Summary For applications in which enhanced-oil-recovery (EOR) polymer solutions are injected, we estimate injectivity losses (relative to water injectivity) if fractures are not open. We also consider the degree of fracture extension that may occur if fractures are open. Three principal EOR polymer properties are examined that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. An improved test was developed to measure the tendency of EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers. Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft. For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea. Considering the polymer solutions investigated, satisfactory injection of more than 0.1 pore volume (PV) in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm3/cm2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects in which polymer solutions are injected. Introduction Maintaining mobility control is essential during chemical floods (polymer, surfactant, alkaline floods). Consequently, viscosification using water soluble polymers is usually needed during chemical EOR projects. Unfortunately, increased injectant viscosity could substantially reduce injectivity, slow fluid throughput, and delay oil production from flooded patterns. The objectives of this paper are to estimate injectivity losses associated with injection of polymer solutions if fractures are not open and to estimate the degree of fracture extension if fractures are open. We examine the three principal EOR polymer properties that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. Although some reports suggest that polymer solutions can reduce the residual oil saturation below values expected for extensive waterflooding (and thereby increase the relative permeability to water), this effect is beyond the scope of this paper.
This paper estimates injectivity losses associated with injection of EOR polymer solutions if fractures are not open and considers the degree of fracture extension if fractures are open. Three principal EOR polymer properties are examined that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. Using Berea sandstone cores (100–600 md) and various filters and filter combinations, an improved test was developed of the tendency for EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers. Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft. For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea. Considering the polymer solutions investigated, satisfactory injection of more than 0.1 PV in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm3/cm2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects where polymer solutions are injected. Introduction Maintaining mobility control is essential during chemical floods (polymer, surfactant, alkaline floods). Consequently, viscosification using water soluble polymers is usually needed during chemical enhanced oil recovery (EOR) projects. Unfortunately, increased injectant viscosity could substantially reduce injectivity, slow fluid throughput, and delay oil production from flooded patterns. The objectives of this paper are to estimate injectivity losses associated with injection of polymer solutions if fractures are not open and to estimate the degree of fracture extension if fractures are open. We examine the three principal EOR polymer properties that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. Although some reports suggest that polymer solutions can reduce the residual oil saturation below values expected for extensive waterflooding (and thereby increase the relative permeability to water), this effect is beyond the scope of this paper.
Xanthan gum has been used extensively in the oil industry as a viscosifier for different applications due to its unique rheological properties. In this paper we explore how the rheological behavior of xanthan-based fluids can be used to control fluid loss. Linear and radial flow tests were performed in 100–1,00 md rocks. The rheological characteristics of xanthan gum were measured in linear core flow tests. This constitutive flow behavior was used in a radial flow simulator to predict the invasion profile of xanthan gum in the formation. Radial flow tests were performed to validate the predictions from the simulator and to observe the effect of fluid loss additives such as starch and ground Berea. A laboratory scale drilling simulator was used to determine the leakoff and formation damage of xanthan-based drilling fluids. The fluid was circulated through tubing and cuttings were removed from the annulus. Thin section analysis and environmental SEM were performed on rock samples taken at different distances from the wellbore to determine the nature and depth of the damage. Results show that fines generated during the drilling process form an external filter cake which in combination with xanthan gum results in considerable fluid loss reduction. Damage due to xanthan gum is small and limited to a narrow thickness around the wellbore, resulting in negligible skin factors. The use of starch can lead to considerable damage and large skin factors if allowed to invade the formation. Introduction The rate of leakoff is of critical importance during drilling, completion operations (i.e. sand control) and stimulation treatments, such as acid treatments and hydraulic fracturing. In all of these cases, fluid loss control has been achieved by two basic mechanisms: 1Increasing the overall viscosity of the fluid using high polymer concentrations or by crosslinking the polymer.2,3Developing an internal and/or external filter cake using fluid loss additives (starch, sized CaCO3, mica, silica flour, oil soluble resins, etc.) to plug the pore-throats of the formation.4 Both fluid loss control mechanisms may result in a loss of permeability when flow is initiated in the production mode. Furthermore, if fluid loss additives are not used properly, they can cause significant loss of permeability due to their plugging mechanism if they enter the formation.5,6 Xanthan gum has been used extensively as a viscosifier in the oil field for drilling, drill-in and completion fluids due to its unique rheological properties.7 In this paper we explore the rheological properties of xanthan-based fluids in Berea sandstone rocks and how these properties can be used to control fluid loss. Prior attempts to simulate the flow of non-Newtonian fluids in porous media have not been entirely satisfactory because of the lack of an adequate correlation between the deformation rates inside the pore-throats and the velocity of the fluid. 3,8,9 Linear and radial flow tests were performed in 100 to 1,000 md rocks. The rheological behavior of xanthan gum was measured in linear core flow tests. This constitutive flow behavior was used in a radial flow simulator to predict the invasion profile of xanthan gum in the formation. Radial flow tests were performed to validate the predictions from the simulator. Simulations of field scale wellbore invasion profiles are presented using both xanthan gum and HEC. The effect of fluid loss additives, such as starch and sized CaCO3 was also studied in radial flow leak-off tests. The damage left over associated with those additives was quantified and compared to pure xanthan-based fluids.
