This paper elucidates the influence of pH and ion exchange on formation damage caused by fines migration. The experimental results affect waterflooding, design of drilling muds, and alkaline flooding. In-situ release of naturally existing fines (generally clays) results from changes in colloidal conditions of the permeating fluid. Such processes can cause extensive formation damage in sandstones, thereby reducing oil production. Our recent studies clearly indicate that the release process is started by a combination of high pH and low salinity. We present experimental results that suggest and confirm the interdependence between changes in salinity, cation exchange, and pH, leading to drastic permeability reductions. These results therefore provide new insight into the phenomenon of formation damage caused by water sensitivity or injection of incompatible brines. We also describe a unified approach to understanding these results and the findings of previous investigators. Predictions obtained from a physiochemical model based on ion exchange and colloidal chemistry agree well with experimental observations. The effect of different cations on formation damage also was investigated. This study can be extended to predict migration of bacteria and other particulates that cause formation damage.
This paper presents the results of corrosion and mechanical testing ofwelded high-nickel, corrosion-resistant-alloy (CRA) lined pipes manufacturedusing various lining processes. The corrosion pipes manufactured using variouslining processes. The corrosion resistance of CRA-lined pipes for use as aflowline material in sour service was evaluated. The effects of themanufacturing process, CRA lining material, and welding on the corrosionprocess, CRA lining material, and welding on the corrosion performance ofCRA-lined pipes also were determined. performance of CRA-lined pipes also weredetermined. Introduction
Many recently discovered and developed oil and gas fields are deep and sour.In these severe sour environments, the use of steel pipes with inhibition isineffective or infeasible in combating pipes with inhibition is ineffective orinfeasible in combating corrosion and cracking. Therefore, CRA's have been usedmore frequently. The high initial cost of nickel-based CRA materials oftenmakes it difficult to provide the economic justification for use of solid-CRApipes. Therefore, several manufacturers are producing a steel pipe with only aCRA lining as a cost-effective producing a steel pipe with only a CRA lining asa cost-effective alternative to solid pipes. The double-wall, bimetallicCRA-lined pipe has an inner layer made of a very resistant CRA and an outerlayer made of low-cost steel. Some CRA-lined pipes have metallurgical bondingbetween the lining. and the steel, while some have only a mechanical bondbetween the CRA layer and the steel layer. The metallurgically bonded pipes(called clad pipes) usually are manufactured by such processes as coextrusion,hot-rolled bonding, explosive bonding, processes as coextrusion, hot-rolledbonding, explosive bonding, or centrifugal casting. The mechanically bondedpipes are manufactured by thermohydraulic gripping of CRA and steel pipes. Themanufacturing processes of CRA-lined pipes differ from solid-CRA pipeprocesses. Flowlines transport production fluids from the wellhead to treatingand processing facilities. They typically are constructed by girth welding pipesegments end-to-end. In sour fields, the fluids transported through flowlinesmay contain highly corrosive gases, like H2S and CO2, and highly corrosivebrines. The objective of this study was to evaluate the corrosion resistanceand suitability of CRA-lined pipe for use as a flowline in sour service. Theprimary questions included (1) whether CRA-lined pipe performs in sour serviceas well as solid-CRA pipe, (2) whether a performs in sour service as well assolid-CRA pipe, (2) whether a difference in performance exists betweenmanufacturing processes, (3) whether the CRA lining materials performdifferently from each other, and (4) whether a weldment performs in sourservice as well as the parent pipe. Three UNS N06625-lined and three UNSN08825-lined Grade X60/X65 pipes were tested in this study. These pipes weremanufactured by coextrusion of the CRA and steel pipe, coextrusion of CRApowder metallurgy cladding and steel pipe substrate, and thermohydraulicgripping of the CRA and steel pipe. Table 1 summarizes the manufacturingprocedure for each of the pipes investigated. A solid pipe of UNS N06985 alsowas included in the test program so that the corrosion performance of CRA-linedand solid-CRA pipe could be compared. Table 2 lists the standard chemicalcompositions of UNS N06625, UNS N08825, and UNS N06985.
Standard tensile, Charpy impact, shear-strength, flattening, andhardness/microhardness tests were performed to characterize the pipes. Becausemany tests were needed to evaluate the mechanical pipes. Because many testswere needed to evaluate the mechanical and corrosion performance of the pipes,the quantity of some welded samples acquired for this study was not sufficientfor all tests. Priority was given to making specimens for corrosion testing.Priority was given to making specimens for corrosion testing. Also, because themechanically bonded pipes lacked metallurgical bonding between the lining andthe steel, shear strength could not be measured. Therefore, not all tests wereconducted for each pipe. Table 3 summarizes the mechanical properties of thetested pipe samples.
Tensile Strength. Yield and tensile strengths of the steel layer weremeasured after cladding removal. The strengths of the liners also were measuredafter machining away the steel outer shell. Strengths were measured for bothparent and welded pipes. The yield strength measured from the CRA liners wasused to determine the deflections needed to stress the bent beams to 90% yieldfor stress-corrosion-cracking (SCC) testing.
