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Measurment of Water Activity from Shales Througt Thermohigrometer

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Resumo Este trabalho apresenta os resultados de uma campanha de ensaios laboratoriais para obter a atividade química de folhelhos e do fluido dos poros originados de bacias sedimentares terrestres e marítimas. Os resultados das atividades químicas dos folhelhos estudados variaram de 0,754 a 0,923 e para os fluidos dos poros entre 0,940 a 0,987. Os resultados mostram que a atividade química medida através do equipamento no fluido dos poros pode ser quantificada em seis dias e 10 dias para a amostra de folhelho. O grau de saturação, teor de umidade, tipo e teor de argilominerais expansíveis e hidratáveis, porosidade total e interconectada, salinidade do fluido dos poros e pressões capilares das amostras dos folhelhos afetaram os resultados da atividade química. Abstract This paper presents a campaign of lab tests to obtain the water activity from shales and it's pore fluid originated from offshore and onshore basin. The results of water activity from shales indicate that the values rang from 0.754 to 0.923 and for the pore fluid are between 0.987 and 0.940. The results show that the water activity of interstitial water can be obtained in 6 days and the rock in 10 days using the thermohygrometer used. The degree of saturation, water content, kind and tenor of expansible and hydratable clay mineral, total and interconnected porosity, salinity of interstitial fluid and the capillary pressure of shale samples affected the results of water activity.
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______________________________
1 Ph.D., Petroleum Geomechanics – GTEP/DEC/PUC-Rio
IBP025 04
MEASUREMENT OF WATER ACTIVITY FROM SHALES
THROUGH THERMOHIGROMETE
R
Claudio Rabe1
Copyright 2004, Instituto Brasileiro de Petróleo e Gás - IBP
This Technical Paper was prepared for presentation at the Rio Oil & Gas Expo and Conference 2004, held between 4 and 7 October 2004, in Rio de
Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event according to the information contained in the
abstract submitted by the author(s). The contents of the Technical Paper, as presented, were not reviewed by IBP. The organizers are not supposed to
translate or correct the submitted papers. The material as it is presented, does not necessarily represent Instituto Brasileiro de Petróleo e Gás’ opinion,
nor that of its Members or Representatives. Authors consent to the publication of this Technical Paper in the Rio Oil & Gas Expo and Conference
2004 Annals.
Resumo
Este trabalho apresenta os resultados de uma campanha de ensaios laboratoriais para obter a atividade química de
folhelhos e do fluido dos poros originados de bacias sedimentares terrestres e marítimas. Os resultados das atividades
químicas dos folhelhos estudados variaram de 0,754 a 0,923 e para os fluidos dos poros entre 0,940 a 0,987. Os
resultados mostram que a atividade química medida através do equipamento no fluido dos poros pode ser quantificada
em seis dias e 10 dias para a amostra de folhelho. O grau de saturação, teor de umidade, tipo e teor de argilominerais
expansíveis e hidratáveis, porosidade total e interconectada, salinidade do fluido dos poros e pressões capilares das
amostras dos folhelhos afetaram os resultados da atividade química.
Abstract
This paper presents a campaign of lab tests to obtain the water activity from shales and it’s pore fluid originated from
offshore and onshore basin. The results of water activity from shales indicate that the values rang from 0.754 to 0.923
and for the pore fluid are between 0.987 and 0.940. The results show that the water activity of interstitial water can be
obtained in 6 days and the rock in 10 days using the thermohygrometer used. The degree of saturation, water content,
kind and tenor of expansible and hydratable clay mineral, total and interconnected porosity, salinity of interstitial fluid
and the capillary pressure of shale samples affected the results of water activity.
1. Introduction
The fluid flow and the migration of solutes into or out of shales is critical when considering wellbore stability.
One of the main important causes of the problems has been identified as the movement of water and solutes from
water-based drilling fluids to shale formations (Chenevert and Osinsaya, 1989; Chenevert, 1990; Simpson and Walker,
1996; Simpson and Dearing, 2000). Shales are permeable to water and hydrated ions, in which the water movement
into or out of shales is governated mainly by the hydraulic differential between the drilling fluid pressure and the rock’s
pore pressure.