Achieving optimal fluid performance with biopolymer viscosifiers, xanthan and welan, depends on reaching or exceeding a minimum or critical polymer concentration (CPC). CPC is affected by a variety of fluid and wellbore conditions, including: temperature and salinity, average shear rate, shear history, velocity gradients, hole angle, polymer configuration and rigidity, and the size, density, and concentration of suspended solids. The suspension and transport properties of xanthan and welan correlate directly to low-shear-rate-viscosity (LSRV) and elasticity (G'), properties which cannot be quantified with a conventional field viscometer. LSRV and G' are qualitatively related to a polymer's molecular rigidity and configuration, and quantitatively to the number of physical and chemical polymer chain associations, referred to as polymer networks and structures.
Over 60 horizontal wells have been drilled and completed with slotted liners in Prudhoe Bay, Alaska using a low solids or solids-free clarified xanthan/brine drill-in fluid.As previously described the drill-in fluid demonstrates a functional true yield stress (TYSI in the circulating fluid.' The yield stress is also present in the filtrate. limiting depth of filtrate invasion.The fluid has been further described as being viscoelastic (VEI under stat!c conditions and at the low shear rates exisiting in an expanded plug flow region. This plug flow region is persistent over a wide range of flow rates and is a function of polvmer concentration and brine salinitv. The exhibits both time-indepent and pseudoplastic IS -MS s*~w~rn~by M IADt2spE PrOgrm COmmmee bWng -of inf-m contained in M fibWaCf uhffWDd W~W($). me matwml, u pmemad, does not nmca&llY mnecf any pmtim of me IAOC w SPE. tiw offcem c+ m~p-s v~@ lA~~pE m~lw~Or* wqec! IO puilKa!r2n revmw by EdficfiaI Commliieed of the IADC and SPE Perrmsmon 10 copy IS re$ltiti 10 an *W@ Of nof mom mm 300 ti% lthJ*rat~$ may noi M coped me abstract shodd conmn compcwus acknWd&gem~t ol where and by whom the P-IS pre$entti. Wtie bb~l~spE. p O~x -. Rchntism. TX 793-3. U.S.A. TOIW. 1~45 $pEuT
Formation damage is a concern when attempting to control fluid loss during drilling operations. The usual approach is to use bridging agents and high polymer loadings to reduce fluid loss. However, these additives contribute to formation damage. In this paper we explore the fluid loss characteristics of xanthan-based fluids, including starch and calcium carbonate, during the drilling process. Fluid loss while drilling is a complex process where fluid is lost underneath the bit and through the surface of the wellbore. A unique laboratory scale drilling simulator was used to determine the leakoff and formation damage of xanthan-based drilling fluid formulations. The fluid was circulated as in a conventional drilling operation, through the microbit and up the annulus under overbalanced conditions. Thin section analysis and environmental SEM were performed on rock samples to identify the different components of the fluid system. Sandstones up to 1,000 md were used. Cleanup sequences, which include enzymes and oxidizers, were also evaluated after the cores were drilled. The cleanup efficiencies were compared to conventional QC-testing techniques used by operators for filtercake removal. The results showed that most of the fluid is lost underneath the bit in a continuous spurt condition while drilling. The filtercake formed during drilling does not pose a resistance to flow during production, but poses a strong resistance during leakoff. Xanthan gum contributes to fluid loss reduction, while combinations of CaCO3, starch and xanthan gave the lowest leakoff and formation damage. Wellbore soaking procedures do improve production after drilling. Introduction The issue of formation damage has always been a concern when attempting to control fluid loss during drilling operations. The use of bridging agents and high polymer loadings to reduce fluid loss has been the common approach. However, these additives have the potential to contribute to formation damage.1 Xanthan gum has been used extensively as a viscosifier in drilling, drill-in and completion fluids because of its unique rheological properties.2 In this paper we explore the fluid loss characteristics of xanthan-based fluids, including starch and calcium carbonate during the drilling process. Fluid loss while drilling is a complex process where a significant part of the fluid is lost underneath