Notch Toughness. Charpy V-notch impact toughness of parent pipe and weldmentwas measured. The Charpy impact toughness reported in Table 3 is the average ofthree 10 x 10-mm Charpy impact specimens tested at - 20 degrees F. The Charpyimpact specimens were extracted from the steel layer and oriented in thelongitudinal direction. The Charpy V notches were placed in three differentlocations: the center of the weld, the heat-affected zone, and the basemetal.
Bond Shear Strength. The shear strength of the metallurgical bond betweenCRA and steel was evaluated in accordance with the shear test of ASTM Std.A-265. This test was performed only at the parent pipe cladding. parent pipecladding. Flattening Test. This test was used to evaluate bond ductility inaccordance with ASTM Std. A-530.
Hardness/Microhardness. Rockwell hardness [using B scale up to 100 RockwellB Hardness (HRB) and C scale from 20 Rockwell C Hardness (HRC)] and Vickersmicrohardness (HVN) were measured in the CRA liners in both the parent pipe andthe weldment.
Phase splitting occurs during gas/liquid two-phase flow through pipe junctions and causes a gas/liquid mass ratio in the outlet legs of the junction that is different from that at the inlet. In steamflood distribution networks, this results in different steam qualities at the outlets of a junction than at the inlet. This, in turn, results in a heat distribution not in accordance with the mass distribution in the outlets of the tee. Because heat management of a steamflood project is important for both economic incentives and ultimate recovery, phase splitting must be understood and controlled. This paper presents the results of an experimental investigation conducted on phase splitting of wet steam during annular flow through a horizontal 2-in. impacting tee. The experimental operating range included inlet pressures of 400 and 600 psig, inlet mass fluxes from 1,180 to 10,150 lbm/(in.2-hr), inlet steam qualities from 0.2 to 0.8, and outlet vapor extraction ratios for one outlet leg from 0.2 to 0.5. From these experimental data, the relative importance of these variables on phase splitting was determined and correlations to predict the outlet steam qualities were established. These correlations predicted the experimental results of the present investigation and of Azzopardi et al. to within acceptable limits.
Most large steam EOR projects incorporate a complex steam distribution system involving a multitude of junctions to transport steam to injection wells. The junctions used to distribute the steam can be impacting or branching tees. An impacting tee divides the incoming flow into two coaxial outlet branches perpendicular to the inlet (Fig. 1). A branching tee diverts part of the incoming flow through a branch perpendicular to the inlet while the remainder flows straight through the tee (Fig. 2). In branching tee junctions, the vapor/liquid mass ratio at the outlets can be substantially different from that at the inlet. This phenomenon is known as phase splitting of two-phase flow. Because the vapor phase of a wet steam has a much higher heat content per unit mass than the liquid phase, the difference in the vapor/liquid ratio leads to a heat distribution to each outlet that is not proportional to the mass distribution of the steam. Because of the symmetric geometry of an impacting tee, it was felt that phase splitting may not occur. Therefore, many steam distribution systems of steamflood projects have used impacting tees as junctions. Recent studies have shown, however, that the phase splitting in impacting tees can be as severe as in branching tees, especially when the inlet quality and the extraction ratio are low.
This paper presents a general and unified equation for flowing temperature prediction that is applicable for the entire range of inclination angles. The equation degenerates into Ramey's equations for ideal gas or incompressible liquid and into the Coulter and Bardon equation, with the appropriate assumptions. This work also proposes an approximate method for calculating the Joule-Thomson coefficient for black-oil models.
Flowing temperature distribution often is predicted with different methods for pipelines and wellbores. The Ramey method usually is used for predicting wellbore temperature distribution. This method rigorously incorporates the complex process of transient heat transfer between the wellbore and the reservoir. Ramey's method, however, is limited to either ideal gas or incompressible liquid flow. The Coulter and Bardon equation commonly is used for pipeline temperature prediction. A more rigorous thermodynamic behavior of the flowing fluid is taken into account, incorporating the Joule-Thomson coefficient. Although the Coulter and Bardon equation originally was derived for gas flow, it also is used for single-phase liquid or two-phase flow. This equation is limited, however, by the assumptions of steady-state heat transfer with a constant-temperature environment and horizontal flow.
Coalbed methane (CBM) wells usually are dewatered with sucker rod orprogressive cavity pumps to reduce wellbore water levels, although not withoutproblems. This paper describes high-volume artificial-lift technology thatincorporates specifically designed gas-lift methods to dewater Black WarriorCBM wells. Gas lift provides improved well maintenance and productionoptimization by the use of conventional wireline service methods.
Since 1971, CBM wells have been dewatered by conventional artificial lift.To date, Black Warrior basin wells typically have been produced by either rodor Moyno pumps, with few problems. Wells usually are drilled from 1,000 to2,500 ft deep, with some reaching 6,000 ft. Water has been produced inside 27/8-in. tubing, while methane gas has been produced up the annulus. Productionranges from 50 to 1,000 BWPD (averaging 300 to 350 BWPD). The wells generallyrequire 3 to 12 months to dewater.