The water flow can increase the pore pressure and the water content of the shale near the borehole surface.
The increase of pore pressure can reduce the rock strength and increase the deformations. The ions migration is
governated mainly by the ionic differential between its concentration in the drilling fluid and the rock.
The ions invasion of ions can alter the fabric of clay minerals in shales due to osmotic hydration that can cause
significant swelling in some types of clay minerals. The negatively charged layers present in the clay surfaces attract
cations and water molecules, moreover cations, mainly sodium, calcium, potassium and magnesium, which are easily
exchangeable at the clay surface. It can alter the clay structure, weakling and destabilizing much more the formation
near wellbore. To avoid or reduce these problems, many researchers suggest that the balance of water activity can
adjust chemical potential between the drilling fluids and shales (Chenevert, 1970; Hale et al., 1992, Simpson and
Dearing, 2000; Rabe and Fontoura, 2003), through the addiction of salts to the water phase.
2. Water Activity of Shale
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Shale is considered as a non-ideal osmotic membrane, i.e., a semi-permeable barrier, which permits the
transport of some components of a solution and not others. The transference of solute and water depend not only upon
the relative concentration of each solute in the drilling fluid and the rock matrix and into its pore space, but also on the
solute selectivity of the drilling fluid/shale interface.
According to Hawkes and Mc Lellan (2000), the salt-exclusionary behavior of clay membranes is due to the
electrical restrictions operating within the interstices of clay membrane structures. The balance between the opposite
directions can be the one of the answers to reduce the velocity and intensity of flux and reactions.
As a consequence, the water will flow through the membrane from the low concentration solution to the high
concentration solution, i.e., the water will flow from the solution having a higher water activity to the solution having a
lower water activity. On the other hand, some ions will migrate through the membrane from the high concentration
solution to the low concentration, i.e., the ions will migrate from the solution having a low water activity to the solution
having a high water activity.
Water activity, i.e., it’s chemical activity is defined as the ratio of the water vapor pressure in a solution,
drilling fluid or shale matrix and its pore fluid, to the vapor pressure of pure water at the same temperature. The water
activity depends on the ionic properties of the shale, like ionic strength, particle surface charges and temperature. The
water activity is defined by the ratio pw/pwo.
aw =
wo
w
p
p (1)
where pw is the partial pressure of water vapor and the pwo is the vapor pressure of pure water. Water activity is
expressed as a fraction ranging from 0 to 1.
Change in near-wellbore pore pressure or osmotic pressure change due to chemical gradient between the
drilling fluid and the shale, can be obtained through the differences in the partial pressure of water vapor and the vapor
pressure of pure solution of the drilling fluid and the shale (Eq. 2), or through the difference in the water activities
(Eq. 3).
)
/
/
ln(
woshalewshale
wofluidwfluid
osm pp
pp
V
RT
P= (2)
)ln(
shale
fluid
osm a
a
V
RT
P= (3)
where, Posm is the osmotic pressure change, R is the universal gas constant, T is the temperature, V is the partial
molar volume of water, pwfluid is the relationship between the partial pressure of water vapor and pwo is the vapor
pressure of pure water of the drilling fluids and shale samples, amud is the water activity of drilling fluid and ashale is the
water activity of shale.
Initially, it is necessary to realize a shale physico-chemical characterization (Fontoura et al., 2002) to
determine the water activity from shales and its pore fluid, then, control the water flow and the diffusion of ions
throughout the adjust or balance the water activity of drilling fluids. This paper presents a campaign of lab tests to
obtain the water activity from shales and it´s pore fluid originated of samples extracted from formations at offshore and
onshore plataforms.
3. Description of Shale’s Individual Constituints
The lab tests were realized with five types of shales (Table 1). Three of them are originated from Brazilian and
Norwegian deep waters offshore platforms and the others two are from Colombian and Venezuela onshore plataforms.
The samples from Brazil and Norway, after coring, were stored in mineral oil in order to warrant that the samples prior
to testing would not be exposed to air and let dry. The Colombia’s and Venezuela’s shales were not well stored,
causing the drying of the cores during the transport to Brazil, generating the appearance of fractures and loss of water
content in the samples, reducing the degree of saturation.
Table 1. Depht, origin and type.