the bit under continuous spurt conditions while drilling.3 The spurt loss appears to occur where new surface area is being generated, i.e. where the rock is being crushed and removed. During the initial spurt loss, an internal filtercake is formed, which eventually leads to and external filtercake. The composition of the filterake is made up of bridging agents (drill fines, CaCO3, and starch) and viscosifying polymer (xanthan gum, HEC) that covers the porous wellbore. This filtercake is beneficial since it can significantly reduce the fluid loss rate preventing further damage to the wellbore. During the spurt phase, however, fluid enters the formation resulting in potential damage. The depth of the invasion and the reduction in permeability in the invaded zone will determine the skin and overall effect on production.1,4 A significant effort has been placed into removing the external filtercake by means of soaking the wellbore with breaker solutions intended for the bio-polymer and the bridging agents.5-9 The idea is to dissolve the filtercake to reduce potential damage during production.
Xanthan gum has been used extensively as a viscosifier in the oil industry for different applications due to its unique rheological properties. In this paper we describe the properties of two previously introduced bio-polymers for use in drilling, drill-in, completions, spacer fluids and coiled tubing applications. The first bio-polymer yields higher viscosities and better temperature stability at lower polymer concentrations than welan and xanthan gum due to its higher molecular weight; this polymer is particularly effective in low salt fluids. The second bio-polymer has improved solubility in high density CaCl2 brines. Viscosity data over a wide shear rate range in different brine systems is presented comparing the new bio-polymers with xanthan and welan gum at temperatures between 75°F to 330°F. The effect of different types of solids and friction pressure tests in coiled tubing are presented, showing diutan's friction reduction properties. Introduction Since its introduction in 1964 xanthan gum has been used extensively in the oil industry as a viscosifier for different applications due to its unique rheological properties. These applications include drilling, drill-in, completions, coiled tubing and fracturing fluids.1 Similarly, welan gum (introduced in 1985) has been used in drilling fluids and cement spacers, due to its compatibility with oil field cement formulations. Navarrete et al.2 introduced two new bio-polymers which have improved performance in some of the applications where xanthan and welan gum have been traditionally used. The first polymer is a new bio-fermented polymer produced by a newly isolated naturally-occurring bacterial strain of the Sphingomonas genus. This bio-polymer has been given the generic name of diutan gum. The chemical structure of the monomer is shown in Fig. 1. The tertiary structure is a double-helix. The diutan structure is closer to that of welan gum (Fig. 2) than that of xanthan gum. However, there are important differences. Diutan has an average molecular weight of 5×106, which is much higher than those of welan and xanthan. This is why the length of the diutan molecule is larger than that of welan or xanthan (Fig. 3). The second polymer is a pyruvate-free variant of xanthan gum, or Non-Pyruvylated Xanthan (NPX) gum, produced from Xanthomonas campestris. The chemical structure of the NPX monomer is shown in Fig. 4. NPX is similar in structure to xanthan gum on all other respects aside from the absence of the pyruvic acid group which reduces anionic character. The unique structures of these two bio-polymers give them different properties in solution. Some of these properties can be advantageous in the design of water-based drilling, drill-in, completions, coiled tubing and spacer fluids. These properties are presented in this paper. Experimental Rheological Measurements. Rheological measurements were performed using a Brookfield PVS viscometer which can measure shear viscosity between 0.05 to 1,000 s-1, at temperatures up to 350°F and pressures up to 1,000 psi. A pressure of 300 psi was used in all tests. Different geometries can be used with this instrument. The ones used here were the single annulus B1-R1 Couette geometry, and the triple annulus TA5 Couette geometry. Other viscometers used at ambient temperature were the FANN 35 (B1-R1 Couette) and the Brookfield DV-II (wide gap Couette).
