Chemical Osmosis, Shale, and Drilling Fluids

IADC/SPE 74557

Chemical Osmosis, Shale, and Drilling Fluids R. Schlemmer, J.E. Friedheim, and F.B. Growcock, M-I L.L.C.; J.B. Bloys, ChevronTexaco Copyright 2002, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the IADC/SPE Drilling Conference held in Dallas, Texas, 26–28 February 2002. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435

Abstract This paper describes continuing efforts to develop a waterbased drilling fluid that will provide the osmotic membrane behavior and wellbore stability of an oil-based drilling fluid. A pore-pressure-transmission technique in use for several years as a tool to measure osmotic behavior has been refined for improved measurement of changes in shale permeability and pore pressure in response to interaction with drilling fluids. Conventional invert emulsion and water-based drilling fluids containing selected additives were tested with outcrop and preserved shale specimens using an innovative screening method. Observed pressure differences were compared with values predicted by osmotic theory. From this comparison, an empirical concept of “membrane efficiency” was developed. Three distinct types of “membranes” are postulated to describe the interaction of various drilling fluids with shales. Type 1 membranes are generally characterized by coupled flows of water and solutes between fluid and shale. Type 2 membranes greatly reduce surface permeability of the shale restricting both flow of water and solutes; the latter to a greater extent. Type 3 membranes more selectively transport water but shale permeability and fluid chemistry may alter performance measurements. Invert emulsion fluids tend to form efficient Type 3 membranes; however, these fluids can, under certain conditions, yield lower capillary pressures than previously described and invade the interstitial fabric of a shale. Several water-based mud formulations were prepared which achieve about ¼ to ½ the measured osmotic pressure of a typical oil-based mud. Fluid additives which supplement or reinforce a Type 1 membrane, such as saccharide polymers,

(especially in combination with calcium, magnesium or aluminum salts) can exhibit relatively high efficiencies. As expected, fluids which form a Type 2 membrane such as silicate and aluminate muds, provide the highest membrane efficiencies. Some may prefer to view these described membranes as a simple seals, but they are less or more efficient membranes, nonetheless. Basic Osmosis Concepts Leakiness governs the effectiveness of osmosis and is the determiner of efficiency for a semi-permeable membrane. A semi-permeable membrane restricts the passage of solutes while the solvent is relatively unrestrained. Leakiness may more accurately describe a phenomenon for which the term “selectivity” has been previously applied. Efficiency of the membrane is quantified by the reflection coefficient, σ. The “reflection” analogy comes from an optical model adopted by researchers. The model assumes a semipermeable membrane analogous to a mirror – fully or semisilvered. All solutes of a solution to which a membrane is exposed will be fully or partially “reflected” by the membrane. An ideal semi-permeable membrane, i.e. one that allows passage of the solvent only, has a reflection coefficient, σ, of 100% or 1. Non-ideal membranes which allow partial passage of solute have reflection coefficients, σ, of less than 1 and are therefore referred to as “leaky”. Clay-based materials have intrinsic membrane behavior with reflection coefficients between 0 and 1, depending on the fluid contacting the clay surface. A high-permeability sand, on the other hand, does not exhibit semi-permeable properties and the reflection coefficient of the sand is essentially zero. For a system at thermal and electrical equilibrium, osmosis across a semi-permeable membrane consists of transport of solvent – usually water – from higher water activity to lower water activity, i.e. from the side containing a lower concentration of solute (dilute) to the side with higher concentration of solute (concentrated) such as a salt, sugar, or glycol. This flow of pure solvent is commonly referred to as “chemico-osmosis” or “chemical osmosis.” Flow of solvent will continue unless or until osmotic pressure is balanced by hydraulic pressure. For an ideal semi-permeable membrane, that is the extent of osmosis. For a leaky membrane, however,

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R. Schlemmer, J.E. Friedheim, F.B. Growcock, J.B. Bloys

solute species will also flow, and can flow in both directions; 1furthermore, hydrated species will carry solvent with them, thus leading to countercurrent flow of water and solutes.4,5 For a shale in contact with a typical salt-based aqueous drilling fluid, water will flow from the shale into the drilling fluid, but opposing, hydrated, cations and anions will flow from the drilling fluid into the shale. Additionally, hydrated salt species in the pore network of the shale will tend to flow into the drilling fluid. Further complicating the picture is the resulting exchange of ions on the clay, which will then also contribute to the complex dance. These “coupled flows” which characterize osmosis complicate prediction of membrane efficiency.5 Soil scientists and drilling fluids researchers commonly observe osmotic pressure development as a developing hydraulic head in an atmospherically pressured environment. Measured osmotic pressure curves typically develop as presented in Figure 1 The slope of the pressure development curve of an ideal membrane approaches zero. The slope of the pressure development curve of a non-ideal membrane becomes negative after a period of equilibration. 3

Fig. 1 – Pressure Development Curves for ideal and non-ideal 1 semi-permeable membranes. (reproduced with permission of Thomas Keijzer)

The clays composing shales are natural membranes. They are made up of combinations of two basic structural units. The silica tetrahedron and alumina octahedron are assembled in sheets. Clay minerals are characterized by the differences of stacking of these sheets and the manner by which the sheets are held together. Differences in the crystal structure of the sheets (isomorphic substitutions) are seen commonly as replacement of Al3+ for Si4+ in the tetrahedral sheet and Mg2+ for Al3+ in the octahedral sheet. These substitutions cause clay surfaces to have a net negative surface charge. Electrical neutrality is preserved by attraction of cations which are held between the layers and at the surface of the platelets. This electrostatic attraction results in a charged clay surface and a concentration of counter-ions which diminishes with distance from the surface. The charged clay surface, with the counterions in the pore water, forms the diffuse double layer. The double layer is affected by changes in salinity, pH, temperature, and valence of counter-ions.1

SPE 74557

The ability of clays to act as membranes is a consequence of overlapping double layers of adjacent clay platelets. Compaction, as occurs during formation of shales, results in higher concentration of cations and reduced concentration of anions in the double layer with respect to an equilibrium solution. The aqueous environment of narrow pores can be overwhelmed by the merged, opposing double layers. Diffusion of anions through the narrow aqueous film is inhibited, because the anions are repelled by the net negative charge of the platelets. Advection (flow of solutes and heat that accompany bulk motion of a fluid) is restrained. The effect is known as the “Donnan Exclusion”. 4 Because anions are inhibited from diffusion into the pores, associated cations are also inhibited from moving across the clay. This inhibition contributes to a membrane effect and increasing membrane efficiency, σ. The stacking of clay platelets and the narrow pore openings in shales also creates a matrix capable of supporting deposited (Type 2) and nonaqueous (Type 3) membranes. Thus, in principle, Type 2 and Type 3 membranes do not require or depend on fluid-clay interactions.4,6 whereas Type 1 membranes are strongly influenced by fluid-clay interactions. In practice, morphology of the clay structure and fluid-pore water interactions may play significant roles in the construction and maintenance of all three types of membranes. Membrane ideality of an exposed natural clay/shale depends on several factors; most important are: • Clay type; clay with high negative charge (expressed as the CEC) generally provide superior semipermeable membranes than clays with a lower CEC. The double layer is “thicker”. • Clay/Shale porosity; the more compacted the clay/shale, the more double layers overlap to form a contiguous membrane. • Salt concentration of the pore water of the clay; lower salt concentration also results in a “thicker” double layer, and more ideal membrane.1 • Change in any of the above due to compaction. • Drilling fluid composition; the nature of the clay/fluid interface is influenced strongly by physical and chemical interaction of solute species in the mud with the clay surface and/or dilution of bound water by drilling fluid solvent. Illustrating these factors are Figures 2 and 3. Figure 2 presents reflection coefficients, σ, as a function of porosity for a refined montmorillonite with CEC of 100 meq/100 g and an illite with CEC of 20 meq/100 g, using a mean salt concentration of 0.35 mol/L NaCl. Figure 3 compares reflection coefficients of a commercial montmorillonite tested at two salt concentrations.2 The interaction of drilling fluids with shales may be categorized in terms of formation of three types of “membranes,” as shown in Table 1. It should be emphasized that the term “membrane” is used here solely for the purpose of illustrating how the drilling fluid/shale interface affects the flow behavior of species between the drilling fluid and shale.

