Polymer Injection Wells Research Articles

Study and Practice of stabilized injection technologies in injection well life cycle

The technologies to steady pressure and injection rate and that to reduce pressure and increase injection rate are along with multiple stages of secondary and tertiary oil recovery. The ongoing injection process will subject most wells to pressure rise, reduced injection volume, fouling and plugging of reservoir, and corrosion of tubing string. In this paper, a portfolio of feasible measures can be provided for the steady injection in injection well life cycle by taking a closer look at cleaning & anti-swelling & anti-migrating technology, interlayer pressure influence balancing technology, slow releasing solid acid unpowered acidizing technology, low damage & low reaction rate acidizing technology, and degrading & acidizing technology for polymer injection wells.

Fuzzy-ball fluid self-selective profile control for enhanced oil recovery in heterogeneous reservoirs: The techniques and the mechanisms

Conventional water flooding and polymer flooding are common approaches to improve oil recovery. However, flooding agents injected into heterogeneous reservoirs preferentially enter the seepage channels in high-permeability zones. As a result, it is difficult to displace the hydrocarbons in low-permeability areas. Therefore, using the agents with selective plugging capability to block the high-permeability channels and promote the subsequent displacement in the low-permeability area has become a potentially preferable solution for enhanced oil recovery (EOR) in heterogeneous reservoirs. In this study, the techniques and mechanisms of the novel fuzzy-ball fluid for enhancing oil recovery in heterogeneous reservoirs are discussed. Laboratory tests were conducted using 45 mm × 45 mm × 300 mm artificial cores with permeability ranging from 200 to 1200 mD to simulate the formation channels. Two cores with different permeabilities were connected in parallel to simulate the heterogeneous formations. The oil displacement performance of fuzzy-ball fluid was compared with that of polymer and surfactant fluids. Flooding the cores with fuzzy-ball fluid could significantly increase the oil recovery rate of the low-permeability cores. Field tests were conducted in two polymer injection wells located in a heterogeneous conglomerate reservoir in Karamay Oilfield, China. After fuzzy-ball fluid flooding, the average daily liquid production rate decreased, the average daily oil production rate increased and the overall water content decreased. There was a significant improvement in oil displacement effect in low-permeability areas.

Study and application of a new blockage remover in polymer injection wells

Abstract With the extensive application of polymer flooding technology in offshore oilfields, the plugging in polymer injection wells has become more and more severe, which seriously affects the oil displacement effect and regular production of oilfields. In this paper, a new kind of blockage remover has been developed and evaluated by rheological behavior experiments, dissolution experiments and core flooding experiments. The results reveal that this new blockage remover can effectively reduce the viscosity of polymer and completely degrade the reservoir blockage with low corrosion rate. It is beneficial to long-term production of oil wells in offshore oilfield. Results of core flooding experiments show that this new blockage remover can relieve polymer damage and improve permeability. The agent has been applied in LD10-1 oilfield in 2016, the daily injection rate increased significantly after stimulation.

The Effect of Polymer Rheology and Induced Fracturing on Injectivity and Pressure-Transient Behavior

Summary Polymer transport and fluid rheology were implemented in a fully implicit hydraulic-fracturing and reservoir simulator. For flow in the matrix, a fluid-rheology function was used with shear thickening at high shear rates and shear thinning at medium and low shear rates. For flow in fractures, a shear-thinning constitutive law with a zero shear-rate plateau was used. The average viscosity in each fracture element was calculated by assuming smooth and parallel fracture walls and numerically solving for the velocity, shear rate, and viscosity distribution across the aperture. The simulator was used to investigate the effect on injectivity of shear thickening at high shear rates near the wellbore. For comparison, simulations were performed by use of the full shear-thickening and shear-thinning rheology function and by use of a shear-thinning-only rheology function. In the former case, the shear thickening caused rapid buildup of fluid pressure and the creation of a hydraulic fracture at the wellbore. Once the fracture formed, shear thickening no longer occurred because there was lower Darcy velocity in the matrix caused by lower concentration of flow at the wellbore. As a result, after the formation of the hydraulic fracture, injectivity in the simulation with shear thickening and thinning was nearly identical to that in the simulation with only shear thinning. The simulations were repeated with the constraint that a hydraulic fracture was not permitted to form. In this case, the simulation with shear thickening had a significantly lower injectivity than the simulation with shear thinning only. This result shows that formation of an induced fracture is a plausible explanation for unexpectedly high injectivity during polymer injection because it prevents shear thickening caused by high flow rate because of concentration of flow at the wellbore. Simulations were performed to investigate the effect of polymer rheology on the pressure transients occurring after shut-in of an injection well. Shear thickening affected the shut-in transient only at very-early time. Shear thinning affected the entire duration of the transient, causing an increase in effective fluid viscosity as the Darcy velocity gradually decreased over time. Despite fluid-rheology effects, linear flow was clearly identifiable after shut-in in the simulations with hydraulic fractures. This result shows that hydraulic fractures around polymer-injection wells can be diagnosed in field data from the linear-flow regime in the shut-in transient, regardless of fluid-rheology effects.

