lab tests for stimulation.pdf

Objectives of laboratory experimentsLaboratory studies are used to

■ identify damage mechanisms ■ analyze the rock■ analyze the formation fluids■ select the optimum treating fluid and design.

Formation cores, samples of formation fluids and sometimes samples of the damaging material (organic deposit or scale) are the subject of laboratory studies. Various analyses are per-formed on these samples to obtain the information necessary for designing a matrix treatment.

Core analysis Core analysis, including flow testing, is an integral part of the laboratory study used to helpdesign a matrix treatment. Tests performed on cores can be classified as follows:

■ Chemical studies include solubility tests and calculation of iron dissolved in HCl.■ Petrographic studies include X-ray diffraction (XRD), binocular lens observation, thin section

examination and scanning electron microscopy (SEM).■ Petrophysic studies determine porosity and permeability.■ Core flow tests monitor the permeability response of the rock when different fluids are

injected.

Solubility testsSolubility tests are used to determine the amount of any material that is dissolved by a given sol-vent. The results are given in weight percent. The solubility of a rock sample in a particular sol-vent (acid) depends on the mineralogy of the rock. The total solubility is the sum of the solubilityof the mineral components. Table 7-1 shows the solubility of various common minerals in acid.

Carbonate and clay mineral content of the rock are often estimated from solubility testresults. This method is only used if no other information is available. Mineral content is easilyskewed by a variety of factors.

■ Solubility tests are performed under ideal laboratory conditions. The physical rock structureis destroyed when grinding the sample for the test. Consequently, all the minerals are in con-tact with a large excess of acid. During acidizing operations in the field, the effective solubil-ity may be completely different because of the structure of the rock and the position of eachmineral relative to the pore through which the acid flows.

■ Carbonate is assumed to be equal to HCl solubility. However, solubility in 15% HCl includesnot only carbonates but also halite and possibly anhydrites and iron compounds.

■ The solubility of the sample in regular mud acid (RMA), a mixture of 12% HCl and 3% HFacids, minus the solubility of the sample in HCl is only a rough approximation of the percentof clays in the formation. Silicates and other HF acid-soluble minerals are also included in theRMA solubility test. The percentage of micas, feldspars and quartz soluble in RMA can bemany times that of the clays. A large difference between the solubilities in HCl versus RMA(>30%) normally indicates that there is a large amount of clays, micas and feldspars present.

Fluid Selection Guide for Matrix Treatments ■ Laboratory Studies for Designing a Matrix Treatment 49

Laboratory Studies for Designing a Matrix Treatment

50 Fluid Selection Guide for Matrix Treatments

■ Negligible solubility in either HCl or RMA normally means that the formation is composedalmost entirely of quartz. Acid stimulation may still be viable if the skin damage that is knownto be present is composed of acid-soluble material. However, this fact is not apparent from labstudies on clean formation samples.

Table 7-1. Solubility of Common Minerals in Acid

Minerals Chemical Composition Solubility

HCl HCl + HF

Quartz SiO2 None Low

FeldsparsOrthoclase K(AlSi3O8) None Moderate

Microcline K(AlSi3O8) None Moderate

Albite Na(AlSi3O8) None Moderate

Plagioclase Na, Ca (Al1 – 2 Si2 – 3 O8) None Moderate

MicasBiotite K (Mg, Fe)3 (AlSi3O10) (F, OH)2 None Moderate

Muscovite K Al2 (AlSi3O10) (F, OH)2 None Moderate

ClaysKaolinite Al4Si4O10 (OH)8 None High

Illite (K,H3O)(Al,Mg,Fe)2 (Al4Si4O10) [(OH)2 • H2O] Moderate High

Smectite (Na, Ca)(Al, Mg)6 (Si4O10)3(OH)6 – nH2O None High

Mixed layer Kaolinite, illite or chlorite with smectite None High

Chlorite (Fe, Mg, Al)6 (Si, Al)4 O10 (OH)8 Moderate High

Glauconite (K, Na)(Fe, Al, Mg)2 (Si,Al)4 O10 (OH)2 Moderate High

Zeolites (Ca, Na) AlSiO6 – H2O (general) High High

CarbonatesCalcite CaCO3 High High

Dolomite CaMg(CO3)2 High High

Ankerite CaFe(CO3)2 High High

ScalesGypsum CaSO4 – 2(H2O) Low Low

Anhydrite CaSO4 Low Low

Halite NaCl High High

Iron oxides Moderate Moderate

Laboratory Studies for Designing a Matrix Treatment 51

Petrographic studyKnowledge of the petrography (description and classification) of the formation rock is essentialto understanding the rock’s response to fluid injection. Understanding rock fluid interactionsdepends upon

■ what minerals are present■ where the minerals are located relative to the path of the injected fluid.