SPE 74557

Chemical Osmosis, Shale, and Drilling Fluids

3

of membrane is typical of in-situ polymerized oligomer, silicate, and some aluminum-based fluids.3 Membrane Type 3 is associated with invert emulsion-based drilling fluids and does not depend upon a deposited or precipitated solid film. A mobile film of the continuous phase plus surfactants of the drilling fluid bridges and separates the internal aqueous phase of the drilling fluid from water-filled shale pores. Although it is possible for anions and cations to diffuse through non-electrolytes as charge neutral ion pairs or net charge neutral groups,8 laboratory studies of lowpermeability shales indicates that solutes do not readily diffuse across the non-aqueous membranes generated by invert emulsion fluids.3 Downhole Simulation Tests conducted with high-permeability shales, on the other hand, have generated conflicting results. In earlier work with a conventional lowtoxicity mineral oil invert mud, no ion exchange appeared to occur in the shale.9 Later studies with a synthetic-based invert mud indicated that ion exchange occurred as deeply as ¼ to ½ in. into a relatively high permeability shale.10

2

Fig. 2 – Clay type - Reflection coefficient vs. porosity. (reproduced with permission of Soil Science of America)

Membrane

1

Membrane Type 1 is constructed within the shale. For this type membrane, drilling fluid filtrate, shale/clay, and pore fluid chemistry, as well as pore dimension, filtrate viscosity, permeability, clay components, and shale cementation all can contribute to development of membrane effect and a more ideal σ. The major portion of developmental effort has been on water-based materials supporting Type 1 membranes. Type 1 membranes are generally characterized by σ < 0.2.7 Membrane Type 2 side-steps the physicochemical force complications. A Type 2 membrane is efficiently laid down as a relatively impermeable deposit or precipitate primarily external to or within the near-wellbore shale matrix. This type

Type 3

Position

Internal

Character

Dynamic, Not Permanent

Primarily External Static Fixed Durable

Dependent

Independent

Independent

Dependent

Independent

Independent

0.5

1.0*

To 1000 psi 6.9 MPa

To 4000 psi 27.6 MPa

Variable

Double Layer Effects Clay/shale Effects Typical Reflection Coefficient (σ) Osmotic Pressure * Ref. 2

Fig. 3 – Salt concentration - Reflection coefficient vs. porosity. (reproduced with permission of Thomas Keijzer)

Table 1 - Membrane Types Type 1 Type 2

Primarily External Dynamic, Not Permanent

Shale Stability and Membranes. The phrase "Shale Stability" will be avoided in this paper, but if one goal is to be ascribed to the shale membrane studies, it would be to demonstrate "shale stability" improvement in a variety of water-based drilling fluids. As described here, the term is not associated with traditional cuttings stability, bentonite pellet stability, or bulk hardness tests. Shale bits and pieces, disrupted by mechanical and hydraulic forces at the bit and further influenced by chemical effects on their way to the surface, are only of concern to the operator and mud engineer for about an hour or two. At issue here is the ability to maintain an open hole through sensitive shale for periods of days or weeks, allowing extended trouble-free drilling using water-based drilling fluids. For decades, intact shale pieces have been evaluated, as presented in Table 2, by exposure to drilling fluids in pressured and unpressured vessels. In recent years, shale samples have been routinely exposed to differential pressures which induce fluid diffusion through a confined shale specimen. Traditional shale stability tests typically measured changes in physical properties. Shale

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SPE 74557

membrane tests measure development of pressure changes and/or fluid flow across the shale. Table 2 – Shale Test Characteristics Shale Stability Test • • • • • • •

Hardness change Moisture content change Dimensional change Tensile/compressive strength change Extrudability Dispersibility abrasion hot-roll Salinity change

Shale Membrane Test • Chemical osmotic flow volume • Chemical osmotic pressure development • Hydraulic flow volume • Hydraulic pressure development • Net direction & volume of flows • Shale permeability • Shale/fluid conductivity • Water/oil content

The standard by which fluids are judged is the invert emulsion drilling fluid. The diesel oil-based fluids of the 1960’s, built from tall oil soaps and polyamide surfactants, are the prototype for recent variants and continue to be used. Diesel oil has been replaced to a degree, market by market, with mineral oils, hydrogenated mineral oil, paraffins, hydrogenated olefins, polyolefins, ethers, and esters. The original polyamide-type surfactant, calcium soaps, and similar materials provide excellent emulsion stability. These materials concentrate at the interface between the dispersed aqueous phase and the continuous non-aqueous fluid. Salts and other water-soluble materials are dissolved in the internal aqueous phase of invert emulsion fluids to establish a concentration gradient and generate a chemical osmotic force. The backflow of simulated pore fluid resulting from this osmotic force is measurable in the laboratory. In the field, anecdotally, the induced osmotic backflow of formation-pore fluid into the invert emulsion drilling fluid is observed as change in oil/water or synthetic/water phase ratio and a reduction in salt concentration of the internal phase. Activity measurement applied to the Gibbs activity-osmotic relationship predicts that a potential osmotic pressure development for an invert emulsion fluid with 300,000 mg/L CaCl2 dissolved in the internal aqueous phase is 10,000 psi. With literature reporting σ = 1 for invert emulsions, those muds must be powerful indeed! System Design. The Shale Membrane Tester (SMT) is similar to the pore-pressure-transmission device described in a paper presented at Eurock '94.11 The five membrane-test cells each mount a shale core, diameter of 25.4 mm and length of 6 to 8 mm. A radial confining stress is applied. Test cells and shut-in valves are enclosed in an oven which allows testing to 250°F. The basic equipment arrangement is as shown in Fig. 4. A more detailed description of Test Equipment, Procedure, and Sources of Error can be found in Appendix B. The shale cores used in these experiments were cut from outcrop. The shale (X-ray diffraction, ion exchange, and porosity/permeability data are given in Table 3) was supplied

Fig. 4 – SMT System Schematic.

