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New membrane efficient, water-based drilling fluids for cost-effective borehole instability
by UA Tare, Halliburton; FK Mody, Shell International E&P; CP Tan, CSIRO Petroleum
(12/4/2002) Shale instability results in an estimated US$1.3 billion annual expenditure
by the petroleum industry. As environmental concerns restrict the use of
oil-base fluids, there is an urgent need for water-based fluids (WBF) that
meet key performance measures, especially while drilling high-angle,
extended-reach well trajectories through water-sensitive shale formations.
A major collaboration between Commonwealth Scientific and Industrial
Research Organization (CSIRO) and Halliburton's Baroid product service line
was undertaken to develop membrane-efficient, environmentally acceptable
water-based drilling fluids. The project's principal objectives included the
development of compounds for use in WBFs that generate highly efficient (or
isolation) membranes on the borehole wall in shale formations and the
development of functional drilling fluid formulations with these compounds.
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This pore-pressure transmission measurement apparatus is used to gauge
membrane efficiency of various fluids. |
maintained with membrane-efficient WBFs through a combination of osmotic
outflow of pore fluid (chemical potential mechanism) and the
prevention/minimization of mud pressure penetration by generating an
isolation membrane on the borehole wall or minimizing hydraulic diffusivity.
When drilling shale with an overbalanced WBF where no effective flow barrier
exists at the wellbore wall, mud pressure penetrates progressively into the
formation. A small volume of mud filtrate penetration causes a considerable
increase in pore pressure near the wellbore wall, reducing effective mud
support and possibly leading to wellbore instability.
The mechanisms that influence fluid (water) transport are differences
between shale and drilling fluid hydraulic pressures, chemical potentials,
electrical potentials and temperatures.
In most cases, the two most relevant mechanisms for water transport in and
out of shale are the hydraulic pressure difference between wellbore pressure
and shale pore pressure; and chemical potential difference, i.e., water
activity between the drilling fluid and the shale.
Osmotic semi permeable membrane
The fine pore size and negative charge of clay on pore surfaces cause
argillaceous materials to exhibit membrane behavior. Efficiency is a measure
of the membrane's capacity to sustain osmotic pressure between the drilling
fluid and shale formation. The driving force for the movement of water by
osmotic mechanism is represented in the following equation.
For WBF-shale systems, membrane efficiency (reflection coefficient) is not a
clearly defined term, unlike the oil film present in invert emulsion
systems. The membrane efficiency of shale-fluid systems is due to a
difference in mobility of water and solutes (ions) in shales.
If only water movement is allowed and all solute movement is restricted, the
membrane is ideally semi-permeable (100% membrane efficiency or s=1). For
shales, when the mobility of solutes is lower than that of water and the
membrane is "non-ideal", a membrane efficiency less than 100% is more
realistic. A non-ideal membrane does not entirely restrict solute transport.
Membrane efficiency in the WBF-shale system has a direct relationship with
the average 'effective' shale pore radius and the radius of hydrated ions
present in the drilling fluid system.
If the drilling fluid water activity is lower than the formation water
activity, an osmotic outflow of pore fluid from the formation lessens the
pore pressure increase, due to mud pressure penetration. An osmotic outflow
greater than the inflow, resulting from mud pressure penetration, creates a
net flow of water out of formation into the wellbore. This results in
lowering the pore fluid pressure below the in-situ value. The associated
increase in the effective mud support improves wellbore stability.
Osmotic outflow increases as membrane efficiency increases. Most
conventional WBFs have low membrane efficiency, even if the WBF water
activity is significantly lower (with a high salt concentration) than the
shale water activity.
Screening Tests for Membrane Efficiency
Over 300 pressure transmission-chemical potential tests have been performed
to screen novel compounds for their membrane generation capacity in shales.
Well-preserved shale samples are confined under geo-static stress and test
fluids are circulated, under confined dynamic conditions, at the upstream
end. Changes in downstream pressure are measured simultaneously. The
application of very high pressure simulates downhole conditions where
overbalance is maintained. The downstream pressure changes indicate changes
in the sample pore pressure. Membrane efficiency is given by the ratio of
the maximum differential pressure across the sample and the theoretical
osmotic pressure for an ideal semi-permeable membrane of the test
fluid-shale system.
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| Figure 1. Schematic of test cell of membrane efficiency screening equipment. |
A schematic of the membrane efficiency screening test cell is provided in
Figure 1. Up to six different test solutions can be tested simultaneously
using six test cells with confining pressure and pore pressure capacities of
35 MPa and 20 MPa respectively. The upstream pressure of the six test cells
is monitored by a single pressure transducer. The downstream pressure of
each cell is monitored by a separate pressure transducer. Circulation of the
test solution is adjusted with a needle valve. The entire apparatus is
placed in a constant temperature environment.