The laboratory techniques described in this chapter are used to determine the answers tothese questions and to give insight on how this affects flow through the rocks. Understandingbasic concepts on the formation of sedimentary rocks will help in understanding the laboratoryprocedures.

Sedimentary rocksMost petroleum reservoirs are found in sedimentary rocks such as sandstones, carbonates orchalks. Sedimentary rocks form at, or near, the earth’s surface at relatively low temperatures andpressures through the transformation of sediments by diagenesis. Figure 7-1 is a schematic of themain steps of sedimentary rock formation and their consequence on the flow properties.

Sediments are

■ deposited by water, wind or ice■ precipitated from solution ■ grown in position by organic processes (e.g., carbonate reefs).

Figure 7-1. Formation of sandstone and carbonate rock—consequences for their flow properties.

Coarse

Fine

• Detrial minerals– Quartz– Feldspar– Micas

• ClaysScattered inthe frameworkor as laminae

Framework

– Cementation

– Compaction

Transformation into a rock

• Cement – Quartz– Clays– Calcite– Dolomite– Anhydrite Etc.

Flow of brines– Dissolution– Recrystallization

– Transformation of clays– Crystallization of

authigenic mineralsChanges in porosityPermeability

Fracturation Usually minor

Dissolution of shells – Transformation of calcite into dolomite– Selective dissolution

Changes in porosityPermeability

Can be very importantfor reservoir properties

• Detrial grain– Fossils– Previously deposited

carbonates• Precipitated mineral

– Calcite– Dolomite– Mud

• CementCalciteDolomite

Carbonate RocksSandstone

Sedi

men

t

DiagenesisGrain

Cement

Pore

Lining

Filling

Framework

Rock

} }

These three mechanisms coincide with the three main sediment constituents:

■ silicate fragments that are derived from the weathering and erosion of preexisting sedimen-tary, metamorphic or igneous rocks

■ chemical and biochemical precipitates that are formed at the site of deposition, for example,evaporite minerals or cement in sandstones or limestones

■ allochems that are skeletal materials, ooliths, faecal pellets, as seen in carbonates.

The coarse particles (0.06 mm–2 mm) form the framework of the sediments. Smaller particles(clays, lime, mud) are also deposited. The original porosity of the sediment depends on the

■ size of the particles■ shape (sphericity) of the particles ■ packing of the particles■ amount of mixing of coarse and fine grains.

During diagenesis, a cementation process transforms the sediment into rock. Cementationresults from the flow of brine through the original sediments. The brines dissolve some compo-nents and reprecipitate others between the grains of the framework. Cementation reduces theporosity of the sediments. Dissolution of cementing minerals will increase porosity but cause adecrease in compressive strength in the rock. Diagenesis stops when a nonreacting fluid, such asoil, fills the pore system during the formation of the hydrocarbon trap.

Precipitated minerals are called authigenic, meaning formed in place. Most clays found in thepore network of sandstones are authigenic. In limestones, the transformation of calcite intodolomite by diagenisis results in new porosity. This transformation, called dolomitization, isdescribed by the following mechanism:

Because of this process, dolomites normally have greater porosity than limestones.

Petrographic techniquesPetrographic techniques include thin section examination, X-ray diffraction and scanning electron microscopy.

Thin section analysisThin section analysis is a method used to study rock structure and quantify minerals. The tech-nique can determine mineralogy, porosity types, grain size, sorting and location of pores, cement-ing minerals and clay fines.

Rock core samples are impregnated with a colored resin to fill the interconnecting porosity. Athin slice is then cut off, polished to a thickness of about 30 microns and viewed in transmittedlight with a polarizing microscope. Characteristic shape and size are used to identify the variousminerals. The colored resin identifies interconnected porosity, while the isolated porosity showsup between the mineral crystals.

