during low salinity water flooding for both sodium and calcium chloride. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 hours. Results also imply Low-salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency

Reducing Excessive Water Production Associated with Gas Hydrate Reservoirs using a Thermal In-Situ Heating-Inhibitor Method

Gas hydrates are one of the most abundant sources of energy present today. They are formed at high pressures and low temperatures, and contain mainly water and methane. When dissociated, a large volume of water forms, much of which is produced. This research performs a simulation study on how to decrease the volume of water produced from gas hydrate reservoirs by utilizing an in-situ heating method combined with a low concentration thermodynamic inhibitor injection. Since gas hydrates form at high pressures and low temperatures, depressurizing the reservoir, or increasing its temperature would cause the solid hydrates to become unstable, and dissociate. The research begins by building a hydrate reservoir model using almost the same description of the models present in the literature in order to compare the results obtained. Several simulation runs were then performed using various production methods, several types of inhibitors, and finally testing and optimizing the newly proposed production method which combines thermal stimulation with inhibitor injection. The optimization process involves testing the novel method using 5-spot, 7-spot, and 9-spot production methods. The effect of each variable on the water recovery was studied, and the conditions under which the lowest water recovery were obtained. The highest water production occurred during glycol injection since it had the largest endurance to hydrate reformation and thus the largest water flow duration. When the glycol was combined with the thermal stimulation method however, the lowest water recovery was obtained. This is mainly due to two factors which include high rate of depletion of reservoir pressure, and the significant decrease in glycol concentration when used with thermal stimulation. This novel production method was chosen as the best method in terms of low water recovery based on a comparison of its recovery with that of all the other methods. The second task was to further optimize this method by introducing several well patterns and comparing their performance to that of the single well case. The largest number of wells, 9-spot pattern, was found to have the lowest water recovery due to the extremely high rate of reservoir pressure depletion. Gas hydrate production is still considered in its preliminary steps due to the complexity of hydrate reservoirs. By understating the mechanism by which these reservoirs can flow, and trying to reduce the excessive water production associated with these reservoirs a better understating of how to economically and safely produce from gas hydrate reservoirs is reached. This may lead to the utilization of this source of energy in the near future

Improve Plugging Efficiency in Fractured Sandstone Reservoirs by Mixing Different Preformed Particles Gel Size

The oil recovery from fractured reservoirs is usually low, which is usually caused by the existence of areal formation heterogeneity. Preformed particle gel PPG has been used successfully use to reduce Heterogeneity and improve sweep efficiency. Low salinity waterflooding (LSWF) was recognized by the oil industry to increase displacement efficiency. The main objective of this study is to test the effectiveness of coupling these two technologies to increase oil recovery. Additionally, this study will determine the optimum PPG size to use with LSW to improve conformance control in the fractured sandstone cores. Semi-transparent five-spot model made of sandstone cores and acrylic plates were built to visualize the sweep efficiency from the coupled methods. Sandstone cores were saturated by 1.0% NaCl and then light oil was injected to simulate initial water saturation before the fracture was made. Brine at different salinities was injected initially into the fracture model to determine oil recovery. PPG with different sizes was injected later to reduce the fracture conductivity and increase sweep efficiency. Brine was injected again after gel treatment to determine the oil recovery improve after the gel injection. Laboratory experiments showed that the oil recovery factor and the water residual resistance factor (Frrw) increased when the low-salinity water was used for injection. However, the PPG extruded pressure decreased when the PPG swelled in a low-salinity water. Additionally, mixing different PPG size resulted in higher plugging efficiency than uniform PPG size and Frrw decreased as increased flow rate. Combining two different preformed particle gel sizes can improve plugging efficiency and, in turn, improve sweep efficiency and enhance conformance control

Static Proppant Settling Velocity Characteristics in High Viscosity Friction Reducers Fluids for Unconfined and Confined Fractures

Measuring proppant settling velocity in high viscosity friction reducers (HVFRs) plays a critical key for evaluating proppant transport in hydraulic fracture treatment. Settling of particles is governed by several factors such as fluid rheology (viscosity and elasticity), proppant size, retardation confining walls effect, and fracture orientation. The objective of this experimental study was to determine how these factors would influence particle settling velocity in hydraulic fracturing applications. The experiments were conducted in unconfined and confined fluid conditions. Fracture cell was designed in certain ways to capture the impact of fracture orientation by 45°, 60°, and 90° on settling velocity. Results showed HVFR provided better proppant transport capability than regular FRs used in slickwater. Proppant settling velocity using HVFR was decreased by 80%. Results obtained from confined fluid experiments showed that proppant settling velocity decreased due to the confining walls exert retardation impact. The wall retardation was also reduced as the fracture width increased. Changing fracture orientation from vertical position (90 degree) to 45 degree led to high reduction in proppant settling velocity

Computational Fluid Dynamics (CFD) Modeling of Proppant Static Settling Velocity in High Viscosity Friction Reducers

In the current petroleum fracturing industry, it is necessary to understand the down-hole migration and settling velocity of the proppant. If we can master this information well, it will be a great help to obtain effective propped fracture conductivity. In order to study the transport of proppants in the well, we used laboratory experiments and computer numerical simulations to compare the results to get a meaningful conclusion. We spent a lot of time building models on a powerful computer and comparing the experimental conclusions. We finally decided to use CFD as the simulation platform, DPM as the base model, and compare the simulation data with settling velocity experiment data to draw conclusions. Three cases were run and tested including fracture fluid type, proppant size, and fracture orientations. Results show a good integration between experimental results and simulation outputs. This paper will help to provide a full understanding of the distinct changes of the mechanical characterization on the High Viscosity Friction Reducers (HVFRs). The findings provide an in-depth understanding of the behavior of HVFRs under confined effect, which could be used as guidance for fracture engineers to design and select better HVFR design