The inherent requirement of a Black Warrior basin completion is that thebottomhole flowing pressure (BHFP) across the coal seams (desorption pressure)must be about 5 to 10 psi. The most effective installation meets this objectiveat an acceptable cost.
Many wells in the basin first arc brought on line by single-point injectionof air down the production string. This allows the well to be cleaned of anyremaining sand or coal fines and to reach a lower fluid production rate in lesstime. Upon reaching this rate, the well can be placed on pump lift.
A large number of wells are scheduled for completion over the next fewyears, many at greater depths than reached previously (3,500 to 4,500 ft).Artificial-lift technology commonly used in conventional wells now can beapplied to CBM wells to maximize efficiency and recovery while minimizingoverall costs.
Over the past few years, gas lift has been introduced to CBM's in Alabama asan alternative method to dewater wells. Gas-lift technology first was used inthe Black Warrior basin in 1984.
A principal method of gas lift still in use is single-point injection (Fig.1). One of the first methods to unload oil and gas wells, this technique notonly assists in unloading the well but also can help remove fracture sand andcoal fines from the wellbore before completion.
Experience with conventional wells has shown that this procedure is quiteinefficient. procedure is quite inefficient. 1. The rig must be maintained atthe wellsite until the rods have been installed, while it might be betterutilized elsewhere if a more effective lifting system completed the well fromthe start. 2. The rig's air supply must be sufficient to turn the fluid aroundand bring the water back to surface. Such a compressor not only is costly butalso keeps the rig from its primary job. 3. Gas production and bottomholepressure (BHP) cannot be monitored effectively during production. 4. With airinjected down the tubing and air and water returning up the annulus, the casingand tubing are subject to significant, perhaps irreparable, corrosion damage ifair is injected for a prolonged period. The well cannot be watered downeffectively before being placed on a rod pump. 5. If the operator simply startsinjection at a higher point with a "macaroni"-type injection system andadds tubing as required to inject more deeply into the wellbore, a rig will berequired.
Conventional casing-flow gas-lift installations also have been tried withgas injected down the tubing through conventional gas-lift valves that arestrategically spaced in the string. Fluid and injected gas are produced up theprimary annular area, while coal-seam gas is produced up the secondary annulararea (Fig. 2). Although considerable fluid is produced, this installation hasseveral shortcomings.
1. Conventional gas-lift valves are a permanent part of the tubing string.As the well is unloaded, production first passes through the ported section ofthe unloading valves. Production fluid often contains coal fines that cut outthe stem and seat. As the well is unloaded to the next operating valve, amultipoint injection failure will occur because of damage to the uppervalve(s). This failure sharply curtails fluid lift efficiency and consumesexcessive quantities of lift gas. 2. Valves cannot be retrieved and repairedwithout the tubing being pulled and a completion workover performed. 3. Theinstallation would cost more than would a conventional rod or gas-liftinstallation. The secondary annulus requires 7-in. minimum casing ID, while theprimary casing string must be 51/2 in.
The installations discussed will produce large volumes of water, but neitheris a truly economical or effective gas-lift system. By comparison, asignificantly modified gas-lift completion was developed that allows theoperator to dewater a well efficiently. This installation (Fig. 3) yields thelifting efficiency and capacity of a standard gas-lift completion under theunique conditions of the Black Warrior basin. The completion requires onlystandard oilfield equipment: (1) a side-string side-pocket mandrel (Fig. 4),(2) wireline-retrievable gas-lift valves, (3) a reeled-tubing injection string,and (4) conventional wireline tools.
Black Warrior basin wells produce water up the tubing and methane up theannulus. Because of the low desorption pressures required and coal seam spacingvarying from 1 to 2,000 ft, a packer-type completion is out of the question.With a typical gas-lift completion, lift gas cannot be injected down theannulus into the tubing string and still attain the required BHFP. A new methodwas used to direct gas to the desired injection point while keeping the annulusopen for gas production.
Reeled tubing was used with side-pocket mandrels in a design that allowedlift gas to be injected selectively into the tubing string. The side-pocketmandrels have ]-in. pockets to accept wireline-retrievable gas-lift valves.These mandrels are designed to provide a full tubing ID. Valves may be servicedthroughout the life of the well without a well workover. These features allowthe operator luxuries not currently available.
1. BHP surveys are better without the concern for the accuracy of soundingdevices. 2. Problem valves can be identified and replaced as required. 3.Valves are not affected by downhole conditions inherently detrimental to pumpinstallations, reducing concerns with fracture sand, coal fines, and rod pumps.4. Fluid production may be altered by adjusting the injection-gas volume orpressure.
Pseudo 3D (P3D) hydraulic fracturing models often overpredict fracture height for a poorly contained fracture. This is caused partly by either the neglect of the fluid flow component in the vertical direction or a crude treatment of the 2D fluid flow in the fracture as ID flow in the vertical direction in the fracture-height calculation. This paper presents a height-growth model that adopts a flow field more representative of the actual 2D flow in a fracture. In this model, the fracture is divided into two regions: an inner region where the flow direction is nearly horizontal, and an outer region where the flow field is approximated by a radial flow from an imaginary source. The governing equations for determining height growth rate and the numerical method for solving these equations are described. A commercial P3D simulator was modified by replacing its original height-growth model with this 2D flow-height model. The modified simulator was tested against the original simulator and the Terra Tek and U. of Texas fully 3D simulators. The modified P3D simulator incorporating the new height model showed significant improvement over the original model in height calculations and good agreement with the fully 3D models.