The location of minerals is important in acidizing, because the injected solvent will only dis-solve the minerals that it can contact. Therefore, only minerals available to the interconnectedporosity will contact the acid. This holds true for both the damaging minerals, such as clay par-ticles, or for cementing minerals, such as secondary quartz overgrowth and carbonates in sand-stones. The objective is to dissolve as much of the damage as possible to improve flow capacitywhile dissolving as little of the cementing material as possible to maintain the integrity of the rock.


2 3 2 3 2 2CaCO MgCl CaMg CO CaCl+ → ( ) + .

X-ray diffractionX-ray diffraction (XRD) is used to identify rock composition. It is an analytical technique thatlooks at the scattering pattern of X-rays through crystalline materials. These patterns are uniqueto individual minerals because they are characteristic of their atomic structure. The XRD pat-terns from unknown materials are compared to known mineral patterns to determine the com-position of the unknown solid. Crystalline scale deposits can also be identified using XRD.

XRD is a very accurate way of qualitatively determining the mineral composition. However,quantitative accuracy is relatively poor. This type of testing requires the use of reservoir core samples. Conventional cores are recommended, because sidewall cores can be contaminatedwith drilling fluids and may not be representative of the formation. If sidewall cores are used, theanalysis should be conducted on duplicate cores.

Scanning electron microscopyScanning electron microscopy (SEM) is another way of looking at solid particles. It provides twomajor advantages over light microscopy: depth of focus and range of magnification. It is designedfor looking directly at the surface of solid objects, and it is particularly useful for the observationof clays. SEM pictures of clay particles show their distinct shapes. For example, illite is spindlyand kaolinite has a plate-like structure (Fig. 4-2).

With SEM, electrons, instead of light, are used to produce a reflected image of the sample. Theelectrons are scanned across the surface and focused with a magnet. They cause the release ofenergy in the form of X-rays, light and electrons. Detectors record the energy released from thesample and convert it into digital or photographic images.

The types of images of interest to geologists and engineers in the petroleum industry are

■ secondary electron images (SEI) generated from the low-energy electrons released from thesample. This type of image emphasizes the topography of the sample.

■ Back-scattered electron images (BEI) are produced from the high-energy electrons of theoriginal beam focused on the sample and reflected back from it. This type of image accentu-ates the compositional differences of the sample.

Like XRD analysis, SEM testing requires the use of reservoir core samples. Conventional coresare recommended, because sidewall cores can be contaminated with drilling fluids and may notbe representative of the formation. If sidewall cores are used, the analysis should be conductedon duplicate cores.

Computed tomographyComputed tomography (CT) is a method for obtaining cross-sectional images of the internalstructure of a solid object. Used extensively in the medical field, this technique is also useful forlooking at the internal structure of cores. X-ray images are taken along sequential planes per-pendicular to the length of the sample. Computers are used to enhance the visualization of thesample.

The X-rays are focused across an area of the sample and recorded as a pattern of electricalimpulses. The radiation absorption figures are used to assess the relative density of the interiorof the sample. When plotted, the variation in density is shown as variations of brightness, pro-ducing a detailed cross-sectional image of the internal structure.

An example of this technique in oilfield applications is the study of core samples before andafter acid response tests. In carbonate cores, this can detail the formation of wormhole struc-tures. In sandstone cores, the dissolution of materials within the pore structure can be visualized.


Magnetic resonance imagingMagnetic resonance imaging (MRI) is another diagnostic technique borrowed from the medicalfield. It can be used to determine fluid distribution in core samples. The method uses theresponse of magnetic fields to short bursts of radio waves to produce the images. Like CT, MRIimages are two-dimensional, cross-sectional, planar views perpendicular to the length of the sample. The images must be viewed sequentially to visualize the whole core. Additional computerenhancement can be used to produce a three-dimensional visualization.

PetrophysicsThe petrophysic characterization of a rock sample includes measurements of its porosity and permeability.

PorosityPorosity is the ratio of the void space volume to the bulk volume of a material. It is a measure-ment of the amount of space occupied by liquid or gas in the reservoir. Total, effective and resid-ual porosities are defined as follows:

Residual porosity = Total porosity – effective porosityPore volume = Total bulk volume – grain volumeEffective pore volume = Volume of interconnected pores = Total bulk volume – effective grain volume

The porosity of the sample can be determined by several techniques. Typically, only two of thethree basic parameters, bulk, grain or pore volume, are measured in the laboratory.