Xanthan gum has been used extensively as a viscosifier in the oil industry for different applications due to its unique rheological properties. In this paper we introduce two bio-polymers for use in drilling, drill-in, completions, spacer fluids and coiled tubing applications. The first bio-polymer yields higher viscosities and better temperature stability at lower polymer concentrations that welan and xanthan gum due to its higher molecular weight; this polymer is particularly effective in low salt fluids. The second bio-polymer has improved solubility in high density CaCl2 brines. Viscosity data over a wide shear rate range is presented comparing the new bio-polymers with xanthan and welan gum at temperatures between 75°F to 300°F. Viscoelastic measurement and settling test are presented to demonstrate the effect of elasticity of the bio-polymers on solids transport and suspension capabilities. Fluid-loss, formation damage tests and friction pressure tests in coiled tubing are also shown. Introduction Since its introduction in 1964 xanthan gum has been used extensively in the oil industry as a viscosifier for different applications due to its unique rheological properties. These applications include drilling, drill-in, completions, coiled tubing and fracturing fluids.1 Similarly, welan gum (introduced in 1985) has been used in drilling fluids and cement spacers, due to its compatibility with oil field cement formulations. Here two new bio-polymers are introduced which have improved performance in some of the applications where xanthan and welan gum have been traditionally used. The first polymer is a new bio-fermented polymer produced by a newly isolated naturally-occurring bacterial strain of the Sphingomonas genus. This bio-polymer has been given the generic name of diutan gum. The chemical structure of the monomer is shown in Fig. 1. The tertiary structure is a double-helix. The diutan structure is closer to that of welan gum (Fig. 2) than that of xanthan gum. However, there are important differences. Diutan has an average molecular weight of 5×106, which is much higher than those of welan and xanthan. This is why the length of the diutan molecule is larger than that of welan or xanthan (Fig. 3). The second polymer is a pyruvate-free variant of xanthan gum, or Non-Pyruvylated Xanthan (NPX) gum, produced from Xanthomonas campestris. The chemical structure of the NPX monomer is shown in Fig. 4. NPX is similar in structure to xanthan gum on all other respects aside from the absence of the pyruvic acid group which reduces anionic character. The unique structures of these two bio-polymers give them different properties in solution. Some of these properties can be advantageous in the design of water-based drilling, drill-in, completions, coiled tubing and spacer fluids. These properties are presented in this paper. Experimental Rheological Measurements. Rheological measurements were performed using a Brookfield PVS viscometer which can measure shear viscosity between 0.05 to 1,000 s-1, at temperatures up to 350°F and pressures up to 1,000 psi. A pressure of 300 psi was used in all tests. Different geometries can be used with this instrument. The ones used here were the single annulus B1-R1 Couette geometry, and the triple annulus TA5 Couette geometry. Other viscometers used at ambient temperature were the FANN 35 (B1-R1 Couette) and the Brookfield DV-II (wide gap Couette). Rheological Measurements. Rheological measurements were performed using a Brookfield PVS viscometer which can measure shear viscosity between 0.05 to 1,000 s-1, at temperatures up to 350°F and pressures up to 1,000 psi. A pressure of 300 psi was used in all tests. Different geometries can be used with this instrument. The ones used here were the single annulus B1-R1 Couette geometry, and the triple annulus TA5 Couette geometry. Other viscometers used at ambient temperature were the FANN 35 (B1-R1 Couette) and the Brookfield DV-II (wide gap Couette).
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