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Shale Medium depth (m) Origin Country
A 2587 Offshore Brazil
B 3072 Offshore Brazil
C Data not available Onshore Colombia
N 2328 Offshore Norway
V Data not available Onshore Venezuela
3.1. Physical Properties
The physical of shales samples are present in Table 2. The water content was obtained by oven-drying the
samples at 105°C for 24 hours, as recommended by the International Society of Rock Mechanics, and the specific
gravity of grains was determined using the picnometer, following, the recommendations of ASTM. The determination
of degree of saturation, voids ratio and porosity values were obtained with the use of classical soil mechanics
expressions (Lambe and Whitman, 1979).
Table 2. Physical properties of shale samples.
Shale Water content
(%)
Specific Gravity Degree of
Saturation (%)
Voids Ratio Total
porosity (%)
A 7.3 2.69 95 0.21 17.4
B 14.2 2.70 96 0.40 28.6
C 4.9 2.69 41 0.32 24.2
N 36.5 2.69 100 0.88 46.8
V 3.1 2.71 49 0.17 14.5
Table 2 indicates that the shales present high porosity and that samples B and N have high water content. The
shales are saturated, except the samples C and V.
3.2. X-Ray Diffraction
X-Ray diffraction is a well-known technique for the evaluation of mineral composition of soils and rocks,
especially for the examination of clay minerals. The tests were carried out using the X-Ray equipment, SIEMENS
D-5000, available at the Department of Material from the Catholic University of Rio de Janeiro. The powder method
was adopted with scanning speed of 6º by minute. The diffractograms interpretation was made through standard
procedure according to Brown and Brindley (1953).
In order to complement the information obtained from X-Ray diffraction, chemical analysis of samples was
carried out at the Atomic Emission Laboratory. For the realization of the tests, 30 grams of material was need. In
laboratory, the material is dried to 180ºC, then crushed to a 2-mm size and pulverized to a size of 150 mesh. The loss
on fire, that includes H2O, S and CO2, was carried out by calcinations to 1000ºC until constant in weight. Table 3
presents the semi quantitative analysis of shale´s mineralogy.
Table 3. Semi quantitative analysis of shale´s mineralogy.
Shale Main minerals
A Calcite (30%), quartz (21%), illite/smectite (18.4%), plagioclase (7.5%), feldspar (8%), pyrite (5%),
chlorite (4.5%), illite (4.2%) and kaolinite (1.4%).
B Quartz (30%), calcite (29%), feldspar (15%), kaolinite/illite/smectite (15%), chlorite (6%) and
pyrite (5%).
C Quartz (44%), feldspar (29%), kaolinite (9%), illite/smectite (8%), plagioclase (8%) and pyrite
(2%).
N Quartz (38.1%), smectite (20%), chlorite (6%), illite/smectite (13.6%), mica/illite (8.5%), pyrite
(7.6%), calcite (3.5%) and feldspar (2.7%).
V Quartz (38%), calcite (29%), feldspar (11%), kaolinite (9%), illite (3%), pyrite (7%) and
apatite (3%).
The accuracy of the test, for the oxides SiO2, Al2O3, TiO2, Fe2O3, CaO, K2O, MnO, P2O5 was 0.01% and the
inferior limit for Na2O, MgO was of 0,1%. Calcium (shales A and B) suggests the presence of calcite in the rock
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matrix. The semi-quantitative mineralogical analysis was obtained through the combination of the data from X-ray
diffraction and the chemical composition of each mineral through the method developed by Chakrabarty and Longo
(1997). The main clay minerals are: 18.4% of illite/smectite (shale A), 15% of kaolinite/illite/smectite (shale B), 8% of
illite/smectite (shale C), 20% of smectite (shale N) and 9% of kaolinite (shale V). The results indicated that shales A, B
and N are rich in reactive and swelling clay minerals.
The clay fraction in the order of smectite, the most reactive and expansible clay minerals, is about 24% in the
shale A, 15% in the shale B, 17% in the shale C, 42.1% in the shale N and 12% in the shale V (Table 3).