Bulk volume can be determined by either volumetric or gravimetric displacement observa-tions. In either case, fluid penetration into the core sample should be avoided. Direct measure-ment of fluid displacement is one way of determining bulk volume. Gravimetric techniquesmeasure either

■ the weight loss of the sample when it is immersed, or ■ the difference in weight of a pycnometer when it is filled with fluid and when it is filled with

fluid and the core sample.

Grain volume is the measure of the volume of the rock grains. This value is estimated by divid-ing the dry weight of the core sample by the sand grain density. Using the density of quartz, 2.65 g/cm3, for the sand grain density is sufficient for most applications. However, the sample canalso be reduced to grain size, and the actual grain density determined. The Stevens porosimetercan be used to determine the effective grain volume by using gas expansion.

All methods of determining pore volume measure effective pore volume. The measurementmethods are based on either extraction of fluid from, or injection of fluid into, the rock matrix.The procedures for determining pore volume by gas expansion are based on Boyle’s law and useeither nitrogen or helium in a constant volume cell. Pore volume can also be determined bysaturating a clean, dry sample with a fluid of known density. The weight gain is used to calculatepore volume.


Total

Effective

porosity (%) = Pore volume

Total bulk volume

porosity (%) = Volume of interconnected pores

Total bulk volume

×

×

100

100 .

Porosity obtained from gas expansion methods is consistently higher than porosity obtainedfrom saturation methods. Errors due to gas adsorption would tend to cause higher calculatedporosities using the gas expansion method. Conversely, errors due to incomplete saturation wouldtend to cause lower calculated porosities using the saturation method. However, all methods giveacceptably accurate answers if done carefully. (Bradley, 1987 Ch. 26)

PermeabilityPermeability is a measure of the capacity of a porous media to transmit fluids. It can be measuredin situ through pressure transient testing and in the lab using cores. Fluid conductivity mea-surements using cores are made using gas or nonreactive liquids. Core permeabilities to airshould not be confused with the effective permeability to the reservoir fluid. Air permeabilitiesmay be an order of magnitude higher than reservoir permeability to fluid.

Absolute permeability is a rock property and should be constant for liquid and gas, since thecore is 100% saturated. However, absolute permeability measured by flowing gas through a coremust be corrected for gas slippage, also called Klingenberg corrections. This is because perme-ability to gas varies with the pressure used for injection. The correction factor is determinedby plotting gas permeability versus the reciprocal of the mean pressure. Multiple permeabilityversus pressure points should fall on a straight line. This line is extrapolated back to infinitemean pressure (1/p = 0). The point of intersection with the permeability axis is the equivalentliquid permeability. Klingenberg and others determined that this equivalent liquid permeabilityis equal to the liquid permeability through the measured porous media (Bradley, 1987 Ch. 26).

Core flow testCore flow tests measure the effects of fluids injected into sandstone formations. Permeability iscalculated as a function of time or pore volumes injected. Core flow tests can also determine thewater sensitivity of the rock and examine the reaction of the formation to a proposed treatingfluid or fluid sequence.

Acid response curve testIn acid studies, the permeability change depends on the dissolution and precipitation reactionsthat occur. Observations that indicate what dissolves and what precipitates are extremely usefulin selecting the best treatment fluid.

The tests should be run at bottomhole temperature and pressure conditions with backpressure.For tests with acid, a minimum of 1000-psi backpressure is required to keep the CO2 produced bythe acid dissolution of carbonate components in solution. The flow rates used should ensure thatthe fluid movement has minimal effect on the movement of fines contained within the pore struc-ture. Typically 17 to 30 pore volumes of test fluid are injected. This approximates a treatment of125 gal/ft.

The formation cores used are typically 1-in. diameter and 12-in. long. They should be cleanedwith aqueous alcohol or ethylene glycol monobutyl ether solutions to remove traces of oil andensure that they are water-wet. Using core holders with multiple pressure taps, the test canexamine the effect of each fluid as it penetrates deeper into the core.

Permeability is calculated based on the changes in pressure and plotted as an acid responsecurve (ARC). An example of this is shown in Fig. 7-2.