by TerraTek Inc., Salt Lake City, USA and described as “Pierre 1e”. Table 3 – Shale Characterization Data Pierre 1e Quartz

34%

Feldspar

6%

Calcite

1%

Dolomite

5%

Siderite

-

Pyrite

2%

Kaolinite

6%

Illite/Mica

18%

Chlorite Smectite and Mixed Layer

28%

CEC (mEq/100 g)

22

Porosity

17%

Permeability, Horizontal (D) Permeability, Vertical (D)

~ 1x10 –7

-6

~ 1x10 – 10

–8

Reservoir Pressure Development. Reservoir pressure development is dependent upon factors including, but not necessarily limited to ion diffusion, osmotic diffusion, hydraulic (Darcy) flow, barrier development, and, perhaps, viscosity of the diffusate. Osmotic diffusion of water is dependent upon a difference in ion/solute concentration on the respective wellbore and reservoir sides of the test cell. As ion/solute diffusion progresses, osmotic differential pressure will decrease. Darcy flow of water is dependent upon pressure difference between wellbore and reservoir sides of the test cell. Darcy flow can be opposed by osmotic diffusion. The addition of any dissolved material to the mud will generally decrease its water activity and increase potential

SPE 74557


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measured using vapor-pressure osmometry. Measured activity values were converted to osmotic pressure using the Equation 2: π = RTlnXA (Eq. 2) where π = osmotic pressure R = gas constant (0.08206 L atm/mol K) XA = activity

Fig. 5– Osmotic Pressure of Salt Solutions.

osmotic pressure development. While measured pressure differential may increase only temporarily, dissolved mineral salts can produce long-term effects on shale in several ways: 1) collapsing the double layer on clays 2) dissolution of sulfate or carbonate cementation 3) alteration of swelling characteristics by ion exchange. Mineral salts will also affect polymers present in the drilling fluid. If the viscosity or plugging effect is decreased, the measured osmotic pressure can decrease despite a lower activity of the drilling fluid. On the other hand, it is seen that addition of moderate amounts of calcium salt may so affect the structure of polymer or shale that the permeability is decreased or polymer-mediated viscosity increased, thereby reducing the flow of fluid into or out of the shale. Experimental Definition of Membrane Efficiency. For purposes of this screening work, a very simple model of membrane efficiency is applied. Membrane efficiency, as presented in Equation 1, is calculated from the measured initial stable differential pressure compared to the potential osmotic pressure.

Me = where Me Pw Pr π

= = = =

(Pw - Pr) ) π

(Eq. 1)

nominal membrane efficiency applied wellbore pressure recorded equilibrium reservoir pressure potential osmotic pressure

Osmotic pressure, π, is dependent upon the relative colligative properties of the test fluids which are often measured as solution activities. When water is the test solvent, π can be calculated from the difference in water activities of the test fluids. Osmotic pressure can be calculated from measured activity values or published values as appropriate for each test solution may be applied. Figure 5 was prepared from published activity values. Such published values are used to calibrate a laboratory activity test device. Potential osmotic pressures for saccharide-based and other solutes were calculated individually from activity values

For SMT tests, the reservoir fluid has water activity of approximately 1, thus the potential osmotic pressure developed between the test fluid and the reservoir fluid is essentially that given by Equation 1. However, these measurements, adequate for sample screening, do not take into account ongoing changes to the shale. In addition to initial pressure development, subsequent changes are indicative of the net effect of exchange of water, non-aqueous liquid, or solute over time. Those ongoing changes are manifested in three ways in the SMT. The initial osmotic effect may be profound or gradually trending up or down or change not at all depending on the type of membrane that is formed. Using the test apparatus described the pressure differential of applied mud pressure and developed reservoir pressure is recorded. This measurement method produces a curve inversely proportional to the hydraulic head development curve presented in Figure 1. Therefore generally one can expect a positive slope of increasing reservoir pressure with a Type 1 membrane, a zero slope and constant reservoir pressure with a Type 2 membrane, and, frequently, a negative slope of decreasing reservoir pressure with Type 3 membrane. When recording differential pressure a zero slope or negative slope indicates stable or increasing osmotic pressure and is preferred. A rising pressure curve indicates decay of osmotic pressure differential and is typical of water-based drilling fluids. A constant pressure indicates that fluid flux is zero or that a solvent/solute equilibrium condition has been established across the shale membrane. This equilibrium is typical of properly formulated silicate drilling fluids. Falling reservoir pressure indicates improving membrane efficiency. This study demonstrates that in some cases pore fluid moves out of the reservoir but may be partially or totally replaced by non-aqueous filtrate from the drilling fluid in the wellbore. Membrane efficiency, σ, generally changes with shale exposure time, pressure differential, and salt concentration. A simple membrane efficiency calculation is therefore not available for judging solute performance in these tests. The nominal, initial σ is therefore adjusted by the slope of the developing osmotic pressure curve to yield, for convenience of chemical evaluations and comparisons, a “σ factor” for judging the effectiveness of additives. The developing osmotic pressure and slope of the ongoing pressure curve are quantified in the data collection, Appendix A. The slope of the ongoing pressure curve is normalized against pressure drop and time. A negative or low “σ factor” is an indicator of reasonably stable osmotic properties (Figure 5). Both initial

6


osmotic pressure and a slope of the developed pressure curve are combined in a “σ factor” calculated by Equation 3: σ factor = 10000 * m / π Where: m π

(Eq. 3)

= slope of ongoing pressure trend = nominal osmotic pressure (from y intercept)

Both slope and nominal osmotic pressure are determined from the linear regression trendline of data collected after system is reasonably equilibrated. Nominal osmotic pressure is the difference between applied mud pressure and y-intercept from regression data. Because the SMT measures reduction in reservoir pressure rather than an increase in wellbore hydraulic head, the pressure response and slope measurement will be opposite that discussed in the introduction/background. Reduced membrane efficiency (σ < 1) or leakiness is demonstrated by a positive “σ factor”. Membrane efficiency of 1 is predicted by a calculated “σ factor” of zero or, in the case of invert emulsion-based fluids, a negative value. Example Test and Interpretation Figure 6 illustrates that osmotic effect persists through the 192-hour test. To test for osmotic effect, the reservoir pressure of WBM B, 10% CaCl2 formulation, was raised by 100 psi at 132 hr into the test. Over the next 24 – 28 hr, the chemical osmotic pressure product of the residual saltconcentration gradient returned the reservoir pressure to a normal and natural trendline; thus demonstrating a persistent and continually changing membrane efficiency. More important for test purposes is the relationship between the two pressure response curves. The composition of the two test fluids was as shown in Table 4. As might be expected, WBM A, the lower activity fluid, produced the greatest drop in reservoir pressure. Salts of divalent cations Shale Membrane Test Pierre 1E shale sample - High Performance WBM with carbohydrate blend and selected salt Pore Fluid 0-17hr Test Fluids 17-185hr 1000

Pressure, psi

900 800

Wellbore (Mud) Pressure Pore Pressure, HPWBM - 20% NaCl Pore Pressure, HPWBM - 10% CaCl2

700 600 500 400 0

24

48

Fig. 6 – WBM Comparison.