Over the past decade, numerous 3D hydraulic-fracturing models have been developed. These models can predict fracture geometry, including height, with known reservoir parameters. The 3D models can be divided into two categories. The first type of models, often called P3D models, evolves from the 2D Perkins-Kern-Nordgren (PKN) model. Unlike the constant fracture height assumed in the PKN model, the height in a P3D model grows with time and varies along the pay-zone direction. The fluid flow in the fracture is assumed to be predominantly ID. The plane-strain condition is assumed on the deformation of each vertical fracture cross section. The other type of models, called fully 3D models, solves a set of coupled equations governing the deformation of a 3D fracture and the 2D fluid flow in the fracture. The fully 3D models are mathematically more rigorous but very complex and difficult to run.
Different P3D models use different approaches to calculate fracture height and vary significantly in degree of complexity. The simplest approach is to determine height from the local net pressure, stress profile, and rock toughness by satisfying the static equilibrium of the fracture. The height thus obtained is the equilibrium fracture height. Fluid pressure is assumed constant over each vertical cross section, and the fluid flow is assumed to be in the pay-zone direction only.
Studies were conducted on site in the Coalinga, Belridge, and Midway Sunsetfields in California to research the cause of metal losses detected in theradiant section return bends and immediate piping downstream from the steamgenerators. Surveillance of silica content in the influent and effluent streamsof the selected steam generators and the results of X-ray inspection of bends,elbows, welds, and pipings indicated that (1) a correlation is likely to existbetween the silica and bicarbonate concentration in the feedwater and thesilicate scale buildup, and incident rate of wall loss and (2) the cause ofwall loss/pipe failures is a combination of corrosion and erosion mechanismsaccelerated at higher steam qualities.
Large-scale steamdrives began in the west Coalinga field in 1979. Injectionrates increased from 3,000 B/D of steam (BSPD) (feedwater equivalent) in 1979to 39,000 BSPD currently. Silica content of the steam generator feedwater hasincreased concurrently from 70 to 275 mg/L. The silica content is expected toincrease as more reservoirs are steamflooded and the produced water is recycledcontinuously. Most heavy-oil operators in southern California have experienceda similar increase in silica levels in their generator feedwaters. With littledilution by fresh water and maximum use of recycled produced water, someoperators tended to reduce the steam quality to between 50% and 60% or to lowerthe pressure levels to 500 psig to tolerate the high silica content. TheCoalinga Steam Injection System normally operates at 3,000 BSPD (feedwaterequivalent), 75 % to 80 % steam quality, 950 psig, and 540 degrees F. In 1986,pinhole leaks began to appear bimonthly in the steam generator discharge pipingat the Coalinga field. In 1987, following a leak frequency increase and therupture of two pipes, steam injection was shut in for about 3 weeks forcomprehensive inspection and repairs. Some fittings reportedly had beenreplaced only months earlier, demonstrating how quickly wall loss was occuring.When reinjection was begun, the operating steam quality was reduced to 50% forsafer generator operation until the problem could be defined better. Thisreduction in quality resulted in 20% less heat input to the reservoir for thesame boiler feedwater, with a subsequent decline in oil production. This paperdescribes a study conducted in 1987 in the Coalinga. Belridge, and MidwaySunset fields near Bakersfield. The purpose of this study was to search for thecauses of detected wall loss and frequent pipe failures at Coalinga and tocompare results with those found at the other two fields. This included (1)surveillance of silica content in the influent and effluent streams of selectedsteam generators at a range of steam qualities (50% to 85 %), (2) metallurgicalstudy of the failed sections and identification of major deposits, (3) X-rayinspection of the steam generator's piping systems to locate metal loss andscale buildup, and (4) determination of the influence of piping system andsteam quality on erosion of corrosion films and solids transport.
The produced water from a steamflood generally contains silica. This silicais dissolved from the quartz present in the formation by unvaporized andcondensed water that has a pH greater than 9. Dissolved silica tends to formscales in steam generator tubes if either its concentration is reduced or itssolubility is increased. The API2 has proposed several guidelines for thequality of wet-steam generator feedwater. The guidelines emphasize that afeedwater with hardness less than 1 mg/L (as CaCO3) and silica content nothigher than 150 mg/L in the absence of scaling ions (iron, magnesium, etc.) isnecessary to maintain satisfactory operations. The API also reported that theamount of silica and hardness that can be tolerated in the feedwater of steamboilers decreases as the pressure of the steam generator increases. pressure ofthe steam generator increases. Silica can be removed by coagulation withchemicals such as in cold- or hot-lime softening or demineralization by anionexchange resins. A description of these processes is beyond the scope of thispaper. However, it is worth mentioning that two operators, one in south Texasand one in Peace River (Canada), have reported that the dissolved silicaconcentrations were reduced from 400 to less than 50 mg/L by the hot-limesoftening process.