The decrease in permeability seen in Fig. 7-2 indicates probable damage due to mud acidinjection. This may be due to calcium fluoride precipitation or fines release. Removal of calcitecementing materials by the HCl stage can result in release of fines. This is more detrimental inlow-permeability cores. If large increases in permeability occur during HCl injection, with littleresponse to mud acid, the mud acid stage may not be required. A smooth increase in permeabil-ity due to mud or clay acid indicates that the well is a good stimulation candidate.


Core flow tests should not be used to estimate treatment fluid volumes. Volumes are based onthe amount and type of damage. Since core flow tests are always run on restored-state, cleanedcores, there can be damage due to sample preparation. This unknown damage will skew anyattempt to use these tests to estimate treating volumes.

A petrographic study should be done in conjunction with any core flow studies. An accuratelithological breakdown is very helpful when interpreting acid response curves. SEM studies, bothbefore and after fluid injection, can also be a valuable tool when determining the effect of theinjected fluid. Sandstone permeability changes, in particular, depend on both dissolution andprecipitation reactions. Observations that indicate what dissolves and what precipitatesare extremely useful in selecting the best treating fluid sequence. Effluent analysis is anothermethod that can be used to monitor the reactions that occur within the core.

Water sensitivity testPermeability measurements before and after fluid injection, especially brine, can give insightsinto the sensitivity of the formation clays to both fines migration and clay swelling. The typicalprocedure calls for sequential injection of the following fluids:

■ n-hexane■ isopropanol■ n-hexane■ isopropanol■ 3% CaCl2

■ distilled water■ 3% NaCl■ distilled water.

The solvent steps are designed to remove oil and water residues from the core. The calciumchloride followed by distilled water may cause clay swelling or migration. The sodium chloridefollowed by distilled water will typically cause clay migration in any sandstone core. Table 7-2explains the permeability effects of each fluid step.


Figure 7-2. Acid response curve of a core treated with HCl and mud acid sequence.

Volume (mL)

Permeability (mD)

3% NH4Cl

3% NH4Cl

Mud acid

2000

1600

1200

800

400

00 300 600 900 1200 1500

Fluid analysesAnalyses of oil and formation brine provide useful information for fluid selection. Most fluid testsare used when determining the damage mechanism affecting the well. These tests are discussedin the “Damage identification” section. Oil compatibility studies should be made with plannedtreating fluids and formation oil to investigate the possibility of sludge or emulsion formationwhen the treating fluid, either live or spent, contacts the formation oil. The selection of treatingfluid additives is based on the information obtained in compatibility tests.

Acid and oil compatibilityBefore pumping into the well, the compatibility between proposed treating fluids and formationfluids should always be tested. This testing will measure the tendencies to form emulsion orsludge, which can cause major problems if the treating fluid is incompatible with the formation,the rate of separation and the phase condition.


Table 7-2. Explanation of Permeability Changes in a Water Sensitivity Test

Fluid Sequence Change Meaning

Hexane to isopropanol Increase Improved cleaning of core, removal of water and/or alcohol-soluble salts

Decrease May indicate incomplete removal of oil residue. In very low-permeability cores, adsorption of alcohol on pore walls may reduce capillary flow. Wettability factors may contribute

Isopropanol to hexane Increase In low-permeability cores, differences in adsorptionmay cause hexane’s permeability to be higher thanthose measured with isopropanol.

Decrease May indicate contamination of the hexane or incomplete removal of water by isopropanol.

Isopropanol to 3% CaCl2 brine Increase Seldom noted

Decrease Common. The decline may be due to strong adsorptionof water molecules on pore surfaces and partial expansion of clay aggregates. Some disintegration may occur in poorly consolidatedcores. Severe permeability loss indicates physicalmovement of clay particles. Failure of core to returnto its previous permeability with isopropanol confirms particle movement.

3% CaCl2 brine to distilled water Increase Seldom noted

Decrease Uncommon, but extremely sensitive cores may lose some permeability from clay movement

3% NaCl brine to distilled water Increase Seldom noted

Decrease Fines migration

Many types of emulsifying agents occur naturally in crude oils. When formation fluids are contacted by treating fluids, emulsions of varying degrees of stability may result. For example,during treatment of an oil well, as the acid is being forced into the formation, an emulsion of theacid in the crude oil can be formed. These viscous emulsions are slow to return to the wellboreand, often, are never returned, especially in low-pressure wells. When this occurs, the emulsionstays in place in the formation and permanently blocks the flow channels. Therefore, it is betterto prevent the emulsion by proper acid plus oil compatibility testing before the treatment.Although emulsions can be broken if they are already in the formation, this is more difficult.