72

96 Time, hr

120

144

168

192

SPE 74557

generally produce more stable membranes which is shown by the reduction in slope of the ongoing pressure curve of WBM B as compared to WBM A. A linear trend line was established for a equilibrium section of each curve and slope calculated. From slope, y-intercept, an initial maximum osmotic pressure was calculated “σ factor”. In this test, the 24-hr pressure fluctuations were caused by change in pump-control sensitivity resulting from diurnal swings in room temperature. Wellbore pressure ranged from 882 to 911 psi tracking building environmental change. Oven temperature was nominally 150°F with variance of no more than +/- 0.1°F during the test. Daily fluctuation in wellbore pressure was passed to reservoir measurements with no more than 15% degradation in amplitude. Materials of Interest Initially the materials of interest were evaluated in fresh water and in 20% sodium chloride salt solutions. As need arose to screen more materials, a standard test fluid was mixed from tap water, 20% w/w sodium chloride salt, and with up to 30lb/bbl test material. Reduced concentrations of test material were used to compensate for excessive viscosity development of polymers and other higher viscosity additives (viscosity building materials typically did not perform well in these tests). A concentration was selected which allowed preparation of a mixed test sample which displayed a yield point of less than 20 lb/100 ft2. Xanthan gum polymer was added to increase and equalize yield point of fluids. A 20% salt solution was selected for use in these tests for three reasons. Many Gulf of Mexico water-based drilling fluids specify 20% sodium chloride to reduce the crystallization of gas hydrates at the low temperatures experienced in deepwater drilling. In addition to gas hydrate suppression, sodium chloride has been shown to provide a measure of shale stability in traditional tests. Other salts, which may provide improved membrane effects, are detrimental to the mysid shrimp used to test toxicity of Gulf of Mexico drilling fluids. Since a 20% sodium chloride solution can potentially produce an osmotic pressure of 3500 psi, measurable pressure development can be expected to occur despite membrane efficiencies reported in the literature to be typically less than 5%.7 Individual novel materials tested during three years included: Acrylic acid based polymers (14) Siloxanes (11) Polyamines (6) Saccharides and derivatives (28) Lignosulfonates, tannins, resins (7) Other polymers (16) Plugging materials (5) Glycols, polyglycols, and derivatives (13) Miscellaneous surfactants (26) When materials with interesting membrane properties were discovered, they were also tested at one or more calcium

SPE 74557


chloride concentrations. The most successful candidates were also combined with other novel shale stabilizing materials for further product development. A partial list of “activity enhancers” which were tested in water-based drilling fluids and/or synthetic-based drilling fluids included both ionic and non-ionic materials along with solutes intended to replace or supplement 20% NaCl as water activity suppressants: calcium chloride formates glucose (Aldrich Chemical Co.) sucrose glycols methylglucoside monomer (Sigma Chemical Co) commercial methylglucosides molasses commercial table sugar vinyl alcohol In addition, fully formulated muds weighing up 20 lbm/gal were evaluated. Performance Results - Membrane Type 1 Saccharides and derivatives. As a class, the saccharides materials are promising. Osmotic pressures of several hundred pounds per square inch characterized certain undiluted commercial methylglucoside materials. Addition of 50% water to commercial methylglucoside concentrated material with addition of sodium chloride salt to restore fluid activity did not maintain the osmotic pressure development seen with the pure or less dilute commercial material. Proprietary saccharide mud systems containing blends of sugars and oligomers, originally applied in the North Sea in 1991, display an osmotic effect similar to and in many applications superior to commercial methylglucoside. Use of polyvalent salts improves the plugging/viscosity effects of this class of osmotic enhancers. Proprietary saccharides muds do, as originally claimed, provide stable osmotic pressure development. Commercially available table sugar mixed at equal solids concentration to the proprietary saccharides mud system did not provide equivalent osmotic pressure. Peak osmotic drawdown of recorded reservoir pressure was high and pressure recovery curve was nearly horizontal, approaching zero slope and indicating a σ = 1. Specially prepared starches and other saccharides can enhance membrane efficiency in virtually every water-based drilling fluid to which they are added including silicates and other primarily Type 2 membrane formers. Peak osmotic reservoir pressure drawdown was usually but not necessarily significantly improved. The slope of the pressure recovery curve was less positive indicating viscosity and/or plugging effects as σ approaches 1. Test results indicate that selected materials, typically lowmolecular-weight saccharides and substituted carbohydrate polymers applied in high concentration increase membrane efficiency. Precipitative polyvalent salts are shown to increase the effect of many materials in this category of polymers

7

perhaps by crosslinking mechanisms and/or increased hydrated ion diameter. It has been demonstrated that a proper mix of polymer molecular weights will yield significant beneficial effect. The effect can be used to establish a membrane with a measurable “membrane efficiency”. A range of short chain, lowmolecular-weight polymers should be sufficiently small to just enter the shale pores. As the largest fraction of these polymers is physically trapped by torturosity of the capillary structures, hydrogen bonded to sites on exposed clays within the shale, or otherwise reacted, the permeability of the shale is effectively reduced. These trapped polymers reduce the internal pore dimensions. What follows is a cascade of entrapment of smaller, shorter, lower molecular weight polymers until some minimum dynamic pore dimension remains. The hydrated polymer molecules and constrained water molecules further slow fluid movement through the matrix of permeability. This represents a combined viscosity and plugging effect. Acrylic acid-based polymers. Generally positive results were not obtained with the polyacrylate, polyacrylamide, and related copolymers tested over a range of molecular weights. One low-molecular-weight polyacrylate demonstrated an osmotic pressure differential of 150 psi and a sigma factor of –0.03 based on a 20-hr test. A long-term test is required for validation. Siloxanes (dispersed or in an aqueous solution). Siloxanes as a class were unpredictable in performance. One silicon polymer derivative may double the permeability of shale to pore fluid and the next sample may decrease permeability by 50 to 80%. Positive membrane-forming effects were not generally significant in 20% sodium chloride solution. Lignosulfonates, tannins, resins. Lignosulfonates mixed at concentrations above 25 lb/bbl effectively reduced shale permeability by 50 to 70% in pore fluid-based formulations. This supports old claims that drilling fluids with high concentrations of lignosulfonate provide shale stabilization. However, lignosulfonate was not helpful in a 20% sodium chloride-based fluid. Glycols, polyglycols, and derivatives. A few glycols and polyglycols when used at high concentrations provided interesting osmotic differential pressures. This apparently was due to a water activity effect rather than stable membrane formation. The materials as a class failed to provide stable reservoir pressure for extended time. Miscellaneous surfactants. A variety of surfactants were tested including alkyl betaines, fatty acid salts of sorbitans, and others. The effect on osmotic pressure and stable reservoir pressure were not significantly improved compared to other materials. Traditional high-performance and highly inhibitive waterbased drilling fluids. Virtually all high-performance water-