3.3. Pore Fluid Composition
The composition of the shale interstitial fluid is an important element during the analysis of mass transfer
mechanisms between the drilling fluid and the shale. The fluid extraction technique developed by Schmidt (1973) was
followed during the experiments. The results of the concentration of ions dissolved in the pore fluid are indicated in
Table 4, in which it can be seen that the pore fluid of shale originated from offshore plataforms are rich in chlorites and
sulfates. The main cations are: sodium, potassium, calcium and magnesium. This composition is similar to the
composition of seawater. The pore fluids from onshore plataform shale have traces of chlorites and sulfates, therefore,
the shales from onshore plataforms are poor in salts.
Table 4. Ions dissolved in the pore fluid (g/l).
Shale Na+ K
+ Ca++ Mg++ Cl- SO4
-2
A 14.44 0.42 0.87 0.13 12.76 9.35
B 16.67 0.23 0.13 0.11 17.87 12.89
C 5.3 0.7 0.01 0.01 0.02 0.02
N 24.3 0.4 0.53 0.17 28.98 5.85
V 0.12 0.02 0.02 0.00 0.10 0.1
Sea water 10.8 0.4 0.48 1.29 19.36 2.70
3.4. Interconnected Porosity and Suction of the Shale Samples
The pores represent an important component of shale structure. Through the pores occur mass transport
processes such as of water and ions. The technique of mercury injection was used for describing the interconnected
porosity and negative pressures that the samples are submitted at atmospheric condition.
As suggested by Ritter and Drake (1945), the interconnected porosity of shale samples was obtained through
the technique of mercury injection. The model 9220 Autopore III with maximum injection pressure of 400 MPa was
used during the tests. The interconnected porosity was obtained by the sum of intercommunicated pore volumes, i.e.,
the pores in which total area is the sum of the volume of mercury intruded. Table 5 shows the values of the
interconnected porosity and it´s relationship with the total porosity.
Table 5. Interconnected porosity (%).
Shale
A B C N V
Interconnected porosity 16.3 25.9 6.6 12.9 13.4
Variation in relation to total porosity (%) -6.3 -9.4 -72.7 -72.4 -7.6
As observed in Table 5, the values of interconnected porosity are smaller than total porosity. The results
indicated that the shale C and N have low interconnected pores (difference greater than 72%). The interconnected
porosity of shales A, B and V is almost 10% less than the total porosity, indicating a great communication between the
pores.
The generation of negative pressures is obtained through a vacuum bomb with capacity of suction of
1000MPa, that would be enough for extrude the mercury injected into the sample. To estimate the suction, it was used
the Laplace’s law, considering that the pores have a cylindrical shape. In Equation 4, the development capillary
pressure is shown by equilibrium condition between the pressures of the wetting and non-wetting phases:
d
Pc
θ
γ
cos4
= (4)
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where: the capillary pressure (Pc) is function of the surface tension between the wetting and non-wetting phases (γ) , θ
is the contact angle and d is the diameter of the pore.
Figure 1 presents the suction curves. The negative pressures behavior can be observed in function of sample’s
degree of saturation. The results indicated that the samples become unsaturated at elevated pressures, between 95MPa
and 100MPa.
Suction starts to become intense at 80% of saturation. High levels of non-saturation can create fractures and
disintegration of shale’s samples during its confection to porosimetry tests. Shale C (S = 41%), which is under negative
pressure of 33 MPa, can create a partly disintegration of some samples. Disintegration of shale can be wrong attributed
to reactivity phenomena’s (Forsans and Schmitt, 1994).
Table 6 shows the negative pressures that the samples are submitted in relation to its degree of saturation,
obtained through the physical properties (Table 2). The results indicated that shales C and V are submitted to high
negative pressures, that is, 36 MPa and 85 Mpa, respectively.
Figure 1. Suction curves of shales.
Table 6. Negative pressures of shale samples.
Shale
A B C N V
S (%) 95 96 41 100 49
Pc (MPa) 0.009 0.004 36.240 0 0.085
The non-well preservation of the cores lead to large negative pressures in the shale pore space, and it can lead
to desaturation through cavitation. The cavitation is filled with the water vapor or gas, and the interfacial tension affects
the water activity. Fam and Dusseault (1998), using Kelvin’s law (Eq. 5), concluded that if both water and air are
present in pores, then the activity coefficient depends on both the chemical composition and capillary pressure.
