Laboratory Studies for Designing a Matrix Treatment Objectives of laboratory experiments Laboratory 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 performed 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 help design 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 tests Solubility tests are used to determine the amount of any material that is dissolved by a given sol vent. The The results are are given in weight weight percent. percent. The The solubility solubility of a rock rock sample in a particula particularr sol vent (acid) depends on the the mineralog mineralogyy of the rock. The total solubilit solubilityy is the sum sum of the solubilit solubility y of 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 test results. This method is only used if no other information is available. Mineral content is easily skewed by a variety of factors. ■
■
■
Solubility tests are performed under ideal laboratory conditions. The physical rock structure is destroyed when grinding the sample for the test. Consequently, all the minerals are in contact with a large excess of acid. During acidizing operations in the field, the effective solubility may be completely different because of the structure of the rock and the position of each mineral relative to the pore through which the acid flows. Carbonate is assumed to be equal to HCl solubility. However, solubility in 15% HCl includes not 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% HF acids, minus the solubility of the sample in HCl is only a rough approximation of the percent of clays in the formation. Silicates and other HF acid-soluble minerals are also included in the RMA solubility test. The percentage of micas, feldspars and quartz soluble in RMA can be many 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
■
Negligible solubility in either HCl or RMA normally means that the formation is composed almost entirely of quartz. Acid stimulation may still be viable if the skin damage that is known to be present is composed of acid-soluble material. However, this fact is not apparent from lab studies on clean formation samples.
Table 7-1. Solubility of Common Minerals in Acid Minerals
Chemical Composition
Solubility HCl
HCl + HF
SiO2
None
Low
Orthoclase
K(AlSi3O8)
None
Moderate
Microcline
K(AlSi3O8)
None
Moderate
Albite
Na(AlSi3O8)
None
Moderate
Plagioclase
Na, Ca (Al1 – 2 Si2 – 3 O8)
None
Moderate
Biotite
K (Mg, Fe)3 (AlSi3O10) (F, OH)2
None
Moderate
Muscovite
K Al2 (AlSi3O10) (F, OH)2
None
Moderate
Kaolinite
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
Calcite
CaCO3
High
High
Dolomite
CaMg(CO3)2
High
High
Ankerite
CaFe(CO3)2
High
High
Gypsum
CaSO4 – 2(H2O)
Low
Low
Anhydrite
CaSO4
Low
Low
Halite
NaCl
High
High
Moderate
Moderate
Quartz Feldspars
Micas
Clays
Carbonates
Scales
Iron oxides
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Fluid Selection Guide for Matrix Treatments
Petrographic study Knowledge of the petrography (description and classification) of the formation rock is essential to understanding the rock’s response to fluid injection. Understanding rock fluid interactions depends 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 to these questions and to give insight on how this affects flow through the rocks. Understanding basic concepts on the formation of sedimentary rocks will help in understanding the laboratory procedures.
Sedimentary rocks Most petroleum reservoirs are found in sedimentary rocks such as sandstones, carbonates or chalks. Sedimentary rocks form at, or near, the earth’s surface at relatively low temperatures and pressures through the transformation of sediments by diagenesis. Figure 7-1 is a schematic of the main 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).
Sandstone Coarse t n e m i d e S
Carbonate Rocks • Detrial grain – Fossils – Previously Framework deposited carbonates • Precipitated mineral – Calcite – Dolomite – Mud
• Detrial minerals – Quartz – Feldspar Framework – Micas
}
}
Fine
Diagenesis – Cementation – Compaction Transformation into a rock
• Clays Scattered in the framework or as laminae • Cement – Quartz – Clays – Calcite – Dolomite – Anhydrite Etc.
Rock Flow of brines – Dissolution – Recrystallization
– Transformation of clays – Crystallization of authigenic minerals Changes in porosity Permeability
Grain Cement
• Cement Calcite Dolomite
Pore
Dissolution of shells
Lining
– Transformation of calcite into dolomite – Selective dissolution
Changes in porosity Permeability
Filling Fracturation
Usually minor
Can be very important for reservoir properties
Figure 7-1. Formation of sandstone and carbonate rock—consequences for their flow properties.