8


based fluids will benefit from the addition of low-molecularweight saccharide polymers. Relatively high concentrations of these materials must be applied to reduce fluid flow into shale. A range of 15 to 30 lb/bbl was used in preliminary tests. Potassium and ammonium-based fluids, in general, reduce formation of or disrupt Type 1 membrane. Performance Results - Membrane Type 2 Polymerized films - In-situ polymerized films are efficient membranes. Work with polyacrylates, sugars, and glucosides led to an understanding of the role played by low-molecularweight polymers in membrane development in and on shale. Low-molecular-weight polymers from several suppliers were tested. A variety of cellulose-derived and polyacrylate oligomers increased σ to provide enhanced osmotic pressure. A family of economical proprietary material remained consistently interesting throughout testing during 2001 and 2002.13 The novel oligomers compared favorably to similarly performing proprietary acrylic acid-derived oligomers. One such experimental oligomer is totally soluble in virtually all types of aqueous-based fluids including KCl-polymer, calcium-based muds, bromide and formate-based fluids, and the currently used ether amine inhibited HPWBM systems used in the Gulf of Mexico, Canada and southern Europe. This very soluble oligomer provides both the sub-unit for a highly crosslinked polymer membrane and contributes to shale stability and improved HTHP filtrate control. Two personalities of the new HPWBM can be seen with change in pH. At pH above 9.5, a crosslinked-polymer membrane readily forms to coat the formation. At lower pH, the material does not readily polymerise but supports traditionally measured clay inhibition and stabilization. Available amine and oligomeric additives can easily enter the lamellae of the clay and serve as complementary hydration suppressants. One method used to form a polymer membrane in situ is by condensation of an aldehyde or ketone with a primary amine to form a Schiff base, as shown in Fig. 7. In this example, the primary amine (Reactant #1) is a diamine, but other primary amines and polyamines will react in the same way. The carbonyl molecule shown in Fig. 7 (Reactant #2) is glucose, but other sugars and polysaccharides may be used. Many of the carbonyl molecules that participate in this crosslinking reaction require an elevated pH to present an HC–OH | C=O | HO–CH | HC–OH + | HC–OH | H2C–OH

(2)

H2–N HC–OH CH3 CH3 HC–OH | | | | | C = N–CH–X–CH–CH2–CH–N = C CH–CH3 | | | | X HO – CH CH3 CH-OH | | | CH3–CH ---> HC–OH HO–CH | | | CH2 HC–OH HO-CH | | | CH–CH3 H2C–OH H2C–OH | H2-N (1)

+

HOH (2)

SPE 74557

aldehyde functionality, which facilitates the polymerization reaction. In some cases, the primary amine or polyamine will provide the pH environment required to drive the reaction. However, long-chain amines, diamines, or polyamines with a relatively low amine ratio may require supplemental pH adjustment using materials such as sodium hydroxide, potassium hydroxide, sodium carbonate, potassium carbonate, or calcium hydroxide. Effect of pH on osmotic pressure development is presented in Fig. 8 which shows decrease in reservoir pore pressure with time at pH 10. 13 Component solubility is affected by the working environment established by the carrier brine concentration and temperature of application. Reactant #1 and Reactant #2 should be selected to be soluble in the specific working environment. Solubility is primarily associated with molecular weight and polymer chain length but component moieties of both reactants will also affect solubility of the resulting Schiff base product. The Schiff base formed by the reaction of Reactant #1 and Reactant #2 must be of reduced solubility or insoluble in the carrier brine in order to form a sealing membrane on shale or other formation exposed during drilling of a well. Carrier brine salinity typically and usually applied in the testing of the present invention is 20% w/w which is a commonly used standard concentration used for offshore drilling in the Gulf of Mexico - USA. Salt concentrations from 5% NaCl to saturation have been tested and found effective in supporting the reaction. Application is not limited to sodium chloridebased carrier solutions. The Schiff base forms in potassium chloride, calcium chloride, and sulfate and nitrate salt solutions and in sugar, molasses, and methylglucoside solutions as well. 13 Salinity is not required for the Schiff reaction to occur. Proper selection of Reactant #1 and Reactant #2, each soluble in distilled, fresh, or tap water can produce a reaction product insoluble in fresh water and membrane formation would occur in that environment as well. If the salinity (more accurately stated as the water activity) of the wellbore fluid is equal to or less than the salinity (more accurately stated as the water activity) of the reservoir fluid then the desired osmotic pressure development would not occur. The membrane formed in a high activity environment will reduce water flow or diffusion into or through shale and also contribute to shale stability despite not contributing to a strong osmotic effect.12 Plugging materials. Plugging materials such as silicates, fumed silica, aluminates, aluminum salts, calcium hydroxide, and phenolic resins were tested. Sodium silicate-based fluids supplemented with sodium and potassium chloride salts provided the highest osmotic pressure development of all fluids tested. Sodium silicate-based fluids supplemented with proprietary saccharide-based polymers build and maintain osmotic pressures closest to their theoretical osmotic potential. Silicate-based fluids can provide membrane efficiency in excess of 70%.

Fig. 7 – Condensation Reaction Example.

Field results of fluids which yield Type 2 membranes have


been encouraging. Bit balling has been less of a problem than experienced with Type 1 membrane fluids. Formation and cuttings stability have been excellent. Type 2 membranes are typically formed by reaction or interaction of specific drilling fluid components with the surface of the formation. Material depletion is the greatest concern. Drilling fluid should be monitored for more than physical properties. Levels of reactive membrane-forming ingredients must be maintained to drive membrane formation. Maintenance of perfect rheological properties, HTHP, or pH in no way guarantees that membrane formation is occurring. Performance Results - Membrane Type 3

Pnet = π + Pc

(Eq. 4)

where Pc, the capillary pressure developed by the fluid at the entrance to a pore or void in the rock, is given by Eq. 5: Pc = 2 γmp cos θ/rp

(Eq. 5)

Pierre 1E Shale - pore entry comparison Fluid - IO1618 (maximum recordable reservoir pressure = 980 psi)

1500 Wellbore (Mud) Pressure Pore Pressure, low permeability shale Pore Pressure, high permeability shale

Pressure, psi

1000 750 500 250 0 0

12

24

36

48

60

Time, hr

Fig. 9 – Shale Entry Pressure for Olefin IO1618.

1250

1000

750

Well Bore (Mud) Pressure Pore Pressure, low permeability shale Pore Pressure, high permeability shale

500

250

0

Non-Aqueous Fluids, Synthetic-Based Fluids and Invert Emulsion Fluids. Oil-based and synthetic-based invert muds (OBM and SBM), now often referred to as non-aqueous fluids, have long been considered ideal drilling fluids for shale stabilization. It has been claimed that invert emulsion fluids produce a semi-permeable membrane on wellbore surfaces that prevents transport of all materials except water across the wellbore interface.14 Other experiments suggest that this may not be the case.15,16 In addition, the argument is made that there exist large capillary forces which in themselves prevent oil filtrate or oil-based mud (and emulsified water) from invading the rock fabric,16-19 implying that osmotic flow control with invert muds may not be critical for wellbore stability. Wettability measurements of oil-based muds on mineral surfaces suggest otherwise.20 The net steady-state pressure measured at the interface between an invert emulsion fluid and shale is expected to be

1250

9

Pierre 1E shale sample - high and low permeabililty tests Invert Emulsion Drilling Fluid - Activity 0.84 maximum recordable pore pressure = 980psi