)ln(
)cos(2
w
p
t
wa
ca
V
RT
r
ppP ===
θ
σ
(5)
where pa and pw are the pressure of air and water, respectively, σt is the surface tension, rp is the pore radius and θ is the
contact angle. This equation indicates that low degrees of saturation reduce the water activity considerably.
4. Measurement of Water Activity
4.1. Test Equipment and Test Procedure
The equipment was developed to measure the water activity of shale samples and its simulated pore fluid at
atmospheric pressure. The apparatus (Figure 2) is a termohygrometer inserted in a non-pressure vessel (erlenmeyer)
that contained a shale samples or simulated shale pore fluid subjected to atmospheric pressure and ambient temperature.
A thermohygrometer placed in near of a vicinity of the shale specimen sample, or simulated shale pore fluid was used
to measure the ambient relative humidity and temperature of a small volume of atmosphere. Measurements of water
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activity in the laboratory are based on equilibrating the samples and solutions in environments with different relative
humidity. The water activity is obtained directly by the measurement of relative humidity (RH):
100
RH
aw= (6)
For each test, rock undisturbed fragments were used, with approximate weight of 30 grams. Before the tests,
the samples were handled inside a high humidity room. This procedure guarantees that the sample was not exposed to
the air.
The simulated pore fluid was prepared at the atomic spectrometry laboratory with the same composition of
pore fluid present in Table 6. For each test, was used 50 ml of solution. The pH and salt concentrations of solutions
were measured and controlled before the test.
Figure 2. Equipment to measure (a) water activity of shales and (b) water activity of simulated pore fluid.
4.2. Experimental Results
The behavior of water activity of shales and pore fluids in function of time obtained through the equipment are
presented in Figure 3, and the final results in Table 7.
The water activity of shales is ranging from 0.754 to 0.923. Shales C and V presented low water activity,
while shales A, B and N presented high water activity. The tests results show that the equilibrium was obtained faster
with shales C (216 hours) and V (240 hours). Shales with high water activity spent 251 hours (A), 259 hours (B) and
275 hours (N) to obtain the equilibrium of humidity.
The water activity of simulated shale pore fluid is ranging from 0.940 to 0.987. The onshore shales have high
water activity of shale pore fluid. The values are next to the water activity from the pure water (apw = 1.000). The tests
also showed that the equilibrium was obtained faster in shales N (157 hours) and B (159 hours) and A (160 hours), that
present low water activity. The water activity of simulated pore solution from shales with high water activity spent 163
hours (C) and 164 hours (V). The medium time to obtain the water activity of simulated pore fluid was 64.7% less than
water activity from the shale samples.
(
a
)
(
b
)
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Figure 3. Changes in water activity of shales and in water activity of the simulated shale pore fluid.
Table 7. Shale water activity and water activity from pore fluids
Shale ashale Temperature (ºC) apore fluid Temperature (ºC)
A 0.896 22.1 0.965 21.9
B 0.917 22.3 0.958 22.8
C 0.731 21.7 0.977 21.3
N 0.923 21.3 0.940 21.8
V 0.754 21.9 0.987 21.7
5. Conclusions
The apparatus is simple and present low cost, and the tests can be done in both laboratory and plataform
conditions. The main disadvantage is that the tests aren’t conducted in situ conditions.
The measurement of activity is based on the equilibrium of the shale sample among the environments, each
with different relative humidity characteristic. This may give a lower value of water activity, when compared with in
situ conditions, because de degree of saturation in some shale samples can be less than 100%. The non-well
preservation of the cores leads to large negative pressures in the shale pore space, and this can leads to desaturation
through cavitation.
The shales with low degree of saturation, water content, low clay fraction and rich in non-expansible and
hydratable clay type, low salinity in the pore fluid, and with high capillary pressure tend to have a low water activity.
The salinity present in the pore space also reduced the water activity of preserved shale samples.
Chemical reconstitution of shale pore fluid seen to be a good technique to produce a great volume of solution.
The technique to extract and measure the salt concentration is much more sophisticated, expansible and spend much
more time than measure the undisturbed shale samples. The high tenor of salts present in the pore space in the offshore
samples is the responsible by the low values of water activity in the rock matrix and in the simulated pore fluid.
