Non-Steady-State Coupled Model of Viscosity–Temperature–Pressure in Polymer Flooding Injection Wellbores

On the basis of results from a substantial number of field projects, polymer flooding has been found to be successful over broad ranges of polymer flooding has been found to be successful over broad ranges of reservoir conditions and fluid characteristics. But it is a complicated process to design a polymer flooding program, and the many variables process to design a polymer flooding program, and the many variables involved require sophisticated calculations that are best handled with a computer. Introduction Papers by Pye and Sandiford in 1964 established Papers by Pye and Sandiford in 1964 established the fact that the mobility of the brine used in waterflooding was greatly reduced by the addition of very small amounts of hydrolyzed polyacrylamide, a water-soluble polymer. This reduction in brine mobility resulted in greater oil recovery than that attributable to conventional waterflooding. Many additional papers sustaining and extending this information have since appeared in the literature. To date, very little field information has been available from which to draw conclusions regarding the most suitable reservoir and fluid characteristics for polymer flooding applications. The purpose of this polymer flooding applications. The purpose of this paper is to present basic conditions and test results paper is to present basic conditions and test results for a large number of polymer flood projects and to examine the ranges of some of the more important parameters within which success has been achieved. parameters within which success has been achieved. In addition, the effects of variations in several important reservoir and polymer properties upon polymer flood recovery are illustrated with the aid polymer flood recovery are illustrated with the aid of a computer program. Such effects are not readily observable by field testing. Field Test Results Tables 1 and 2 list reservoir and fluid properties for 61 polymer flood projects begun between 1964 and mid-1969. All projects with which we or our colleagues have been associated are included. We believe that the polymer used in these 61 projects represents more than 95 percent of all the polymer injected to date as a mobility control agent in flooding. Although the individual projects vary greatly in size, the combined amount of polymer used amounts to several million pounds under commercial rather than purely experimental conditions. Specifically excluded from these tables are those projects employing polymers on a small-volume, short-term basis for injection profile correction, and projects where polymer solutions profile correction, and projects where polymer solutions are used to displace miscible fluids. Also excluded are previously reported research pilot tests. previously reported research pilot tests. Table 1 lists 29 projects from which significant information concerning the applicability of the polymer flooding process can be obtained. Table 2 lists polymer flooding process can be obtained. Table 2 lists 32 additional projects from which such conclusions cannot be drawn either because of some gross reservoir defect rendering the reservoir unsuitable for any displacement process or because the project was started too recently to be interpreted. In each table, most of the more important reservoir and fluid characteristics are listed together with the recommended polymer flood plan. The sequence in which the polymer flood plan. The sequence in which the projects are listed is determined by the stage of projects are listed is determined by the stage of depletion (Column 14) at which the project was begun that is, P indicates a start near the end of primary; ES, early secondary; LS, late secondary; and T, tertiary. Test results are indicated in Column 20 and are defined both in the footnotes of each table and in the following paragraph. JPT P. 675

Summary Polymer flood applications in offshore fields face more challenges than that of onshore fields. These challenges include limited platform space, costs to transfer polymer chemical, short service life, large well spacing, reduced polymer viscosity when mixed with sea water, and lack of analogs of practical polymer flood projects implemented in offshore. The above challenges make it's hard to directly apply the onshore polymer flood technologies and experiences proved successful. Taking five offshore viscous oil polymer flood projects as examples, this paper summarizes their implementation, production performance, reservoir management and lessons learned during pilot or field-wide polymer flood process. These projects cover cases in both shallow and dep water, and polymer flood beginning at early, interim, and mature development stages with water-cut 60%, respectively. Targets of these projects are all high-quality sandstone reservoirs with oil viscosity at reservoir condition varying from 11 to 88 cP. These projects were implemented in phase from single well injectivity test, pilot, to field, achieving an incremental recovery from 4% to 7%. For the mature field cases, water-cut performance is characterized by typical funnel-shape, experiencing process of decreasing, stabilizing at low, then back to the high level. This corresponds to oil rate changes of the increasing, maintaining at a high, and then drop to low rate production. For the case of polymer flood starting at early development stage, the funnel-shape will never occur. Instead, water-cut rises sustainably, while its increasing trend is obviously arrested. Effective polymer flood process shows increased injection pressure and resistance factor, dropped water-intake index and improved injecting profile. Production responses to polymer injection is generally earlier than polymer breakthrough timing with average responding duration of 2.6 years comparing with that of average polymer breakthrough of 4.8 years in specific cases. Lessons learned are: (1) early polymer flood could be a strategy for offshore field, which recovers oil in short time, saves the cost of production fluid processing as well as achieves relatively higher recovery factor; (2) mechanic degradation at the near wellbore is the main source of polymer degradation due to permeability impairment caused by poor quality produced water injection. Rather than the most popular HPAM, the salinity and shearing resistance polymer such as hydrophobic associated polymer is a better solution; (3) effective reservoir management such as zonal polymer solution injection and gel plus polymer flood injection benefits for improving polymer flooding.