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51
These three mechanisms coincide with the three main sediment constituents: ■
■
■
silicate fragments that are derived from the weathering and erosion of preexisting sedimentary, 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. Cementation results from the flow of brine through the original sediments. The brines dissolve some components and reprecipitate others between the grains of the framework. Cementation reduces the porosity of the sediments. Dissolution of cementing minerals will increase porosity but cause a decrease in compressive strength in the rock. Diagenesis stops when a nonreacting fluid, such as oil, fills the pore system during the formation of the hydrocarbon trap. Precipitated minerals are called authigenic, meaning formed in place. Most clays found in the pore network of sandstones are authigenic. In limestones, the transformation of calcite into dolomite by diagenisis results in new porosity. This transformation, called dolomitization, is described by the following mechanism: 2CaCO3 + MgCl2 → CaMg (CO3 )
2
+
CaCl2 .
Because of this process, dolomites normally have greater porosity than limestones.
Petrographic techniques Petrographic techniques include thin section examination, X-ray diffraction and scanning electron microscopy.
Thin section analysis Thin section analysis is a method used to study rock structure and quantify minerals. The technique can determine mineralogy, porosity types, grain size, sorting and location of pores, cementing minerals and clay fines. Rock core samples are impregnated with a colored resin to fill the interconnecting porosity. A thin slice is then cut off, polished to a thickness of about 30 microns and viewed in transmitted light with a polarizing microscope. Characteristic shape and size are used to identify the various minerals. The colored resin identifies interconnected porosity, while the isolated porosity shows up between the mineral crystals. The location of minerals is important in acidizing, because the injected solvent will only dissolve the minerals that it can contact. Therefore, only minerals available to the interconnected porosity will contact the acid. This holds true for both the damaging minerals, such as clay particles, or for cementing minerals, such as secondary quartz overgrowth and carbonates in sandstones. The objective is to dissolve as much of the damage as possible to improve flow capacity while dissolving as little of the cementing material as possible to maintain the integrity of the rock.
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Fluid Selection Guide for Matrix Treatments
X-ray diffraction X-ray diffraction (XRD) is used to identify rock composition. It is an analytical technique that looks at the scattering pattern of X-rays through crystalline materials. These patterns are unique to individual minerals because they are characteristic of their atomic structure. The XRD patterns from unknown materials are compared to known mineral patterns to determine the composition 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 contaminated with drilling fluids and may not be representative of the formation. If sidewall cores are used, the analysis should be conducted on duplicate cores.
Scanning electron microscopy Scanning electron microscopy (SEM) is another way of looking at solid particles. It provides two major advantages over light microscopy: depth of focus and range of magnification. It is designed for looking directly at the surface of solid objects, and it is particularly useful for the observation of clays. SEM pictures of clay particles show their distinct shapes. For example, illite is spindly and 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. The electrons are scanned across the surface and focused with a magnet. They cause the release of energy in the form of X-rays, light and electrons. Detectors record the energy released from the sample 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 the sample. This type of image emphasizes the topography of the sample. Back-scattered electron images (BEI) are produced from the high-energy electrons of the original beam focused on the sample and reflected back from it. This type of image accentuates the compositional differences of the sample.
Like XRD analysis, SEM testing requires the use of reservoir core samples. Conventional cores are recommended, because sidewall cores can be contaminated with drilling fluids and may not be representative of the formation. If sidewall cores are used, the analysis should be conducted on duplicate cores.
Computed tomography Computed tomography (CT) is a method for obtaining cross-sectional images of the internal structure of a solid object. Used extensively in the medical field, this technique is also useful for looking at the internal structure of cores. X-ray images are taken along sequential planes perpendicular to the length of the sample. Computers are used to enhance the visualization of the sample. The X-rays are focused across an area of the sample and recorded as a pattern of electrical impulses. The radiation absorption figures are used to assess the relative density of the interior of the sample. When plotted, the variation in density is shown as variations of brightness, producing a detailed cross-sectional image of the internal structure. An example of this technique in oilfield applications is the study of core samples before and after acid response tests. In carbonate cores, this can detail the formation of wormhole structures. In sandstone cores, the dissolution of materials within the pore structure can be visualized.