The presence of high-interconnected porosity may also be responsible for the low time spent to reach the
equilibrium of the water activity of the shale pore fluid. The interconnection permits that o shale present a membrane
more permeable, in which the water flux and pressure can be rapidly transmitted.
The degree of saturation, the tenor of clay minerals and salts in the pores are responsible for the longest time
spent to obtain the equilibrium of water activity. The degree of saturation affects strongly the results. The difference of
water activity between saturated and non-saturated shales is over 12%.
The time obtained to reach humidity equilibrium among the rocks, pore fluids and the atmosphere inside the
erlenmeyer, is due to some rock’s properties, like: rock microfabric or structure, clay content, pore water composition,
type of clay minerals, presence of air in the pore space, porosity and grain size distribution.
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6. Acknowledgements
Petrobras for the technical and financial supports throughout to the development of this study. Financial
support of the Brazilian Petroleum Agency is gratefully acknowledged. Thanks are directed to the author’s colleague at
Petrobras, Flávia de Oliveira Lima Falcão for reviewing this paper.
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Stability problems encountered in shale formations significantly increase the cost of drilling operations. It is not possible to identify a single main factor in shale instability; failure mechanisms are only now beginning to be identified, and the dominant processes seem to vary for different conditions of stress, mineralogy, fabric, and geochemistry. This article reviews a number of physical and chemical concepts in borehole stability analysis and raises several issues related to the activity coefficient and cation exchange processes. It is shown that the degree of saturation and clay particle separation have significant impact on the activity coefficient of tested cores. A simple coupling model based on the modified effective stress principle shows that when a shale with low porosity and high specific surface (reactive shale) is subjected to an increase in pore fluid salt concentration, a pore pressure front may develop. This front may trigger changes in effective stress and shear strength around the borehole. This may be a major destabilizing mechanism in the more reactive shales (generally the smectitic shales). P. 461
Article
Interstitial water from shales and sandstones shows a contrast in concentration and composition. Sidewall cores of shales were taken every 500 ft between 3,000 and 14,000 ft in a well in Calcasieu Parish, Louisiana, which encountered abnormally high fluid pressures just below 10,000 ft. Significant differences between the total dissolved solids concentrations in waters from normally pressured sandstones (600-180,000 mg/l) and highly pressured sandstone (16,000-26,000 mg/l) were noted. Shale pore water has a lower salinity than the water in the adjacent normally pressured sandstones, but the concentrations are more similar in the high pressure zone. Shale water generally has a concentration order of SO4 = > HCO3- > Cl-, whe eas water in normally pressured sandstone has a reversed concentration order. Conversion from predominantly expandable to non-expandable clays accelerates near the top of the high pressure zone, which appears correlative with a major temperature gradient change, an increase in shale porosity (decrease in shale density), a lithology change to a massive shale, an increase in shale conductivity, an increase in fluid pressure, and a decrease in the salinity of the interstitial waters. The data presented suggest that the clays subjected to diagenetic change release two layers of deionized water and that this released water may be responsible for the lower salinity of the water found in the high pressure section.
Article
This paper presents laboratory and field results showing that an environmentally acceptable water-based mud (WBM) can be formulated to act like an oil-based mud (OBM) in preventing hydration, pore-pressure increase, and weakening of shale by effectively developing sufficient osmotic force to offset the hydraulic forces acting to cause water flux into the shale. We also show that this methyl glucoside system has other performance characteristics similar to OBM's, such as lubricity, filtration control, and tolerance for common WBM contaminants, thus meeting the needs for drilling high-angle or even extended-reach wells.
