Summary Recent displacement data conclusively show that the initial permeability reduction during in-situ gelation processes does not result from a bulk gelation of the injected fluid. This paper presents a filtration-based model that correctly accounts paper presents a filtration-based model that correctly accounts for all physical phenomena occurring during in-situ gelation displacements. Introduction Permeability modification treatments are used to improve waterflood Permeability modification treatments are used to improve waterflood sweep efficiency in mature waterfloods. These treatments consist of injecting a polymer solution combined with a crosslinking agent into a water-injection well. It is envisioned that the viscous gelling solution enter shigh-permeability, water-swept regions of the reservoir and plugs these channels, forcing subsequent water injection into regions of the reservoir that have not been swept by water. Previous investigators represented the in-situ permeability reduction mechanism as simple bulk gelation of the injection solution. However, displacement data show that flow resistance developed in sandpacks before the injected polymer solution could get in bulk. McCool and McCool et al. proposed that the initial permeability was reduced by filtration of Cr+3/polyacrylamide permeability was reduced by filtration ofCr+3/polyacrylamide aggregates from the gelling solution, well before a true" gel" could form. This paper presents a new numerical model based on the filtration hypothesis. The model consists of a mass-transport equation for10 species coupled with kinetic models of the gelation process and porousmedium and with filtration models from the process and porous medium and with filtration models from the literature. The model successfully matches Marty et al. five in-situ gelation displacements. Model formulation and simulation results are presented here. Background Permeability modification treatments for injection wells are Permeability modification treatments for injection wells are designed by choosing a treatment radius around the wellbore and calculating the volume of gelling solution required to displace the water saturated PV in this region. It is assumed that the gelling solution forms a bulk gel throughout this region after injection. Laboratory displacement data show that high flow resistance developed in sandpacks before the polymer solution could gel in bulk. Large pressure drops caused by this region of high flow resistance limited the amount of gel solution that could be injected into the sandpacks. Although a bulk get formed in the region bounded by this zone of high flow resistance, the treatment depth was limited and was significantly less than predicted from formation of a bulk gel. Previous investigators assumed that an in-situ permeability reduction mechanism resulted from simple bulk gelation of the injected solution. However, McCool et al. hypothesized that the permeability reduction resulted because the porous medium filtered permeability reduction resulted because the porous medium filtered aggregates of chromium/polyacrylamide from the gelling solution well before a true"get" could form. None of the models in the literature include the mechanisms needed to simulate correctly the in-situ gelation behavior of gelling systems studied by McCool, McCool et al., and Marty et al. The model developed in this paper is based on the filtration of gel aggregates from agelling solution. Model Description This section describes a conceptual model of in-situ gelation and develops mathematical equations to model the process. The model was developed by combining transport equations for the various chemical species in porous media with models of gelation kinetics and filtration processes. Equations describing chemical reaction kinetics and filtration mechanisms are taken from the literature. The porous medium consists of a linear sandpack of known permeability and porosity. A solution of thiourea, dichromate, and permeability and porosity. A solution of thiourea, dichromate, and polyacrylamide is injected into one end of the sandpack and polyacrylamide is injected into one end of the sandpack and progresses through the porous medium. Initially, nopolymer chains progresses through the porous medium. Initially, no polymer chains are chemically crosslinked, although the solution has a beginning level of entanglement "crosslinks," giving the solution an initial shear modulus, G', and defining an initial size distribution of "pregelclusters." Polyacrylamide solutions used in gelation displacements typically exceed the polymer entanglement concentration. Pregel clusters oraggregates first form when individual polymer chains become physically entangled with other polymer chains. Chemical crosslinking in the polyacrylamide/redox system begins when thiourea reacts with dichromate to produce CT +3 ions, which then attach to polymer chains. Attached CT +3 ions participate in crosslink formation, joining polymer chains and small clusters to form larger pregel clusters. During gelation processes, these pregel clusters steadily increase in size as small clusters combine pregel clusters steadily increase in size as small clusters combine to form larger ones. In the absence of shear, the largest aggregates ultimately form an "infinite" gel molecule throughout the volume of gelling solution. We believe that permeability reduction during in-situ gelation displacements results largely from the filtration of these large polymer aggregates before the infinite gel network is formed. Polymer is retained in the porous medium in two ways. When injected polymer first contacts the porous medium, a layer of polymer adsorbs on to the surface of the sand grains. This thin, polymer adsorbs onto the surface of the sand grains. This thin, dense initial layer is attached to the surface of the sand grain by physical entrapment and surface attractions and has little effect physical entrapment and surface attractions and has little effect on permeability. As polymer aggregates increase in size, some are filtered out and attach to previously deposited polymer. The filtration rate increases with polymer concentration, aggregate size, and attached Cr+3concentration. Porosity and permeability of the porous medium decrease as filtration progresses, causing the zone of high flow resistance observed during laboratory in-situ gelation displacements.