Surfactants and mutual solvents are generally used to treat emulsions. Cationic, anionic ornonionic surfactants may be used depending on the nature of the emulsion being treated. Somemechanically stabilized emulsions may be treated by acidizing the formation to dissolve the stabilizing fines.

The potential for the formation of acid and produced crude oil emulsions and the optimizationof the de-emulsifier treatment are currently evaluated using API Recommended Procedure RP 42(1977).

Crude oil sludge is a name given to the black asphalt-like material that precipitates when certain crude oils come in contact with acid. The precipitate is complex consisting ofasphaltenes, resins, paraffin waxes and other high-molecular-weight components. This materialis present in the crude oil in a colloidal dispersion. Contact with the acid destroys the stability of the dispersed material and results in its precipitation.

Surfactants are generally used as sludge prevention agents. They stabilize the colloidal mate-rial to keep the precipitates from forming on contact with the acid. The acid system to be usedin treating a formation should be tested with the crude oil to see if sludge will form. Tests todetermine whether there is a tendency for a sludge to form, at laboratory conditions, is given inAPI Bulletin RP 42.

Damage identificationEvaluation of solids or fluids taken out of the well can be useful in determining the damage mech-anism affecting well performance. Knowing the damage mechanism is particularly importantwhen treating sandstone reservoirs, since the objective is removal of damage. Testing the forma-tion brine can help determine scaling tendencies and predict incompatibility during mixing withforeign brine. Oil samples can be tested for paraffin and asphalt content to estimate the possi-bility of damage from heavy hydrocarbon precipitation. Analysis of miscellaneous solid particlesfrom the well can be useful in determining whether the problem is primarily organic or inorganicin nature. These tests can also help narrow down the type of scale.

Water analysisAnalyses of oilfield waters are used for a variety of reasons. They are helpful when trying to

identify the source of downhole water and when planning waterflood operations. The main usesof water analysis data in damage assessment includes examining scaling issues and looking atcompatibility with other water that was injected into the reservoir. All water sources associatedwith the well, either produced or injected, must be tested.

A typical analysis gives the ionic composition of the water. The standard techniques and pro-cedures for oil field water analysis are given in API RP 45, Recommended Practice for Analysisof Oilfield Waters.

The following parameters are typically measured:

■ major cations—positive ions associated with the minerals dissolved in the water – most common cations—sodium (Na), calcium (Ca), and magnesium (Mg) Concentration

of these ions can vary from <1000 mg/L to >30,000 mg/L. – fairly typical cations—potassium (K), barium (Ba), strontium (Sr), and lithium (Li) with

concentrations in excess of 10 mg/L– cations sometimes present—aluminum (Al), ammonium (NH4), iron (Fe), lead (Pb),

managnese (Mn), and zinc (Zn)


■ major anions—negative ions associated with minerals dissolved in the water– most common anions—chloride (Cl), concentrations can vary from below 10,000 mg/L to

over 200,000 mg/L– other major anions—bicarbonate (HCO3) and sulfate (SO4) found in concentrations up to

several thousand mg/L Bicarbonate and sulfate concentrations are important in scaling.– fairly typical anions—bromide and iodide with concentrations ranging from less than 50 to

more than 6000 mg/L for bromide and less than 10 to more than 1400 mg/L for iodide

■ mole fraction of CO2—the amount of this dissolved gas is important in carbonate equilibriumand can affect carbonate scaling tendencies

■ pH—usually controlled by the CO2/bicarbonate concentrations—it is used in identifyingpotential scaling or corrosion tendencies. This measurement should be made in the field atconditions as close to in situ as possible. The pH changes over time after sampling because ofthe formation of carbonate ions due to the decomposition of bicarbonate.

Once the composition is obtained, it can be input into the Scale Prediction module in theStimCADE design program to estimate potential for scale. The program will handle one or twowater sources and allows the user to specify the amount of mixing. Analysis of wellhead watersamples is sufficient to predict scaling in surface equipment but may not be reliable for estimat-ing downhole scaling. Pressure decreases as water is produced to the surface causing release ofCO2 and precipitation of scales as the fluid rises. Bottomhole water samples, kept at native pres-sure and temperature conditions, are necessary for more reliable downhole scaling tendencies.