Article
Problems encountered while drilling shale formations are a major factor in the cost of oil and gas wells. A principal cause of the problems has been shown to be the transfer of water and ions from water-based drilling fluids to shale formations. Prior studies have documented two driving forces involved in such transfer. One is the hydraulic pressure differential between the drilling fluid and shale pore fluid. A second is a chemical osmotic force dependent upon the difference between the water activity (vapor pressure) of the drilling fluid and that of the shale pore fluid under downhole conditions. Generally unrecognized is another driving force, diffusion osmosis, which is determined by the difference in concentrations of the solutes in the drilling fluid and shale pore fluid. Diffusion osmosis results in transfer of solutes and associated water from higher to lower concentration for each species, opposite to the flow of water in chemical osmosis. If the diffusion osmotic force exceeds the chemical osmotic force, invasion of ions and water can increase the pore pressure and water content of the shale near the borehole surface. Additionally, the invading ions can cause cation exchange reactions that alter the clay structure in the shale. All of these effects tend to destabilize the shale. Destabilizing ionic reactions within a shale can be minimized if a suitable non-ionic polyol (such as methyl glucoside) is used to reduce the activity of a fresh-water drilling fluid. In certain situations the addition of salt to such a fresh-water drilling fluid to obtain further reduction of water activity can cause an increase in the diffusion osmotic force that offsets some, or all, of the desired increase in chemical osmotic force. This now is recognized to have probably been a factor when sodium chloride was included in the formulation of a methyl glucoside drilling fluid used with moderate success for drilling in the Gulf of Mexico. Chemical osmotic effectiveness can be improved by emulsification of a non-aqueous phase in the drilling fluid. A fresh-water drilling fluid containing methyl glucoside for activity control and emulsified pentaerythritol oleate prevented hydration and maintained stability of Pleistocene shale from the Gulf of Mexico. Drill cuttings from such a drilling fluid should be environmentally acceptable for discharge at offshore or land locations. Introduction Interactions of water-based drilling and completion fluids with shale formations have long been recognized as a major factor in the cost of finding and producing oil and gas. Much progress has been made in understanding the mechanisms responsible for the destabilization of shale and subsequent problems such as high torque, stuck pipe, lost circulation and cementing failures. In most instances the problems can be avoided by use of hydrocarbon-based drilling fluids, but the use of those fluids are now being curtailed because of environmental concerns. The excellent shale stability provided by hydrocarbon-based fluids has been attributed in part to the establishment of an essentially ideal semipermeable membrane at the drilling fluid/shale interface. The membrane has openings large enough to allow water molecules to pass, but small enough to prevent passage of dissolved ions and molecules. This results in development of an osmotic pressure differential which is dependent upon the ratio of water activity (escaping tendency) of the drilling fluid (adf) to that of the shale pore fluid (as).1 The transfer of water is from the higher water activity (lower concentration of dissolved ions or molecules) to the lower water activity. Solutes, such as calcium chloride, can therefore be added to the water phase of a hydrocarbon-based emulsion fluid to reduce the water activity and develop enough osmotic force to prevent shale hydration, or even extract water from shale. This mechanism for water transfer is commonly designated chemical osmosis.
Article
SPE Members Abstract A vast majority of drilling problems occur in shales. The traditional explanation is that shales swell when contacted with water. As the use of oil based muds becomes more difficult, recent years have seen a large number of publications dedicated to the study of water/shale interaction. Unfortunately, this large body of evidence contains too many contradictions to be trusted as a sound basis for engineering. A two years long critical review of this material was therefore undertaken revealing that most experimental observations performed in the laboratory were not representative of downhole conditions as air or water vapor had been introduced in the samples, leading to capillary phenomena which have been mistaken for swelling. Further observations revealed that true swelling is unlikely to be an issue downhole. Upon contact with drilling fluids, the occurrence of mineralogical transformations affecting the shale was identified and it was further shown that such transformations will affect the mechanical response of the rock. Background Many sources have evaluated that problems due to wellbore stability add on average between 10 and 15 % to normal drilling costs. Shales are at the origin of most of these problems and it has traditionally been assumed that this is due to the fact that they swell when contacted with water. As a consequence, the industry has turned successfully towards the use of oil based muds to resolve them. This success is clearly illustrated by the statistical analysis of 100 8"1/2 phases drilled in Italy over recent years with both water and oil based muds. For each well, stuck pipe cases were systematically analysed revealing that only 4 wells out of 26 drilled with oil based mud had a stuck pipe whilst 40 out of 74 wells drilled with water based mud had difficulties. Unfortunately, environmental concerns make the use of oil based muds more and more difficult, costly and risky everywhere:–special authorizations need to be obtained,–secure and expensive cuttings disposal procedures need to be divised,–long term legal liability has been imposed in many countries which leaves little room for errors. P. 741