Field investigations were carried out in three stages: (1) surveillance ofthe silica content upstream and downstream of selected steam generators, (2)investigation of the effect of steam quality on the precipitation or loss ofsilica in the generator, and (3) X-ray inspection of the piping systems.
Status of the Silica Content and Hardness in Feedwater. The steamfloodproduced water from Coalinga, Belridge, and Midway Sunset fields flows throughdiatomaceous earth (DE) filters and then through a series of softeners beforeit is used for steam generation. An oxygen scavenger, such as catalyzed sodiumsulfite, was added periodically to the de-aerated freshwater streams whenmakeup saw was required at Midway Sunset and Belridge. A sampling technique wasdeveloped to collect representative samples from the influent and effluent ofthe steam generator at various steam qualities up to 85%. Fig. 1 is a schematicof the sampling apparatus and associated equipment. Analytical procedures weremodified to account for H2S interference and the presence of colloidal silicaon silica measurements. Table 1 gives the chemical analyses of the feedwater atthe Coalinga, Midway Sunset, and Belridge fields. The survey of silica content(pre- and postfiltration and softening processes) indicated that there was nodetectable colloidal silica in the feedwater and that the DE filters did notcontribute silica to the overall concentration. The following differencesbetween Coalinga feedwater and those of Belridge and Midway Sunset were found.1. The silica content in the feedwater at Coalinga (254 mg/L) was higher thanthat at Midway Sunset (197 mg/L) or Belridge (142 mg/L). 2. The magnesium andcalcium concentrations in the feedwater at Coalinga were also higher than thelevels detected at Belridge and Midway Sunset. These levels (up to 1 mg/L)correspond to a hardness of up to 4 mg/L CaCO3, which is considered fairly highfor feedwater. 3. The dissolved CO2/HCO3- content in Coalinga feedwater was atleast 10 times higher than in the other two feedwaters. 4. The H2S/sulfide andoxygen content in the Coalinga feedwater was higher than in the other twofeedwaters. 5. The salinity of the feedwater was one-half that of Midway Sunsetand one-third that of Belridge.
The concentrations of an oxidative breaker required to reduce significantlythe proppant-pack permeability damage caused by aqueous hydraulic fracturingfluids have been determined. Long-term, proppant-pack permeability testing wasused to evaluate linear and borate-crosslinked gels. Results indicate thatincreasing the breaker concentration can reduce proppant-pack permeabilitydamage very effectively. permeability damage very effectively.
Long-term, proppant-pack permeability testing was performed with a modifiedAPI-type fracture conductivity cell that permitted fluid loss through twolow-permeability cores. The fluids evaluated were linear and borate-crosslinkedgels of natural guar and hydroxypropyl guar (HPG). The effective polymerconcentrations were varied from 100 to 440 lbm/1,000 gal to account forconcentration caused by static fluid loss.
Test results indicate that increasing the breaker concentrations can reduceproppant-pack permeability damage very effectively. The degree of permeabilityimprovement was found to be influenced strongly by the polymer concentrationand the presence of a crosslinker. The breaker concentrations necessary topresence of a crosslinker. The breaker concentrations necessary to improvepermeability significantly were far above those typically used in fieldapplications because of the degrading effect of breakers on fluid transportcapabilities. The knowledge that elevated breaker concentrations can greatlyimprove proppant-pack permeability provided the impetus to develop delayedbreakers to permeability provided the impetus to develop delayed breakers toprotect fluids in the proppant transport stage and degrade them after protectfluids in the proppant transport stage and degrade them after closure. Also, anunderstanding of the relationship of these parameters and the resultantretained proppant-pack permeability parameters and the resultant retainedproppant-pack permeability can be useful in fracturing treatment design andwell performance prediction. prediction. Background
Engineers who design and evaluate hydraulic fracturing treatments frequentlypredict productivity increases much greater than those actually observed. Thein-situ proppant-pack permeability is known to be a primary factor affectingthe productivity of fractured wells, and therefore is important to fracturingtreatment design and evaluation. 1.2 The proppant-pack permeability dataprovided for the design of fracturing treatments typically are short-term datacollected under ambient temperature conditions without a fracturing fluid.Recent efforts have focused on the evaluation of long-ten-n proppant-packconductivity.
Proppant-pack permeabilities were reduced significantly when packsProppant-pack permeabilities were reduced significantly when packs weresubjected to long periods at temperature and stress. The long-termpermeabilities of many of the proppants tested in these studies are as much as50% less than were indicated by the previously published short-term values.Proppant-pack permeability also may be published short-term values.Proppant-pack permeability also may be impaired significantly by the gellingagents common in hydraulic fracturing fluids. Among the parameters known toaffect the degree of damage are the types and concentrations of the gellingagent, crosslinker, and breaker, as well as the reservoir closure stress andtemperature. Many researchers have attempted to quantify the damaging effectsof unconcentrated fracturing fluids on proppant-pack permeability. Cookecorrelated the effects of the proppant-pack permeability. Cooke correlated theeffects of the residue of various unconcentrated gelling agents to thepermeability reduction observed in short-term stressed proppant permeabilityreduction observed in short-term stressed proppant packs. That studydemonstrated a decrease in proppant-pack packs. That study demonstrated adecrease in proppant-pack permeability with increasing gelling-agent-residueconcentration. permeability with increasing gelling-agent-residueconcentration. Kim and Losacano examined the effects of unconcentratedcrosslinked fracturing fluids on the permeability of short-term stressedproppant packs in an API conductivity cell without leakoff. proppant packs inan API conductivity cell without leakoff. Permeability reductions of 30% to 50%were reported for polymer Permeability reductions of 30% to 50% were reportedfor polymer concentrations of 40 to 100 lbm/ 1,000 gal.