SPE Members Abstract A new radial model of in situ gelation of polyacrylamide by Cr(III) produced by a redox reaction has been polyacrylamide by Cr(III) produced by a redox reaction has been developed based on reaction kinetics describing the crosslinking and aggregation in the gelling solution, coupled with filtration equations governing the deposition of polymer on the porous medium. The gel system is based on the reaction of Cr(VI) with thiourea to produce Cr(III). Gelation occurs when Cr(III) reacts with polyacrylamide. The radial model is an extension of a linear polyacrylamide. The radial model is an extension of a linear displacement model (SPE 202 IS). The linear model was tested against displacement data and matching parameters in the model were determined by regression. These parameters were then used in the radial model to simulate parameters were then used in the radial model to simulate cases of practical importance. The radial model describes gelation behavior during the period of gel solution injection and the subsequent shut-in period. During the injection phase, a buildup of flow resistance occurs in the presence of radial flow, i.e., a variable shear field. After shut-in, continued reaction of the gelling solution is simulated under conditions of zero shear. These features allow simulation of a complete gelation treatment from the injection phase through the shut-in period. Using this model, ranges of injection rates, pH, and injection and shut-in times are investigated. The pH history of the gel solution was found to be an important variable in the gelation process. If reservoir pH is in the vicinity of 8.0, gelation is retarded and long shut-in periods are required to develop adequate gel properties for permeability modification. The effects of properties for permeability modification. The effects of reservoir pH can be offset by increasing the pH and the concentration of the reducing agent in the gel solution. A simulation of a three-layer system maintained at constant pressure drop was conducted to illustrate the capability of the model. Permeabilities of the three layers varied from 0.035 to 3.5 darcies. For the gel system simulated, all layers became plugged to some extent during the injection phase. Depth of gel penetration was dependent upon the permeability of the interval. In the lowest permeability zone, the affected region was within the range permeability zone, the affected region was within the range where remedial treatment after gelation might remove the gelled zone. These results suggest that isolation of high permeability zones is required for in-depth permeability permeability zones is required for in-depth permeability modification using the gel system examined in this study. Introduction Water injection is usually an efficient, relatively inexpensive secondary recovery method. However, permeability heterogeneities in the reservoir cause permeability heterogeneities in the reservoir cause channeling of the injected water, lowering sweep efficiency and bypassing oil in lower permeability zones. In situ gelation processes offer a low-cost method to redirect injected processes offer a low-cost method to redirect injected water from these highly conductive "thief zones" into less permeable zones. The low permeability zones often contain permeable zones. The low permeability zones often contain significant mobile oil not previously swept by injected water. When successful, in situ gelation treatments extend the economic life of waterfloods and generate additional oil reserves. P. 183
Current API RP13D guidelines outline 3 methods for determining hole-cleaning efficiency based on wellbore angle. Method 1, used in low-angle wellbores (<30°) compares cuttings slip velocity with annular velocity to determine a transport ratio and cuttings concentration. Method 2, also used for low-angle wellbores (<30°) derives a carrying capacity index (CCI) based on bulk annular velocity, fluid density and power-law rheology. Method 3, used in high-angle wellbores (<30°) derives a transport index (TI) based on fluid rheology, density, and flow rate. TI is then plotted on an empirically derived chart (Luo et al., 1992, 1994) to determine maximum allowable rate of penetration (ROP) that should ensure efficient hole cleaning. Although these methods are considered recommended