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53
Magnetic resonance imaging Magnetic resonance imaging (MRI) is another diagnostic technique borrowed from the medical field. It can be used to determine fluid distribution in core samples. The method uses the response of magnetic fields to short bursts of radio waves to produce the images. Like CT, MRI images 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 computer enhancement can be used to produce a three-dimensional visualization.
Petrophysics The petrophysic characterization of a rock sample includes measurements of its porosity and permeability.
Porosity Porosity is the ratio of the void space volume to the bulk volume of a material. It is a measurement of the amount of space occupied by liquid or gas in the reservoir. Total, effective and residual porosities are defined as follows: Total porosity (%) =
Pore volume Total bulk volume
Effective porosity (%) =
×
100
Volume of interconnected pores Total bulk volume
×
100 .
Residual porosity = Total porosity – effective porosity Pore volume = Total bulk volume – grain volume Effective 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 the three basic parameters, bulk, grain or pore volume, are measured in the laboratory. Bulk volume can be determined by either volumetric or gravimetric displacement observations. In either case, fluid penetration into the core sample should be avoided. Direct measurement of fluid displacement is one way of determining bulk volume. Gravimetric techniques measure 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 dividing 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 can also be reduced to grain size, and the actual grain density determined. The Stevens porosimeter can be used to determine the effective grain volume by using gas expansion. All methods of determining pore volume measure effective pore volume. The measurement methods 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 use either nitrogen or helium in a constant volume cell. Pore volume can also be determined by saturating a clean, dry sample with a fluid of known density. The weight gain is used to calculate pore volume.
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Fluid Selection Guide for Matrix Treatments
Porosity obtained from gas expansion methods is consistently higher than porosity obtained from saturation methods. Errors due to gas adsorption would tend to cause higher calculated porosities using the gas expansion method. Conversely, errors due to incomplete saturation would tend to cause lower calculated porosities using the saturation method. However, all methods give acceptably accurate answers if done carefully. (Bradley, 1987 Ch. 26)
Permeability Permeability is a measure of the capacity of a porous media to transmit fluids. It can be measured in situ through pressure transient testing and in the lab using cores. Fluid conductivity measurements using cores are made using gas or nonreactive liquids. Core permeabilities to air should not be confused with the effective permeability to the reservoir fluid. Air permeabilities may 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 the core is 100% saturated. However, absolute permeability measured by flowing gas through a core must be corrected for gas slippage, also called Klingenberg corrections. This is because permeability to gas varies with the pressure used for injection. The correction factor is determined by plotting gas permeability versus the reciprocal of the mean pressure. Multiple permeability versus pressure points should fall on a straight line. This line is extrapolated back to infinite mean pressure (1/ p = 0). The point of intersection with the permeability axis is the equivalent liquid permeability. Klingenberg and others determined that this equivalent liquid permeability is equal to the liquid permeability through the measured porous media (Bradley, 1987 Ch. 26). Core flow test
Core flow tests measure the effects of fluids injected into sandstone formations. Permeability is calculated as a function of time or pore volumes injected. Core flow tests can also determine the water sensitivity of the rock and examine the reaction of the formation to a proposed treating fluid or fluid sequence. Acid response curve test
In acid studies, the permeability change depends on the dissolution and precipitation reactions that occur. Observations that indicate what dissolves and what precipitates are extremely useful in 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 by the acid dissolution of carbonate components in solution. The flow rates used should ensure that the fluid movement has minimal effect on the movement of fines contained within the pore structure. Typically 17 to 30 pore volumes of test fluid are injected. This approximates a treatment of 125 gal/ft. The formation cores used are typically 1-in. diameter and 12-in. long. They should be cleaned with aqueous alcohol or ethylene glycol monobutyl ether solutions to remove traces of oil and ensure that they are water-wet. Using core holders with multiple pressure taps, the test can examine 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 response curve (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 acid injection. This may be due to calcium fluoride precipitation or fines release. Removal of calcite cementing materials by the HCl stage can result in release of fines. This is more detrimental in low-permeability cores. If large increases in permeability occur during HCl injection, with little response to mud acid, the mud acid stage may not be required. A smooth increase in permeability due to mud or clay acid indicates that the well is a good stimulation candidate.