The gelling agents common in hydraulic fracturing treatments possessmolecular sizes too large to penetrate the matrix of possess molecular sizestoo large to penetrate the matrix of low-permeability formations. Therefore,the gelling agents are concentrated in the proppant pack as a result of fluidloss during the treatment and the volume reduction experienced during fractureclosure. Assuming that all the polymer remains in the proppant pack,postclosure polymer concentration factors may be calculated pack, postclosurepolymer concentration factors may be calculated from the PV with a Gasificationof Cooke's method:
where Cf = final polymer concentration, lbm/gal; Ci = initial polymerconcentration, lbm/gal (Cf/ci = polymer concentration factor, dimensionless); =proppant density, lbm/gal; Cs = proppant concentration in fluid, lbm/gal added;and = proppant-pack porosity, as a percent.
The final polymer concentration may be calculated by multiplying the initialpolymer concentration by the polymer concentration factor. Fig. 1 shows thepolymer concentration factor as a function of proppant concentration forvarying proppant-pack porosities. The fracture width is reduced by increasingthe closure stress, thus reducing the ratio of PV to proppant volume within thefracture and therefore the proppant-pack proppant volume within the fractureand therefore the proppant-pack porosity. For example, assume that, for a giventreatment, 50,000 gal of porosity. For example, assume that, for a giventreatment, 50,000 gal of 40-lbm/1,000-gal fracturing fluid was pumped to place150,000 lbm of 20/40-mesh proppant and that the proppant-pack porosity is 33.5%. Therefore, the average proppant concentration would be 3 lbm/gal. Fig. 1shows that, for a 3-lbm/gal proppant concentration, the postclosure polymerconcentration factor is about 15. Thus, the postclosure polymer polymerconcentration factor is about 15. Thus, the postclosure polymer concentrationwithin the proppant pack would be an average of about 15 times the initialpolymer concentration, or 600 lbm/ 1,000 gal. It is apparent from Fig. 1 thatthe polymer concentration in the proppant pack generally is much greater thanthe 40 to 100-lbm/ 1,000-gal polymer concentration evaluated in previousstudies.
Recent fracture conductivity studies have sought to evaluate theproppant-pack damage caused by concentrated treatment fluids when exposed torealistic environmental conditions. Penny and Parker and McDaniel reported theresults of sophisticated fracture conductivity tests that incorporated dynamicfluid loss, two-core leakoff, and long-term exposure to temperature and stress.The measured permeability reduction was a function of the dynamically formedfilter cake and the concentrated bulk fluid. Large reductions in theproppant-pack permeability were reported, particularly for crosslinked fluids.permeability were reported, particularly for crosslinked fluids. SPEPE
Although acidization has been used successfully for many years to increase the productivity of petroleum wells in carbonate formations, demands on the performance and application of the acidizing process are increasing. This study investigated a method of in-situ foam generation that allows deeper wormhole penetration yet uses less acid than conventional methods. The dissolution patterns were imaged with neutron radiography, which provided an in-depth understanding of the effects of foam and other critical parameters. Results show that foam is effective in promoting efficient stimulation, even at low acid injection rates. promoting efficient stimulation, even at low acid injection rates.
The acidizing technique was patented in 1895. The first successful acid job was performed in 1932 on a limestone formation in Michigan. Since then, acidizing has remained an important part of petroleum engineering. The acidizing process involves injection of acid into a wellbore to dissolve some of the surrounding formation rock. This dissolution allows better inflow of formation fluids, easier injection of completion fluids, or easier injection during secondary recovery. Most carbonate acidizations today are performed with HCl plus a mixture of corrosion inhibitors, penetration fluids, and other chemical additives. HCl is a strong acid penetration fluids, and other chemical additives. HCl is a strong acid that is mass-transfer-limited in its reaction with limestone at temperatures above 32F. Consequently, the rate of spending is a function of the rate of injection, and at small injection rates, the acid penetrates only a limited depth before consumption. This in turn causes excessive dissolution near the wellbore and prevents deep stimulation. The most obvious solution to this problem might appear to be the injection of acid at high rates. Pressure limitations, however, sometimes prevent high injection rates. More important, natural heterogeneities cause some formation zones to accept acid at very slow rates. These low-conductivity zones need stimulation the most.