Mechanistic Simulation of Polymer Injectivity in Field Tests

SummaryPolymer flooding is one of the most widely used chemical enhanced-oil-recovery (EOR) methods because of its simplicity and low cost. To achieve high oil recoveries, large quantities of polymer solution are often injected through a small wellbore. Sometimes, the economic success of the project is only feasible when injection rate is high for high-viscosity solution. However, injection of viscous polymer solutions has been a concern for the field application of polymer flooding.The pressure increase in polymer injectors can be attributed to (1) formation of an oil bank, (2) polymer rheology (shear-thickening behavior near wellbore), and (3) plugging of the reservoir pores by insoluble polymer molecules or suspended particles in the water.In this paper, a new model to history match field injection-rate/pressure data is proposed. The pertinent equations for deep-bed filtration and external-cake buildup in radial coordinates were coupled to the viscoelastic polymer rheology to capture important mechanisms. Radial coordinates were selected to minimize the velocity/shear-rate errors caused by gridblock size in the Cartesian coordinates.The filtration theory was used and the field data history matched successfully. Systematic simulations were performed, and the impact of adsorption (retention), shear thickening, deep-bed filtration, and external-cake formation was investigated to explain the well-injectivity behavior of polymer. The simulation results indicate that the gradual increase in bottomhole pressure (BHP) during early times is attributed to the shear-thickening rheology at high velocities experienced by viscoelastic hydrolyzed polyacrylamide (HPAM) polymers around the wellbore and the permeability reduction caused by polymer adsorption and internal filtration of undissolved polymer. However, the linear impedance during external-cake growth is responsible for the sharper increase in injection pressure at the later times.One can use the proposed model to calculate the injectivity of the polymer-injection wells, understand the contribution of different phenomena to the pressure rise in the wells, locate the plugging or damage that may be caused by polymer, and accordingly design the chemical stimulation if necessary.

The Technology Limits for Stratified Injection of Polymer Flooding

At present the development of Daqing Oilfield has entered the water pick-up period, and the polymer separate injection technology for the injection well is urgent needed. However, the difficulty of selecting well and lever for the separate injection of the injection well is relatively large due to the complexity of the Class II reservoir of geological conditions. So for The limits of technology of the geological features, the limits of technology injection of stratified polymer injection for the Class II reservoir provides a scientific basis for the development of oil fields.In this paper, taking Daqing Oilfield Sabei Development Zone as example, establish the mathematical model of polymer flooding. Determine the well and layer selection principles of layered polymer injection wells in the ClassIIreservoir timing. According to the current development situation, give the decrease in water content and the improvement value in recovery under a given measure.Through this paper, we have got production effect of layered polymer injection in the Class II reservoir of Sabei area and given quantified layered polymer injection technology limits.

Novel Four-Electrode Electromagnetic Flowmeter for the Measurement of Flow Rate in Polymer-Injection Wells

In this article, a novel four-electrode electromagnetic flowmeter (EMF) is proposed for flow rate measurement in polymer-injection wells. The ideal response model of the four-electrode EMF is established. In this model, the weight function and intensity of magnetic field are both derived, according to which numerical calculations are conducted. The calculation results show that in the annular area between the flowmeter and oil tubing, the weight function and magnetic field are both symmetrically distributed near the measurement electrodes and magnetic poles, respectively, and are rapidly attenuating along the radius direction. The potential difference is calculated for several kinds of flow velocity profiles in the annular area, and the calculation results show that the output of the four-electrode EMF is sensitive to the distribution of the flow profile. The experimental results obtained by using the multiphase flow loop facility show that when the four-electrode EMF is used in polymer solutions, the instrument constant of the four-electrode EMF differs from that used in tap water and remains unchanged with the concentration of the polymer solutions. The flow patterns of tap water and polymer solutions are various, leading to the change of the instrument constant of the four-electrode EMF. On-site experiments show that the four-electrode EMF is suitable for the polymer-injection wells developed in short durations. For the wells developed in long durations, the four-electrode EMF is limited because of the contamination, distortion, and corrosion of the oil tubing.

Effective Propagation of HPAM Solutions Through the Tambaredjo Reservoir During a Polymer Flood

Summary Two new methods were developed for anaerobically sampling polymer solutions from production wells in the Sarah Maria polymer-flood-pilot project in Suriname. Whereas previous methods indicated severe polymer degradation, the improved methods revealed that the polymer propagated intact more than 300 ft through the Tambaredjo formation. Our results may help explain the inconsistency between good production responses and highly degraded polymer observed in many past field projects. Analysis of produced salinity, polymer concentration, and viscosity indicated that the polymer banks retained low salinity and, therefore, high viscosity for much of the way through the Sarah Maria polymer-flood-pilot pattern. A strong shear-thickening rheology was observed for 1,000 ppm and 1,350 ppm hydrolyzed polyacrylamide (HPAM) solutions in porous media, even though the salinity was only 500 ppm total dissolved solids (TDS). Examination of injectivities revealed that these solutions were injected above the formation parting pressure in the Sarah Maria polymer-injection wells. Injectivity was insufficient until fractures were initiated hydraulically; however, the fractures propagated a distance of only approximately 20 ft and did not jeopardize sweep efficiency. In contrast, the short fractures greatly improved polymer injectivity and reduced concern about polymer mechanical degradation.

Injection Well Logging Using Viscous EOR Fluids

Summary A new tool has been developed that overcomes problems associated with logging injection wells in the presence of viscous fluids. The tool was evaluated in the laboratory and the field in water and polymer injection wells. Results indicate that the tool provides better information than conventional equipment. Special attention to log interpretation is required in zones where the flow pattern changes from turbulent to transition flow. A method is suggested to improve log interpretation that considers changes in flow regime.