Laboratory Studies for Designing a Matrix Treatment
55
2000 Mud acid 1600 3% NH4Cl 1200 Permeability (mD) 800 3% NH4Cl 400 0 0
300
600
900
1200
1500
Volume (mL)
Figure 7-2. Acid response curve of a core treated with HCl and mud acid sequence.
Core flow tests should not be used to estimate treatment fluid volumes. Volumes are based on the amount and type of damage. Since core flow tests are always run on restored-state, cleaned cores, there can be damage due to sample preparation. This unknown damage will skew any attempt to use these tests to estimate treating volumes. A petrographic study should be done in conjunction with any core flow studies. An accurate lithological breakdown is very helpful when interpreting acid response curves. SEM studies, both before and after fluid injection, can also be a valuable tool when determining the effect of the injected fluid. Sandstone permeability changes, in particular, depend on both dissolution and precipitation reactions. Observations that indicate what dissolves and what precipitates are extremely useful in selecting the best treating fluid sequence. Effluent analysis is another method that can be used to monitor the reactions that occur within the core. Water sensitivity test
Permeability measurements before and after fluid injection, especially brine, can give insights into the sensitivity of the formation clays to both fines migration and clay swelling. The typical procedure 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 calcium chloride followed by distilled water may cause clay swelling or migration. The sodium chloride followed by distilled water will typically cause clay migration in any sandstone core. Table 7-2 explains the permeability effects of each fluid step.
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Fluid Selection Guide for Matrix Treatments
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
Increase
In low-permeability cores, differences in adsorption may cause hexane’s permeability to be higher than those measured with isopropanol.
Decrease
May indicate contamination of the hexane or incomplete removal of water by isopropanol.
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 consolidated cores. Severe permeability loss indicates physical movement of clay particles. Failure of core to return to its previous permeability with isopropanol confirms particle movement.
Increase
Seldom noted
Decrease
Uncommon, but extremely sensitive cores may lose some permeability from clay movement
Increase
Seldom noted
Decrease
Fines migration
Isopropanol to hexane
Isopropanol to 3% CaCl2 brine
3% CaCl2 brine to distilled water
3% NaCl brine to distilled water
Fluid analyses Analyses of oil and formation brine provide useful information for fluid selection. Most fluid tests are used when determining the damage mechanism affecting the well. These tests are discussed in the “Damage identification” section. Oil compatibility studies should be made with planned treating fluids and formation oil to investigate the possibility of sludge or emulsion formation when the treating fluid, either live or spent, contacts the formation oil. The selection of treating fluid additives is based on the information obtained in compatibility tests.
Acid and oil compatibility Before pumping into the well, the compatibility between proposed treating fluids and formation fluids should always be tested. This testing will measure the tendencies to form emulsion or sludge, which can cause major problems if the treating fluid is incompatible with the formation, the rate of separation and the phase condition.
Laboratory Studies for Designing a Matrix Treatment
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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 the acid in the crude oil can be formed. These viscous emulsions are slow to return to the wellbore and, often, are never returned, especially in low-pressure wells. When this occurs, the emulsion stays in place in the formation and permanently blocks the flow channels. Therefore, it is better to 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 or nonionic surfactants may be used depending on the nature of the emulsion being treated. Some mechanically 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 optimization of 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 of asphaltenes, resins, paraffin waxes and other high-molecular-weight components. This material is 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 material to keep the precipitates from forming on contact with the acid. The acid system to be used in treating a formation should be tested with the crude oil to see if sludge will form. Tests to determine whether there is a tendency for a sludge to form, at laboratory conditions, is given in API Bulletin RP 42.