Pressure, psi

SPE 74557

72

84

0

12

24

36

48

60

72

84

Time, hr

Fig. 10 – Shale Entry Pressure of Invert Emulsion Mud

Here γmp is the interfacial tension between the mud and the pore fluid, cos θ is the cosine of the contact angle made by the mud displacing the pore fluid, and rp is the radius of the pore throat. For rp values considered typical of many shales, e.g. 10 nm, Pc is predicted to be as high as 15 MPa (2250 psi).21 This is based on the assumption that the pore surfaces are completely water-wetting, i.e. θ = 0, and γmp = 0.074 N/m (74 dyne/cm). This prediction is consistent with several previously published SPE papers which suggested that oil will not enter a water-saturated shale.3,15 Now, if an invert mud has a membrane efficiency of 1.0 and it contains ~ 19% w/w CaCl2 in the internal phase, the steady-state osmotic pressure, π, should be about 2,750 psi (see Figure 5). Thus, Pnet might be expected to reach 5,000 psi. On the other hand, measured values of Pnet are much more modest. Recently a maximum value of 1 MPa (150 psi) was reported for a shale.22 The pressure differentials observed here for invert emulsion fluids are likewise quite small, ranging from 200 to 1200 psi. Use of natural cores contributed to the variability in the test results, and certainly mud rheological properties affected the rate of pressure development. Yet in no case did Pnet approach 5,000 psi. Invert emulsion fluids have significant membrane efficiencies demonstrated in experiments which show clearly that water moves from a high water-activity shale to a low water-activity invert emulsion fluid. Exchangeable ions do not readily move between the shale and the mud.21,23 Thus, the membrane established by OBM/SBM appears to be essentially perfectly selective and should have an efficiency of around 1.0. With respect to capillary pressure, shale permeability tests using neat oils and synthetic materials (Fig. 9) do reveal elevated entry pressure, in keeping with previous measurements of water/oil displacements.24 Using a more reasonable value for γmp for displacement of the pore water in a shale sample with a hydrocarbon (say γmp = 0.03 N/m) and rp ~ 10 nm, we may expect Pc ~ 900 psi. This is consistent with the results from our study: the entry pressures measured

10


Table 5 – Recovered from Filter Medium Disk Disk Disk Disk 1 2 3 4

Pierre 1E shale sample - high and low permeabililty tests Invert Emulsion Drilling Fluid - Activity 0.84 maximum recordable pore pressure = 980psi 1250

Pressure, psi

1000

750

Well Bore (Mud) Pressure Pore Pressure, low permeability shale Pore Pressure, high permeability shale

500

250

0 0

12

24

36

48

60

72

SPE 74557

84

Time, hr

Mud type Disk wt (g) 3 Disk Volume (cm ) 3 Matrix Volume (cm ) 3 Pore Volume (cm ) 3 Air (cm ) 3 Oil (cm ) 3 Water (cm )

Invert 23.22 5.03 2.92 2.11 0.22 1.02 0.87

Invert 23.09 5.03 2.90 2.12 0.39 0.68 1.05

WBM 23.15 5.03 2.91 2.12 0.18 0 1.94

WBM 23.23 5.03 2.92 2.11 0.35 0 1.76

of such a core forms a steep contact angle and “beads up,” whereas a drop of water placed on the face of a core exposed to polymer/20% NaCl immediately spreads across the surface. Not only does the invert emulsion drilling fluid oil-wet the surface of the shale, it also permeates the core and ultimately generates a significant amount of filtrate; this conclusion is

Fig. 10 – Shale Entry Pressure of Invert Emulsion Mud

for neat IO1618, an olefinic hydrocarbon, were ~ 1300 psi for a water-wet low-permeability shale and ~ 200 psi for a highpermeability (~ 1 μD) shale. A second set of tests (Figure 10) was run using a typical invert emulsion drilling fluid formulation. There was no clear barrier to fluid entry into shale of either high or low permeability. Indeed, reservoir pressure appeared to be established completely by the osmotic effect. This is consistent with previous measurements on water/oil displacements.24 For invert OBM or SBM, the emulsifiers and wetting agents can lower this value to < 0.001 N/m,20 so that Pc may be negligible for all but the finest pores. Based on post-test shale analysis and content of the stainless steel filter disk, a substantial amount of oil can find its way through a shale exposed to an invert emulsion drilling fluid. The photo in Fig. 11 demonstrates the near miscibility of oil and water in the presence of an equal volume of polyamide surfactant, in keeping with the very low value ascribed to γmp between invert emulsion fluids and pore fluid. In addition, it can be demonstrated that shale core samples exposed in the SMT to invert emulsion drilling fluid become oil wet. As shown in Figure 12, a drop of water placed on the face

Fig. 11– Photograph Sample 1 Sample 2 Sample 3 Sample 4

diesel oil + freshwater + surfactant diesel oil + CaCl2 25% + surfactant LVT + freshwater + surfactant LVT + CaCl2 25% + surfactant

Fig. 12 – Oil and Water-Wet Shale.

supported by analyses of fluid extracted from the sintered stainless steel disk supporting the shale core (Table 5). Not only does the invert emulsion drilling fluid oil-wet the surface of the shale, it also permeates the core and ultimately generates a significant amount of filtrate; this conclusion is supported by analyses of fluid extracted from the sintered stainless steel disk supporting the shale core (Table 5). Thus, if Pc is quite low for invert emulsion fluids, the differential pressure measured across the fluid/shale membrane should be approximately equal to π. That the measured values of Pnet are considerably lower than the predicted values of π suggests the strong influence of kinetics on shale dehydration3 and/or the influence of some other process(es). The most likely scenario derives from the observation of filtrate invasion (primarily base fluid + free surfactants), which leads to formation of a distribution of membranes throughout the invaded zone. This distribution of membranes within the fabric of the shale reflects a change in pore fluid composition and increasing pore fluid activity that accompanies the transport of filtrate. As evidence for this, the lower-permeability shale sample exhibited significantly higher Pnet than the higher-permeability sample. Very likely the lower-permeability sample still suffered from filtrate invasion, though not to as great an extent as the higher-permeability sample. Tests with a very-low-permeability shale may help to resolve this issue.

SPE 74557


Conclusions ¾

Three distinct types of membranes are produced by conventional water-based drilling fluids, polymer film forming/silicate based fluids, and invert emulsion based fluids. The osmotic mechanism is very different for each type of membrane.

¾

In-situ polymerization of proprietary oligomers by polyamines provides membrane performance comparable to that of silicate-based drilling fluids.

¾

Silicate-based drilling fluids provide nearly optimum membrane efficiency and osmotic effect.

¾

Specific saccharide-based polymers enhance membrane effects and promote osmotic pressure when used in 20% sodium chloride-based drilling fluids. Reduction of permeability and viscosity enhancement (reduction of hydraulic inflows) are two mechanisms that can account for the observed effects.

¾

Saccharide-polymer performance is enhanced by addition of calcium, magnesium, and aluminum salts to supplement or completely replace sodium chloride.