practices by API, Method 3 (TI) is based on an outdated study (Luo et al., 1992) with limited scope (one flow loop, one field test). Additionally, this method neglects the importance of drill pipe rotation and pipe eccentricity in cuttings transport efficiency, which has been proven to be a factor in other studies (Akhshik et al., 2015; Sanchez et al., 1997b). This paper highlights the shortcomings of current API standards and identifies what effects contributing factors such as pipe eccentricity and drill pipe rotation rates may have on cuttings transport efficiency. Further, this paper discusses the impact pipe-to-hole area ratio and wellbore flow area have on the effects of drill pipe rotation and flow channeling. Five horizontal wellbores were modeled using Siemens Star CCM+ Computational Fluid Dynamics (CFD) software, with bottom-eccentric 4 ½″ drill pipe placement, in annular diameters of 6¾″, 7 ⅞″, 8 ⅜″ 8 ½″ and 8 ⅝″. Additionally, one bottom-eccentric 5″ drill pipe in an 8 ¾" wellbore was modeled to compare identical pipe-to-hole area ratios with different flow areas. Simulations were run with drill pipe rotation speeds increasing from 0 to 180 RPM, in 30 RPM increments. In order to determine the impact fluid rheology has on flow channel development, both medium density oil-based muds and light density water-based muds were modeled and compared. Bulk annular flow velocity was set to 100 ft/min, to maximize the observable effects of drill pipe rotation. Bulk average velocity was calculated from cross sectional area, determining both annular velocity (velocity parallel to wellbore) and absolute velocity (fluid velocity magnitude regardless of direction). The resultant velocity profiles were used as the annular velocity component in API CCI and TI calculations and compared to bulk annular velocity. In addition to observing fluid velocity for CCI and TI calculations, changes in effective viscosity from the onset of pipe rotation was also analyzed to determine changes in wellbore parameters that may affect cuttings transport.
Low primary recovery percentages from unconventional reservoirs have long motivated interest in Enhanced Oil Recovery (EOR) for these reservoirs, resulting in numerous simulation studies and injection pilots. However, performance from injections pilots has typically been disappointing compared to the simulations, suggesting that reservoir permeability and heterogeneity are not adequately described in the reservoir simulation models. In this study, a simulation and history-matching approach was used to quantify the permeability matrix over a six-section, nine-well area. Twelve years of production data were history-matched, using a combination of pressure-dependent permeability and enhanced permeability to represent natural fractures or other high-permeability features. Also, the performance of a failed injection pilot was history-matched to determine the level of reservoir heterogeneity needed to explain the pilot failure. Based on this study, a reservoir description capable of matching twelve years of production and injection history has been developed. Formation properties in the high-permeability streaks capable of causing the disappointing injection pilot performance have been quantified. Recovery has been forecast to depletion, and EOR under hydrocarbon gas injection has been forecast for a variety of scenarios. Optimal operating strategies and recommendations for technology development to mitigate early breakthrough are made. Realistic cost estimates were made for each scenario, and economics were run for each recovery method. These results give insight into the economic potential of enhanced oil recovery in the Elm Coulee Bakken formation. Recommendations for favorable tax treatment and scheduling of expenses/investments are made. Developing the permeability matrix using the history matching approach is a novel and versatile way of quantifying unconventional reservoir properties. However, it is important to match both injection and production data, since the permeability vector appears to have pressure-dependent effects. The effect of controlling injection thief zones by controlling local wellbore outflow is quantified, and a need for in situ permeability modification of fracture thief zones has been determined.
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