Damage identification Evaluation of solids or fluids taken out of the well can be useful in determining the damage mechanism affecting well performance. Knowing the damage mechanism is particularly important when treating sandstone reservoirs, since the objective is removal of damage. Testing the formation brine can help determine scaling tendencies and predict incompatibility during mixing with foreign brine. Oil samples can be tested for paraffin and asphalt content to estimate the possibility of damage from heavy hydrocarbon precipitation. Analysis of miscellaneous solid particles from the well can be useful in determining whether the problem is primarily organic or inorganic in nature. These tests can also help narrow down the type of scale.
Water analysis Analyses 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 uses of water analysis data in damage assessment includes examining scaling issues and looking at compatibility with other water that was injected into the reservoir. All water sources associated with the well, either produced or injected, must be tested. A typical analysis gives the ionic composition of the water. The standard techniques and procedures for oil field water analysis are given in API RP 45, Recommended Practice for Analysis of Oilfield Waters. The following parameters are typically measured: ■
58
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) Fluid Selection Guide for Matrix Treatments
■
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 equilibrium and can affect carbonate scaling tendencies pH—usually controlled by the CO2 /bicarbonate concentrations—it is used in identifying potential scaling or corrosion tendencies. This measurement should be made in the field at conditions as close to in situ as possible. The pH changes over time after sampling because of the 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 the StimCADE design program to estimate potential for scale. The program will handle one or two water sources and allows the user to specify the amount of mixing. Analysis of wellhead water samples is sufficient to predict scaling in surface equipment but may not be reliable for estimating downhole scaling. Pressure decreases as water is produced to the surface causing release of CO2 and precipitation of scales as the fluid rises. Bottomhole water samples, kept at native pressure 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, is Scale Control, Prediction and Treatment or How Companies Evaluate A Scaling Problem and What They Do Wrong by Oddo and Tomson, presented at the 1992 NACE (National Association of Corrosion Engineers) annual conference.
Paraffin and asphaltene content Paraffins 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 molecular weight. 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 contain –N, –O, –S, and metal ions. These dispersions are permeated with adsorbed maltene molecules giving the surface a high negative charge. If the negative surface charge comes in contact with a highly charged positive chemical species, an irreversible neutralization occurs. This neutralization destabilizes the micelle and causes precipitation of the asphaltenes. In addition to causing plugging, the precipitated asphaltene molecules can also help stabilize emulsions and sludges. 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 Test Method for n-Heptane Insolubles.
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Solids analysis An analysis of the solids scraped from the tubulars or brought up from the bottom of the well can be useful in determining what type of damage exists. This type of analysis can determine if there is 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 of sample
Examination of physical characteristics
Color Texture Friability Organic/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 of rotten eggs or lead acetate paper turns brown
Hydrogen sulfide gas suspect iron sulfide
If there is no reaction in cold HCl, immerse the sample in hot HCl
Sample dissolves and turns green or yellow and is magnetic
Suspect iron oxide
If there is no reaction in hot HCl, immerse a portion of the sample in mud acid (HCl/HF)
Sample dissolves
Suspect silica-based compound (e.g., sand or silt particle)
If there is no reaction in mud acid, immerse the sample in U42 or U104.
Sample dissolves (dissolution will be very slow)
Suspect barium or strontium sulfate
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Fluid Selection Guide for Matrix Treatments
Using lab data in fluid selection The 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 ineffective 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 wellbore may not be the optimum solution in sandstone formations. Petrographic and petrophysic studies are particularly important when the reservoir is sandstone. It is highly recommended that the mineralogy be defined since there is the potential for detrimental reaction precipitates when treating with hydrofluoric (HF) acids. The presence of swelling, migrating or HCl sensitive clays should be know when designing the treatment. These parameters 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 verify that the proposed treating fluid will not cause damage. Proper evaluation before pumping can save time, money and effort afterwards.
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