¾

Calcium chloride 10% is superior to sodium chloride 20% for building osmotic pressure and improving membrane efficiency.

¾

Invert emulsion fluids can provide excellent osmotic effects, though fluid invasion is apt to occur. Interaction of these fluids with shales is stronger than previously thought, resulting in capillary pressures and apparent membrane efficiencies that are significantly smaller than those assumed or reported in earlier work.

11

12


Nomenclature σ Pc rp θ γmp Me Pw Pr T XA π m

= = = = = = = = = = = =

Reflection coefficient Capillary pressure Radius of pore throat Contact angle of wetting phase in pores Interfacial tension between mud and pore fluid Nominal membrane efficiency Applied wellbore pressure Recorded equilibrium reservoir pressure Temperature (°K) Measured activity Osmotic pressure Slope of ongoing pressure trend

13.

14.

15.

16.

References 1.

Keijzer, Th.J.S.: “Chemical Osmosis in Natural Clayey Materials”, Geologica Ultraietum 196, PhD thesis, Universteit Utrect, Utrect, The Netherlands (2000). 2. Keijzer, Th.J.S. and J.P.G. Loch, J. P. G.: "Chemical osmosis in compacted dredging sludge", Soil Sci. Soc. Am. J 65: 1045-1055 (2001). 3. van Oort E., et al.: “Critical Parameters in Modelling the Chemical Aspects of Borehole Stability in Shales and in Designing Improved Water-Based Shale Drilling Fluids,” SPE 28309, SPE Annual Technical Conference, New Orleans, Sept 25-28, 1994. 4. Mitchell, J.K.: Fundamentals of Soil Behavior, Wiley (1993) Chapter 12. 5. Yeung, A.T. & Mitchell, J.K.: “Coupled Fluid, Electrical and Chemical Flows in Soil,” Geotechnique, 43 (1993) 121. 6. Fritz, S.J.: “Ideality of Clay Membranes in Osmotic Processes: A Review,” Clays and Clay Minerals, 34 (1986) 214. 7. Ewy, R.T.: “Pore Pressure Change Due to Shale-Fluid Interactions Measurements under Simulated Wellbore Conditions,” Fourth North American Rock Mechanics Symposium, Seattle, Washington, July 31, 2000. 8. Cussler, E.L.: Diffusion – Mass Transfer in Fluid Systems, Cambridge University Press (1984) 159. 9. Simpson, J.P. and Dearing, H. L., “Diffusion Osmosis – An Unrecognized Cause of Shale Instability,” IADC/SPE 59190, 2000 IADC/SPE Drilling Conference, New Orleans, LA Feb. 23-25, 2000. 10. Simpson, J. P. and Dearing, H. L., “Drilling Gumbo Shale – A Study of Environmentally Acceptable Muds to Eliminate Shale Hydration and Related Borehole Problems,” DEA-113, O’Brien-Goins-Simpson & Associates, Inc., Houston, July 2001. 11. Van Oort, E.: “A Novel Technique for the Investigation of Drilling Fluid Induced Borehole Instability in Shales,” Eurock '94, Balkema, Rotterdam, 1994. 12. Hale, A.H., Mody, F. K. and Salisbury, D. P.: “Experimental Investigation of the Influence of Chemical Potential on Wellbore Stability,” IADC/SPE 23885,

17. 18.

19. 20.

21.

22. 23.

24.

SPE 74557

SPE/IADC Drilling Conference, New Orleans, Feb 18-21, 1992. Schlemmer, R., et al.: “Progression of Water-Based Fluids Based on Amine Chemistry – Can the Road Lead to True Oil Mud Replacements?,” AADE-03-NTCE-36, AADE 2003 National Technology Conference, Houston, Apr 3, 2003. Ballard T.J. and Dawe R.A.: “Wettability Alteration Induced by Oil-Based Drilling Fluid,” SPE 17160, SPE Formation Damage Control Symposium, Bakersfield, California, Feb 8-9, 1988. Santos, H. and da Fontoura, S. A. B.: “Concepts and Misconceptions of Mud Selection Criteria: How to Minimize Borehole Stability Problems?” SPE 38644, SPE Annual Conference, San Antonio, Oct 5-8, 1997. Santarelli, F. J. and Carminati, S.: “Do Shales Swell? A Critical Review of Available Evidences,” SPE/IADC 29421, SPE/IADC Drilling Conference, Amsterdam, Feb 28 – Mar 2, 1995. Gazaniol, D., et al.: “Wellbore Failure Mechanisms in Shales: Prediction and Prevention,” Journal of Petroleum Technology (July 1995) 589. Fam, M. A. and Dusseault, M. B.: “Borehole Stability in Shales: A Physico-Chemical Perspective,” SPE/ISRM 47301, SPE/ISRM Eurock ’98, Trondheim, Norway, July 8-10, 1998. Bol, G. M., et al.: “Borehole Stability in Shales,” SPE Drilling & Completion (June 1994) 87. Cline, J. T., Teeters, D. C. and Andersen, M. A.: “Wettability Preferences of Minerals Used in Oil-Based Drilling Fluids,” SPE 18476, International Symposium on Oilfield Chemistry, Houston, Feb 8-10, 1989. Van Oort, E., Hale, A. H., Mody, F. K. and Roy, S.: “Transport in Shales and the Design of Improved WasterBased Shale Drilling Fluids,” SPE Drilling & Completion (Sept 1996) 137. Onalsi, A., Durand, C. and Audibert, A.: “Role of Hydration State of Shales in Borehole Stability Studies,” Eurock ’94, Balkema, Rotterdam, (1994) 293. Simpson, J. P., Walker, T. O. and Aslakson, J. K.: “Studies Dispel Myths, Give Guidance on Formulation of Drilling Fluids for Shale Stability,” IADC/SPE 39376, IADC/SPE Drilling Conference, Dallas, Mar 3-6, 1998. Teeters, D. C., Anderson, M. A. and Thomas, D.C.: “Formation Wettability Studies that Incorporate the Dynamic Wilhelmy Plate Technique,” in Oilfield Chemistry: Enhanced Recovery and Production Stimulation; J. Borchardt and T. Yen, Eds., ACS Symposium Series no. 396, Washington, D.C. (1989) 560.