Various solutions to this problem have been proposed, most of which incorporate some method to slow the acid's reaction with the rock. Acetic and formic acid react with limestone at a slower rate than HCl because of lower H + concentration. Chemical inhibitors also have been formulated to slow the rate of HCl consumption. Hoefner and Fogler developed a stable acid microemulsion that retarded acid diffusion and thus allowed deeper penetration of live acid. Coreflood experiments with the microemulsion penetration of live acid. Coreflood experiments with the microemulsion produced a breakthrough after injection of about 1 acid PV. While this produced a breakthrough after injection of about 1 acid PV. While this technique demonstrated the ability to stimulate carbonates at low injection rates, more cost-effective methods are needed.
This paper describes a method of acidizing in the presence of foam that allows deep stimulation yet uses less acid than previous techniques. The process begins with injection of an aqueous surfactant into a core sample. process begins with injection of an aqueous surfactant into a core sample. Foam is created during acidizing by injecting commingled acid (i.e., nitrogen and aqueous HCl injected simultaneously). Wormholes are formed by the same phenomena as in conventional acidizing, but the presence of foam prevents acid from spending outside the primary dissolution channel. prevents acid from spending outside the primary dissolution channel. Results show the formation of a conductive wormhole rather than dead-end branches. In addition, significant core-face erosion is not a problem, even at very low flow rates.
Neutron radiographs were used to study the structure of the wormholes generated by this and other methods. The wormholes created with foam consistently show uniform thickness with very little branching from the primary channel. The long, thin channels indicate the efficiency of this primary channel. The long, thin channels indicate the efficiency of this method, with some experiments producing a channel breakthrough after injection of less than 0.2 PV of 3 N HCl.
To understand the process of foamed acid stimulation, we must combine knowledge from two complex subjects: the transport of fluids through foam in porous media and the stochastic process of wormholing. The behavior of foam in porous media has been studied extensively. Research in carbonate acidizing has been more limited, although a fairly good understanding of the process has been gained in recent years. Few papers on the use of foams in stimulation contain results from actual acidizing experiments, and none of these papers demonstrates that foam can enhance the wormholing process. Some of the theories on these topics are discussed below.
Foams in Porous Media. Foamed fluids have been used in the field for more than 2 decades. Included in the wide range of applications are leakoff control in fracture acidizing, mobility control in waterflooding, flow diversion, and profile modification. The ability of a foam to provide mobility control and to prevent leakoff has prompted many theoretical studies into the structure, mechanism of formation, and transport properties of foams in porous media. Of these topics, the transport of properties of foams in porous media. Of these topics, the transport of liquid through foam is of the most concern to this work.
Foam exists in a porous medium as a two-phase system of gas and liquid. Liquid is generally the wetting phase and thus resides as a series of lamellae bridging across pore throats and as thin films on the rock's surface. Gas is a discontinuous phase, residing in the larger void spaces of the medium. The addition of a surfactant allows the foam to maintain a stable two-phase configuration in which the lamellae can break and reform during dynamic events. The texture of a foam refers to the number density of gas-phase bubbles. The quality of a foam is the volume percentage of the pore space occupied by the gas phase. Bernard et al. performed the initial work relating to liquid (water) transport through a foam and found that the liquid permeability of a porous medium does not depend on the foam structure but rather on only the fluid saturation. Thus, fluid leakoff could be prevented simply by the introduction of a second phase (e.g., gas). However, foams are generally considered to be especially effective in reducing liquid permeability because they provide a stable method of maintaining a low liquid saturation, even during the flow of surfactant-free water. Holm later showed that liquid flows through foam by means of continuous films and lamellae. The implication of this flow mechanism is that the smaller pores containing no foam (i.e., no gas) will carry the majority of the liquid flow. This concept contradicts single-phase models that proportion the amount of fluid flow to the diameter of channels in a porous medium.
Carbonate Acidizing. The stimulation of a carbonate is very different from the process that occurs in sandstone, primarily because the entire matrix of a carbonate rock is reactive. As a result, carbonate acidizing causes the formation of large flow channels (relative to the pore size) in some portions of the rock, while other portions are unaffected. This type of portions of the rock, while other portions are unaffected. This type of dissolution is extremely heterogeneous. Because of their macroscopic size, these flow channels are highly conductive to fluid, thus increasing the effective permeability of the medium. In contrast, the stimulation of sandstone causes pore-scale dissolution throughout the matrix so that the permeability is increased more homogeneously. permeability is increased more homogeneously.
Laboratory investigation of the interactions between fracturing fluids andresin-coated proppants (RCP's) revealed (among other conclusions) that RCP'sare incompatible with oxidizing breakers. Areas covered included RCP effect onfluid rheology, fluid relationship to RCP strength, theoretical study ofrequired RCP strengths to prevent flowback, and experimental measurement toestablish minimum strength.