Study of the inflow performance relationship of oil wells for polymer flooding reservoirs is the basis of the analysis of oil well production behaviors, design of production equipment and management of production system. During the polymer flooding, the produced fluid that contains the polymer solution in oil wells obviously shows characteristics of non-Newtonian fluid. Because of degradation, adsorption and retention effects, the rheology of the fluid in formation is various in the different places of the reservoir, so previous IPR equations can't be used to estimate accurately the inflow performance relationship of the oil well for polymer flooding reservoirs. Based on the principle of rheology and percolation flow through porous media, a group of differential equations that describe the flow behavior of the mixture of polymer solution and oil through the porous medium are set up. Based on the experiment results, the critical equivalent shear rate of fluid behaving viscoelasticity in porous media is analyzed. The model is solved for the power-law fluid and the viscoelastic fluid occurred simultaneously in the formation, i.e. a viscoelastic fluid in the very vicinity of wellbore and a power- law fluid in the back of formation, then the IPR curves are drawn. The effect of the changes of fluid rheological parameter on the shape of IPR curves of oil wells is analyzed. Using the data of Daqing oil field flow-after-flow test of one well in the polymer flooding reservoir, the IPR curves are drawn using the method presented in the paper. The flowing BHPs calculated are consistent with the actual measured data. The maximum absolute error is - 0.23MPa and the maximum relative error is 5.82%. Introduction After many years of field tests, it has been proved that polymer flooding is an EOR method with great developing potential in Daqing oil field. Up to now this technique has stepped into industrial application stage. There is no doubt that many new problems will be encountered in the course of producing crude oil mixed with polymer solution. The prediction of oil well IPR curves is one of the methods that solve these puzzles and key problems in polymer flooding technique. During water-flooding development phase, we generally treat the oil-water mixture as Newtonian fluid. However, during polymer flooding process, because the flow behavior and the transmission characteristic of polymer solution are restricted by its rheological properties when it flows through porous media, it makes the fluid properties much more complicated than that in water flooding. Since the end of 1960's, many foreign experts have studied the rheological properties of polymer solution systematically and deeply from the point of structural rheology and have established some constitutive equations which adapted to describe rheological characteristics of polymer solution, such as Cross, Meter, Carreau, Ellis, power-law models, etc. But, all of them are unsuitable to describe the percolation flow behavior of polymer solution through porous media, because the variation of the p parameters along flow direction and the elastic effect are not considered. Sampling analysis in the oil field shows that fluid produced from polymer flooding oil wells obviously appears to be non-Newtonian characteristic, and thus conventional methods of calculating IPR curves of oil wells can't be used in such wells. This paper considers the variation of rheological properties of fluid produced and its basic flow behavior for polymer flooding reservoirs on the basis of core displacement and rheological property experiments. The rheological properties of the in-situ fluid and its change rules along the flow direction have been determined and the critical equivalent shear rate is analyzed when in-situ fluid appears to be viscoelastic fluid. P. 969^