Proper sampling, transfer and storage procedures are necessary in order to obtain data representative of the well conditions. A good paper, which includes a discussion on sampling, isScale Control, Prediction and Treatment or How Companies Evaluate A Scaling Problem andWhat They Do Wrong by Oddo and Tomson, presented at the 1992 NACE (National Association ofCorrosion Engineers) annual conference.

Paraffin and asphaltene contentParaffins are straight- or branched-chain nonpolar alkanes of relatively high-molecular weight.Their chains usually consist of 20 to 60 carbon atoms with a melting range of 98° to 215°F [36°to 101°C]. The solubility of paraffin waxes in crude oil is limited depending on the molecularweight. Because of the limited solubility, a cooling environment can cause crystallization and precipitation. One standard test method for paraffin content is UOP 46.

Asphaltenes are colloidal aggregates of condensed, polycylic aromatic hydrocarbons that con-tain –N, –O, –S, and metal ions. These dispersions are permeated with adsorbed maltene mole-cules giving the surface a high negative charge. If the negative surface charge comes in contactwith a highly charged positive chemical species, an irreversible neutralization occurs. This neu-tralization destabilizes the micelle and causes precipitation of the asphaltenes. In addition to causing plugging, the precipitated asphaltene molecules can also help stabilize emulsions andsludges. The asphaltene content of a crude oil can be estimated because they are insoluble in certain solvents. The ASTM standard test method for asphaltene is D3279-90 Standard TestMethod for n-Heptane Insolubles.


Solids analysisAn analysis of the solids scraped from the tubulars or brought up from the bottom of the well canbe useful in determining what type of damage exists. This type of analysis can determine if thereis scale, an organic deposit or formation fines.

Common laboratory analysis procedures are shown in Table 7-3.


Table 7-3. Solids Analysis Procedure

Procedure Result Indication

Visual inspection Examination of physical characteristics Colorof sample Texture

FriabilityOrganic/inorganic

Heating of sample Ignition Oil or organic matter

Clean flame Suspect paraffin

Sooty flame Suspect asphaltene

Noisy flame (i.e., pops and sparks) Contains water

Immersion in water Sample dissolves Suspect inorganic salt (typically NaCl)

Immersion in cold HCl Sample dissolves and gives off odorless gas CO2

Acid doesn’t change color Suspect calcium or magnesium carbonate

Acid doesn’t change color but sample slowly dissolves Suspect calcium sulfate

Acid turns green or yellow and sample is magnetic Suspect iron carbonate

Sample dissolves and gives off gas that smells Hydrogen sulfide gasof rotten eggs or lead acetate paper turns brown suspect iron sulfide

If there is no reaction in Sample dissolves and turns green or yellow Suspect iron oxide cold HCl, immerse the and is magneticsample in hot HCl

If there is no reaction in Sample dissolves Suspect silica-based hot HCl, immerse a compound (e.g., sand or portion of the sample silt particle)in mud acid (HCl/HF)

If there is no reaction in Sample dissolves (dissolution will be very slow) Suspect barium or mud acid, immerse the strontium sulfatesample in U42 or U104.

Using lab data in fluid selectionThe previous section shows how laboratory tests can be used to determine damage mechanisms.This is an important step in selecting the proper fluid to treat the well. Acids would be ineffec-tive in treating paraffins or emulsions. Organic solvents would be recommended in these cases.Likewise, the use of mud acids for treating simple HCl soluble scales, such as calcite, in the well-bore may not be the optimum solution in sandstone formations.

Petrographic and petrophysic studies are particularly important when the reservoir is sand-stone. It is highly recommended that the mineralogy be defined since there is the potential fordetrimental reaction precipitates when treating with hydrofluoric (HF) acids. The presence ofswelling, migrating or HCl sensitive clays should be know when designing the treatment. Theseparameters will influence the type of fluid chosen and the acid strength recommended.

Finally, compatibility testing is necessary to optimize the acid additive package and to verifythat the proposed treating fluid will not cause damage. Proper evaluation before pumping cansave time, money and effort afterwards.


lab tests for stimulation.pdf

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