This paper describes the use of curable RCP's in fracturing treatments.Their primary purpose is to prevent proppant flow from the fracture duringcleanup and production. The use of such materials is increasing rapidly, yetmany concerns exist in design and application of fluid systems. These include(1) the effect of various crosslinked fluid systems on the strength of thecured, consolidated sandpack, (2) breaking of the gel system, (3) temperatureeffects on the resin system during curing, (4) the closure stress required tocause consolidation, and (5) the compressive strength required to preventproppant flow from the fracture. Laboratory experiments have been conducted todetermine the effect of various components in crosslinked fluid systems on theconsolidation of curable RCP'S. Available RCP products and field- applied resinsystems were investigated under several different curing conditions. Extendedcuring before stress was applied resulted severely reduced strengths. Flowexperiments (through consolidated packs) with oil and water were conducted tocorrelate velocity/viscosity packs) with oil and water were conducted tocorrelate velocity/viscosity relationships and proppant flow from a pack. Fluidsystems and techniques for optimized use of curable RCP's are identified, andgel breaker requirements are presented. Compressive strengths obtained underfield conditions generally were much lower than commonly reported.
The use of plastic materials for sand consolidation in producing wells datesback to 1945, when a phenolic resin was used. Since then, use of variousmaterials, including phenolic, furan, and epoxy resin systems, has beendescribed for various sand-control applications. In 1975, the application ofcurable RCP with a phenolic-based system was patented. Literature pertaining tothe use of plastic materials to control sand production has focused on gravelpacking and sand control. During the last decade, proppant production fromhydraulically fractured wells has increased. One reason is the use of higherproppant concentrations during the treatment. To control this proppantconcentrations during the treatment. To control this proppant productioneconomically, the use of curable RCP has grown proppant productioneconomically, the use of curable RCP has grown from novelty status to standardpractice. During the recent growth of RCP application, conductivity,compressive strengths, and general effectiveness have been considered, but someareas of their application remain relatively unexplored. These areas includethe RCP's effect on the fracturing fluid, the fracturing fluid's effect on theRCP, and the amount of bonding strength required to hold the cured RCP in aproducing fracture. The objective of this research was not to generate fractureconductivity data or proppant crushing, but to provide better understandingbetween the interactions of fluid and RCP. In addressing these issues, werealized that common fracturing fluids and conditions influence the resultingstrengths of cured, consolidated RCP. A better understanding of proppantconsolidation was desired because the fluid and curing conditions of RCP affectstrength. Therefore, this paper discusses the RCP's effect on fluid rheology,the relationship of fluid to RCP strengths, the theoretical study of requiredRCP strengths to prevent proppant flowback, and experimental measurements toestablish minimum required strengths. Two general methods are now used duringfracturing treatments to consolidate proppant. The most widespread method isthe use of curable phenolic resins precoated on the proppant. In this case,products are manufactured and delivered to location. Two curable phenolic RCPproducts were evaluated in this study: RCP-A normally contains 4% resin andRCP-B normally contains two layers of resin, 2 % precured followed by 2 %curable resin. A new approach is an on-site coating method where requiredmaterials are to the fluid and allowed to coat the proppant during pumping.This system, RCP-C, uses an epoxy-based resin system. The concentration resinused in this system can be varied to adjust the compressive strength of theconsolidated proppant. A precured similar to RCP-A was used and is calledRCP-D.
RCP Effect on Fluids
The influence of RCP on fluid rheology related to crosslink time andviscosity was examined. The effect of RCP on breakers used oil to obtain acontrolled reduction of the fluid's viscosity also was examined. The first testseries examined the influence of RCP-A on the ambient-temperature fluidcrosslinking rate. In these tests, aluminum-, titanium-, and boron-crosslinkedfluids were examined to evaluate acidic, neutral, and basic fluid systems.Table 1 gives the times to crosslink to a "strong" state. From thesefluids tested, we concluded that RCP-A did not significantly influence thecrosslink rate of these fluids. The RCP effect on fluid viscosity was examinedat 170F for a linear gel and a titanium-crosslinked fluid. For evaluating theinteraction of RCP and base gel viscosity, a 100-lbm/1,000-gal solution ofhydroxypropyl guar (HPG) was monitored for I hour at 170F. Because solidproppant usually is not used directly in the Fann Model 50 TM viscometer, theinfluence of RCP on viscosity was determined by mixing either RCP-A or RCP-B at6 lbm/gal in the water used for preparing the gel and then removing the solidsbefore gelation. Because the water-soluble gel most likely would be influencedby water-soluble components from RCP-A or RCP-B. we decided that this techniquewas a reasonable experimental approach. The gel mix water was exposed for 24hours to RCP-A or RCP-B at ambient and 170F temperatures. In anotherexperiment, RCP-A was allowed to cure in air at 170F and then was exposed towater for an additional 24 hours at 170F to determine whether the cured RCP-Awould affect the break properties. Table 2 shows the results of these tests.The procedures described above were repeated with a 50-lbm/ 1,000-gal solutionof HPG. In this case, the base gel was crosslinked with a titanate crosslinkerbefore the viscosity profile was run for 1 hour at 170F. Table 2 shows thesedata. profile was run for 1 hour at 170F. Table 2 shows these data. Included inthis data set is an experiment where dust collected from pneumatic transfer ofRCP-B during a south Texas fracturing treatment was added directly to thecrosslinked fluid. We concluded that the chemical effects on base gel fromRCP-A or RCP-B are minimal but that the titanate-crosslinked system viscositypotentially could be reduced by 50% under these test conditions. potentiallycould be reduced by 50% under these test conditions. SPEPE