This paper provides an extensive review of the polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer flooding field activity. Reasons for the changes are discussed. Even with current floods, a broad range of polymer viscosities are injected—with substantial variations from a base-case design procedure. Extensive discussions with operators and designers of current polymer floods revealed substantial differences of opinion for the optimum design of polymer floods. This paper examines the validity of arguments that are commonly given to justify deviations from the base-case design. For applications involving viscous oils (e.g., 1000 cp), the designed polymer viscosities have sometimes been underestimated because of (1) insufficient water injection while determining relative permeabilities, (2) reliance on mobility ratios at a calculated shock front, and (3) over-estimation of polymer resistance factors and residual resistance factors. In homogeneous reservoirs, the ratio of produced oil value to injected fluid cost is fairly insensitive to injected polymer viscosity (up to the viscosity predicted by the base-case method), especially at low oil prices. However, reservoir heterogeneity and economics of scale associated with the polymer dissolution equipment favor high polymer viscosities over low polymer viscosities, if injectivity is not limiting. Injection above the formation parting pressure and fracture extension are crucial to achieving acceptable injectivity for many polymer floods—especially those using vertical injectors. Under the proper circumstances, this process can increase fluid injectivity, oil productivity, and reservoir sweep efficiency, and also reduce the risk of mechanical degradation for polyacrylamide solutions. The key is to understand the degree of fracture extension for a given set of injection conditions so that fractures do not extend out of the target zone or cause severe channeling. Many field cases exist with no evidence that fractures caused severe polymer channeling or breaching the reservoir seals, in spite of injection above the formation parting pressure. Although at least one case exists (Daqing) where injection of very viscous polymer solutions (i.e., more viscous than the base-case design) reduced Sor below that for waterflooding, our understanding of when and how this occurs is in its infancy. At this point, use of polymers to reduce Sor must be investigated experimentally on a case-by-case basis. A “one-size-fits-all” formula cannot be expected for the optimum bank size. However, experience and technical considerations favor using the largest practical polymer bank. Although graded banks are commonly used or planned in field applications, more work is needed to demonstrate their utility and to identify the most appropriate design procedure.

Influences of fracture orientation on oil recovery by water and polymer flooding processes: An experimental approach

Summary This paper provides an extensive review of the polymer concentrations, viscosities, and bank sizes used during existing and previous polymer floods. On average, these values have been substantially greater during the past 25 years than during the first 30 years of polymer-flooding field activity. Reasons for the changes are discussed. Even with current floods, a broad range of polymer viscosities are injected, with substantial variations from a base-case design procedure. Extensive discussions with operators and designers of current polymer floods revealed substantial differences of opinion for the optimum design of polymer floods. This paper examines the validity of arguments that are commonly given to justify deviations from the base-case design. For applications involving viscous oils (e.g., 1,000 cp), the designed polymer viscosities have sometimes been underestimated because of insufficient water injection while determining relative permeabilities; reliance on mobility ratios at a calculated shock front; and overestimation of polymer resistance factors and residual resistance factors. In homogeneous reservoirs, the ratio of produced-oil value to injected-fluid cost is fairly insensitive to injected-polymer viscosity (up to the viscosity predicted by the base-case method), especially at low oil prices. However, reservoir heterogeneity and economics of scale associated with the polymer-dissolution equipment favor high polymer viscosities over low polymer viscosities, if injectivity is not limiting. Injection above the formation-parting pressure and fracture extension are crucial to achieving acceptable injectivity for many polymer floods, especially those using vertical injectors. Under the proper circumstances, this process can increase fluid injectivity, oil productivity, and reservoir-sweep efficiency, and also reduce the risk of mechanical degradation for polyacrylamide solutions. The key is to understand the degree of fracture extension for a given set of injection conditions so that fractures do not extend out of the target zone or cause severe channeling. Many field cases exist with no evidence that fractures caused severe polymer channeling or breaching of the reservoir seals, in spite of injection above the formation-parting pressure. Although at least one case exists (Daqing, China) where injection of very-viscous polymer solutions (i.e., more viscous than the base-case design) reduced Sor to less than that for waterflooding, our understanding of when and how this occurs is in its infancy. At this point, use of polymers to reduce Sor must be investigated experimentally on a case-by-case basis. A “one-size-fits-all” formula cannot be expected for the optimum bank size. However, experience and technical considerations favor use of the largest practical polymer bank. Although graded banks are commonly used or planned in field applications, more work is needed to demonstrate their utility and to identify the most-appropriate design procedure.