Pierre II shale samples were saturated by applying a confining pressure of
20 MPa and a backpressure of 10 MPa with simulated pore fluid at the
upstream end. The downstream pressure is increased to above 10 MPa. Upon
consolidation of the sample, the upstream pressure is increased to 15 MPa.
When the downstream pressure increases to about 2 MPa, the upstream pressure
is reduced to 10 MPa. The sample is then re-consolidated by allowing the
excess pore pressure inside the sample to dissipate.
Following the equilibration of the downstream pressure with the upstream
pressure (or stabilization of the downstream pressure), the simulated pore
fluid is displaced by the test solution at the upstream end. The upstream
pressure is then increased to 15 MPa and the downstream pressure is allowed
to increase and stabilize. Following the equilibration of the downstream
pressure with the upstream pressure the test solution is displaced with the
lower water activity solution; this is the chemical potential stage. The
lower water activity solution is circulated at about 0.25 ml/hr. The test is
terminated when a maximum decrease in the downstream pore pressure is
observed.
The Pierre II shale samples used in the experiments were saturated with a
simulated pore fluid. Based on the drilling fluid shale interaction
mechanisms, there are two main categories of mechanisms by which a membrane
can be generated by drilling fluids: 1) stand-alone drilling fluids, where
the fluid provides a membrane independent of the shale; and 2) coupled
drilling fluid-shale systems, requiring interaction between the drilling
fluid and shale. Three groups of membrane efficient WBFs were developed
using the latter mechanism, representing a new generation of membrane
efficient water-based systems. The results presented here compare the
membrane efficiency of the new generation membrane efficient water-based
system containing 12% w/w NaCl salt (e.g., membrane efficient System A) and
a 20% w/w NaCl solution exposed to a Pierre II shale.
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Figure 2. Confining, upstream and downstream pressures vs. time for a
membrane efficiency-screening test utilizing Pierre II shale expose to a
membrane efficient water-based fluid system-A with 12% w/w NaCl. |
Based on the observed maximum downstream pressure drop in the chemical
potential stage, the membrane efficiency for the membrane efficient System-A
with 12% w/w NaCl was determined to be approximately 85% (Figure 2). In
comparison, the pressure plot of the Pierre II shale sample exposed to 20%
w/w NaCl solution shows a much smaller downstream pressure drop with a
calculated membrane efficiency of 7.4% (Figure 3).
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Figure 3. Confining, upstream and downstream pressures vs. time for a
membrane efficiency-screening test utilizing Pierre II shale expose to a 20%
w/w NaCl salt solution. |
The theoretical membrane efficiency of an invert emulsion oil-based fluid
approaches 100%. Membrane efficiency comparisons included commonly used
brines, a conventional sodium silicate system with 20% w/w NaCl, and the
three new membrane efficient water-based mud systems with 12 % w/w NaCl
(Figure 4).
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Figure 4. Comparison of membrane efficiency of Pierre II shale exposed to
salt solutions, sodium silicate mud and new membrane efficient water-based
muds. |
The water activity of System-A with 12% w/w NaCl and the 20% w/w NaCl
solution were measured (using a digital hygrometer) at 0.89 and 0.83
respectively. The test solution water activity is lower than the measured
shale pore fluid water activity (Awshale = 0.99). This difference in water
activity caused the sample pore pressures to decrease as a result of
exposure to the lower water activity solutions. This is consistent with
prior observations, where outcrop shales were exposed to salt solutions of
CaCl2, NaCl and KCl.
The rate of downstream pressure drop during the chemical potential stage
indicates that the majority of osmotic pressure drop occurs in the first
12-24 hrs. System-A with 12% w/w NaCl appears more effective in reducing
the sample pore pressure than the 20% w/w NaCl solution. Since no hydraulic
overbalance was applied at the sample upstream end in the chemical potential
stage it is believed that the water transport was driven predominantly by
the osmotic driving mechanism.
The 20% w/w NaCl solution shows a very low membrane efficiency of 7.4%.
System-A with 12% w/w NaCl generated a membrane efficiency of approximately
85%. Three new generation water-based drilling fluid systems with high
membrane efficiencies (greater than 80%) were developed. A time-dependent
chemical-potential related alteration in shale pore pressure can be observed
within the first 12-24 hours of exposure during the chemical potential
stage.
References on request.
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