Article
Most phenomena in shale drilling instabilities have only been proved in laboratories, on reconstituted, outcrop or core samples. Partial saturation is evidenced for these samples, its origins explained and its consequences detailed. A model is proposed for the calculation of the apparent compressive strength of a rock from its pore size distribution and moisture content. Effects of capillary pressures are presented in various shale/fluid inhibition tests and some classical interpretations turned down. Last, a rehydration procedure is presented, which has been validated on a low permeability shale. Introduction Shale stability is an old problem for the drilling of oil wells, as can be seen from the literature. In early times, a mere descriptive approach was taken: signs of instability were listed and a classification established from it. An analytical approach followed, in which many searchers tried to investigate the mechanisms responsible for the reported signs of instability. Preferably, such studies should have been done in-situ, so that all conditions were reproduced. Unfortunately, accurate measurements of mechanical and structural properties of shales are technically difficult downhole (pressure, temperature, presence of the mud,...) and in addition, the situation itself is very complex, and would have had compromised the interpretation of results. To allow for such studies, samples were taken from different sources and used in the lab for reproducing, on a small scale and with simplified conditions, the phenomena occurring during the drilling process. Many tests have thus been designed to use these samples and are extensively described in the literature. Results of these tests helped select the drilling conditions appropriate to a given shale, this including chemistry of the mud as well as its physical properties (viscosity, density). However, artifacts have been reported which affect the results of many tests and consequently influence mud selection. P. 71
Article
Quantitative information about the reservoir rock minerals is important for making technical and business decisions in hydro-carbon exploration and exploitation. Minerals are usually quantified using mineral properties available from published data and rock properties measured in the laboratory used cored samples or in the field using geochemical well logs. Despite considerable efforts by many researchers, the rapid quantification of minerals. with error estimates remains a challenge. The most widely used, method for rapid mineral quantification is the matrix algebra method that uses the least-squares principle. Although fast and easy to implement, the conventional matrix algebra method is computationally unstable leading to unrealistic values (negative or greater than one) for mineral fractions. In this paper, we present a computationally stable method that retains the speed of the conventional matrix algebra method while overcoming its limitation. The present method can be applied to both laboratory (core samples) and downhole (geo-chemical well logs) analyses. It is effective in handling over determined, determined, and under-determined systems. It also handles both fixed and variable mineral properties. Unlike the conventional matrix algebra method, the present method supplements the rock and mineral properties with several constraining equations that incorporate prior information about the mineral fractions. The prior information about the mineral fractions, and the measured rock properties are weighted by the reciprocals of their respective error variances. Involving only matrix operations, the resulting equation to obtain mineral fractions is easy to implement and fast to compute. Programmed as an Excel macro or in Visual Basic, the method has been successfully implemented in our laboratory since 1993 for quantifying minerals in core samples from diverse rock formations. Introduction Reservoir rocks are an assemblage of minerals such as quartz, carbonates, feldspars, kaolinite, illite, and smectite. Quantitative analysis of these minerals is used by exploration and production geologists as well as by reservoir and production engineers. Exploration geologists use the rock mineralogy to reduce the risk in discovering oil by determining the thermal and diagenetic history of a basin, defining the provenance (source area) and the depositional environment of the sediments, and correlating certain minerals with well logs. Exploitation geologists and reservoir engineers use the rock mineralogy to assess reservoir quality develop effective depletion strategies, and predict the effect of rock-fluid interactions. Production engineers use the rock mineralogy to design work-over and completion strategies such as selection of drilling fluids and proper stimulation methods (e.g., acidizing). Traditionally, rock mineralogy has been determined in the laboratory using cored rock samples(1–4). Over the past few years, there have been efforts to develop mineral logs by downhole geochemical welllogging(5–7). Laboratory and Downhole Mineral Quantification The methodologies for routine laboratory and downhole mineral quantification are similar. In both cases, the rock properties and mineral properties are used to estimate mineral fractions. In the laboratory, X-ray fluorescence is used to measure rock properties (elemental composition expressed as oxides). These properties can be supplemented by other rock properties such as loss on ignition (LOI) and cation-exchange capacity (CEC).