Low salinity water flooding is getting much wider attention in the oil industry since it is highly cost-competitive compared to other conventional EOR methods. Water desalination and hardness removal are the keys to its success for effective oil recovery. However, conventional seawater desalination methods provide almost fresh waters that could be incompatible with resident reservoir clays and hence may not be suitable for direct injection into the reservoir. In this paper, we describe a novel "designer water" desalination scheme that is capable of providing the desired injection water composition to suit the specific formation. Thus, this process could potentially avoid clay-swelling, and at the same time mitigating other critical issues such as reservoir souring and unfavourable wettability modification to more oil-wet state. Selected examples are given to conceptually demonstrate how various water streams generated in the designer water process would help to move the injection water quality point away from the clay flocculation region for different reservoir clay types. Polymer flooding is another promising avenue for low salinity water applications. The use of low salinity water in polymer flooding processes considerably reduces the amount of dosing chemicals required to achieve a target polymer solution viscosity. This favourably impacts chemical procurement, transportation, storage, and handling (mixing and hydration) requirements and operating costs in offshore environments. The effect of injection water salinity on polymer concentration requirements is shown for different polymer solution viscosities. These data indicate about 5-10 times lower consumption of polymer in low salinity water when compared to seawater. As a result, a high-level facility engineering study was performed to assess the cost savings associated with low salinity water in offshore polymer flooding. The study results show that polymer flooding with low salinity water is economically more beneficial compared to seawater polymer flooding. It could be possible to pay out the incremental desalination costs within a 4-year project time frame due to the large savings associated with chemical costs and polymer facilities costs in low salinity polymer flooding. When the reservoir fits the criteria for low salinity flooding, then the additive effect of lower waterflood remaining oil saturation compounds with the benefit of polymer flood improved oil recovery due to better reservoir sweep. This means that low salinity water flooding can synergize well with polymer flooding to drive unit technical cost down and oil recoveries up.

Polymer flooding development tests stared from 1990’s were carried out on Daqing and Shengli oilfields in China, with water-flooding as its most important development measures formerly, which enlarged size scale of tests continuously. Stable production and enhancing recovery efficiency in these oilfields were implemented by polymer flooding technology. Successful field applications showed the yearly production rate reached to nearly 90 million bbl in Daqing oilfield. Feasible and effective report has not been provided yet on the problem that the range of recoverable reserves and recovery efficiency can be reached after polymer flooding. Considering most oilfields accomplished polymer flooding in quick succession and some oilfields were just developed by polymer flooding, practical resolution should be recommended such as the corresponding evaluation model for enhancing recovery efficiency range of polymer flooding. The resolution can also provide an evaluation basis of enhancing recovery efficiency for alkaline-surfactant-polymer flooding in future. This paper proposed an evaluation model for enhancing recovery reserves and recovery efficiency of polymer-flooding based on production decline model of reservoir engineering. Applications of these concepts are illustrated with field examples. Results indicated that recovery efficiency by polymer-flooding after the water-flooding development may be increased between 7% and 12% in Chinese oilfields. The evaluation model has been used effectively to predict EOR effect in Chinese oilfields.

The polymer flooding process has already been applied to the medium permeability type II reservoirs of the Daqing Oilfield (China) to enhance oil recovery. However, this process faces a number of challenges, such as the flooding efficiency, high injection pressure, formation blockage and damage, unbalanced absorption ratio, and economical justification. In this study, single-phase and two-phase flow experiments are performed to investigate polymer injection adaptability with natural cores of type II reservoirs. The enhanced oil recovery (EOR) effects of the polymer are studied by physical simulation experiments, and the results of application in an actual field are also presented. The results indicate that the flow characteristics and injection capability are dominated by the reservoir permeability in polymer flooding. Moreover, the adsorption of polymer molecules and the injection pressure gradient, which reflect formation damage, are affected more significantly by the concentration than by the molecular weight in type II reservoirs. Using the matching relationship, the injection-production process is stable, and additional oil recoveries of 10%–15% can be obtained in heterogeneous type II reservoirs with a high water saturation. This work is significant in that it further accelerates the application of polymer flooding EOR in medium permeability heterogeneous oilfields with high water saturation.

Summary: The success of polymer flooding as a method of oil recovery has been attributed to a profile control mechanism of the displacing fluid (polymer solutions) related to the displaced fluid (crude oil), depending on properties such as polymer viscosity and its dependence with reservoir and flow conditions. The viscosity of polymer flow depends not only on the size of the molecules or molecular weight but it is further affected by salinity and divalent content on the brine used for the preparation of the polymer slug. The effect of salinity on polymer viscosity is more critical in presence of divalent ions Ca2+ and Mg2+ and high salinity conditions, which limits the use high salinity produced water for re-injection in polymer flooding processes where high salinity is involved. A series of salinity resistant polymers have been developed by incorporating co-monomers including hydrophilic and hydrophobic groups or combination of them along the chain of polyacrylamide which has made the viscosity behavior more complex and affected by ionic interactions both intra-molecular and inter-molecular. Therefore, an extensively screening process that includes evaluation of variables such as: stability of polymer solutions under salinity and ion composition, flow conditions and sensitivity analysis using simulation according to specific applications, is required for the selection of any specific system. A systematic comparative study of the screening of commercial partial hydrolysed polyacrylamide (PHPA), and co-polymers of acrylamide and hydrophobic modified Comb-polymers (HMPAM) under high salinity conditions is investigated. Synthetic high salinity and multi-component (with divalent ions) produced water from a North Sea reservoir was used on Bernheimer sandstone core samples using a crude oil from the North Sea with specific gravity 21 oAPI. Results from core flooding and rheology were matched to obtain required mathematical correlations to simulate core flooding experiments numerically and compare the efficiency of the different polymers. While polymers PHPA and co-polymers AM-AMPS and AM-nVP showed typical Newtonian behavior at low shear rates and non- Newtonian at high shear rates, HMPAM polymers have shear thinning behavior. Newtonian behavior on PHPA-3 seems to support its higher recovery factor comparing with PHPA-6 (higher MW). Viscosity of HMPAM solutions is more sensitive to changes of the polymer concentration and more sensible to flow conditions. Additionally, ionic interactions and steric effects in the co-polymers contribute the efficiency of the oil recovery at high salinity. Therefore, their viscosity behavior needs to be evaluated.

A polymer flood process with partially hydrolized Polyacrylamide solution in fresh water has successfully been applied "by Deutsche Texaco AG in the oilfields of Hankensbuettel and Oerrel. The flood process is capable of recovering additional 10–15 % 00IP in high salinity reservoirs with temperatures of 60 °C and oil viscosity up to 20 mPa.s. This paper presents the case history of Oerrel West Block Polymer Flood and demonstrates the importance of comprehensive reservoir description by numerical simulation.

Identification and characterization of dominant seepage channels in oil reservoirs after polymer flooding based on streamline numerical simulation

Formation mechanism and location distribution of blockage during polymer flooding

This paper presents results from a series of single phase stable displacement experiments in a heterogeneous core assembly. This system consists of a 0.5 m cylindrical sandstone core with a central core removed and replaced with high permeability ballotini. Displacements at unit, 2:1 and 10:1 viscosity ratio were performed which demonstrated the importance of crossflow mechanisms in polymer flooding processes. The experiments were modelled using a curvilinear grid in a chemical flood simulator. All of the main features observed in these experiments were successfully reproduced and analysed in terms of viscous and dispersive crossflow effects. Some discussion is presented on the significance of crossflow at the reservoir scale.

Simulation study of polymer flooding performance: Effect of salinity, polymer concentration in the Malay Basin