SI Metric Conversion Factors psi (lbf/in2) lbm/bbl lbf/gal lbm/gal lbf/100 ft2 (°F–32) 5/9

x 6.895 x 3.5 x 1.12 x 1.20 x 4.79

E-03 = MPa E-01 = g/L E-01 = Specific Gravity (SG) E+02 = kg/m3 E-01 = Pa = °C

SPE 74557


13

Appendix A – Sample Data Set

Membrane Type

Nominal Osmotic Pressure (psi)

CaCl2 30%

3

277

-1.49

-54

ES 476v

CaCl2 30%

3

204

-1.00

-49

invert 70/30

ES 160v

CaCl2 30%

3

313

-0.36

-12

invert 70/30

ES 428v

CaCl2 22%

3

200

-0.18

-9

Field invert 80/20

ES 566v

CaCl2 19.3%

3

398

-0.08

-2

invert 80/20

ES 210v

CaCl2 30%

3

266

-0.05

-2

invert 80/20

ES 278v

NaCl 25%

3

911

-0.15

-2

sodium silicate 2.6

special formulation

KCl / NaCl as specified

3000 psi formulation

2

2650

-0.07

0

sodium silicate 2.0

special formulation

NaCl as specified

200 psi formulation

2

302

-0.01

0

sodium silicate 2.6

special formulation

NaCl as specified

2500 psi formulation

2

2470

-0.07

0

Polymerised film – oligomer + primary amine

25 ppb 5 ppb

NaCl 20%

pH 10.5

2

1600

0.01

0

sodium silicate 2.6

special formulation

NaCl as specified

500 psi formulation

2

755

0.01

0

proprietary oligomer blend

50%

CaCl2 10%

1

269

0.03

1

methylglucoside Type 206 (1747) with special additives

30%

CaCl2 18%

1

279

0.10

4

Tested material

Comment

Activity

invert 60/40

ES 215v

invert 90/10

Comment

experimental sample

slope sigma pressure factor return

salt blank

CaCl2 30%

1

230

0.15

7

sugar blank

sucrose 50%

1

267

0.23

8

30% 15ppb

CaCl2 18%

1

610

1.05

17

20% 15ppb

CaCl2 18%

1

213

0.45

21

1

205

1.10

54

sodium gluconate MP42 LMW cellulosic polymer sodium gluconate MP42 LMW cellulosic polymer

“Sigma” methyl glucoside monomer

MP93 MEG MP42 LMW cellulosic polymer

20% 15ppb

CaCl2 18%

sulfonated asphalt

30 ppb

NaCl 20%

1

120

0.87

72

MP7 polyglycol

30 ppb

NaCl 20%

1

135

1.20

89

salt blank

NaCl 20%

1

250

2.38

95

KCl polymer system

KCl 6%

1

42

0.53

127

MP61 CMC

25 ppb

NaCl 20%

1

160

2.10

131

resin lignite

30 ppb

NaCl 20%

1

168

2.25

134

lignosullfonate

30 ppb

NaCl 20%

1

110

2.33

212

14


SPE 74557

Appendix B – Details of Test Equipment, Procedures, and Sources of Error Test - Equipment Preparation. A typical test scenario begins with a thorough cleaning of all wetted surfaces and distilled water rinses of the test assembly. A 25.4-mm diameter core sample 6 to 8 mm in length is installed in a beveled rubber confining gasket mounted in a matching core holder subassembly of the test cell. Using a torque wrench, a clamping ring is installed on the core holder which compresses the rubber confining gasket to provide a calibrated fixed confining stress of up to 1000 psi (compression mechanically imposed) on the shale core. Confining stress cannot be readjusted after a test begins but does change to match mud fluid pressure when fluid pressure exceeds the preset

Fig A1 – Cell Types

confining stress. O-ring seals between coreholder and cell body are lubricated with viscous silicone-based lubricants to eliminate leaks. Before installing the coreholder, the cell body is filled with pore fluid. The coreholder is then pushed into the cell body until its external o-ring beds at a positioning step. Using a 60-mL syringe, excess pore fluid is removed from the reservoir side of cell holder, thereby pulling the coreholder into the cell body until fully seated. When seated in Type A cell, Fig. A1, a reservoir volume of 55.5 mL is established, which includes the porous stainless steel support disk, cell reservoir, gauge volume, and closed valve volume which completes the shut-in reservoir side of the cell assembly. When seated in Type B cell, a reservoir volume of approximately 6 mL is established which includes the sintered stainless steel support disk, passages through the base of the coreholder, the gauge and the closed valve volume. Test results using either Type A or Type B cells were comparable. After installation of the shale core in the cell assembly, the borehole side is filled with pore fluid. The cell cap is pushed into place and the clamping collar screwed down. Filling of the reservoir side of the cell is then completed. Air is removed from the reservoir side of the apparatus in every test. If air is not removed, all pressure build-ups below 200 to 300 psi display substantial lag due to compressibility. The lag precludes consistent test results. Acceptable linearity of the pressure and volume relationship generally begins above 150psi reservoir pressure, depending upon volume of residual air in the apparatus.

The oven is then closed and heater is switched on. Forced convection maintains oven and test cell temperature to within 0.1°F up to 250°F. The data acquisition system is started to record ongoing system adjustments, pressure changes, and temperature stabilization. After a minute, with 6000 data points collected (100 data points / sec), the data are averaged, queued for display, and transferred to a Microsoft Excel spreadsheet. Update of the displayed spreadsheet occurs every 10 min. Hydraulic pressure of 200 psi is applied to the wellbore (top) side of the test cell. Approximately 2 to 2.5 hr are required for the oven and contents to stabilize at the selected operating temperature but stabilization overnight is preferred. Hydraulic pressure of the wellbore (top) side of the test cell is adjusted to 600 psi. Reservoir pressure is adjusted manually to 200 psi using a 3cm3 syringe and the reservoir side shut-in valve closed. Reservoir pressure development is observed and recorded until reservoir pressure approaches wellbore pressure. Shale permeability is calculated as a function of increase in reservoir pressure. The test cell includes wellbore and reservoir containers separated by the shale core. A fluid differential pressure is applied across the shale core. As presented in calibration data, Fig. A2, an increase in reservoir pressure of 1000 psi represents a flow measurement of approximately 600 μL into the reservoir of Type A cell and 78 μL into the reduced reservoir volume of Type B cell.

Fig. A2 – System Pressure-Volume Relationship

The recorded pressure increase is converted to equivalent volume of perfusate. Fluid volume, differential pressure, core diameter, core length, and time are applied to Darcy’s equation to calculate shale permeability. Pore fluid in the wellbore side of the cell is then replaced by a test fluid. To separate the test fluid from the supply manifold, a diaphragm is placed atop the core holder assembly. The cell cap is pushed into place and a clamping collar screwed down upon the complete assembly to close and

SPE 74557


seal the device. Approximately 2 to 2.5 hr are required for the oven and contents to restabilize at the selected operating temperature. The borehole pressure is then set to 600 psi using a syringe pump. Reservoir pressure is adjusted manually to 200 psi using a 3-cm3 syringe and the reservoir side shut-in valve closed. Reservoir pressure development is observed and recorded for a period ranging from 3 hr to 10 days. All current testing is conducted for at least 120 hr if a candidate material is promising. Many tests, especially in case of invert emulsion, silicate, and saccharide-containing drilling fluids, require an increase in wellbore pressure to exceed rapidly building osmotic differential pressure. The highest pressure applied in any test to the wellbore side of the cell was 4500 psi for a silicate/salt mud system. The reservoir pressure was reduced to less than 100 psi by the osmotic pressure established by the silicate fluid. The reservoir pressure transducers have a maximum range limit of 980 psi. With two pressurizing pumps available for 5 cells, a required increase in wellbore pressure for adjacent cells to compensate for exceptional osmotic effect may occasionally drive an individual reservoir pressure off scale. Sources of Error Shale variation. Permeability tests with water indicated that the Pierre 1e shale ranged from approximately 0.3 to 10 μD when tested parallel to the bedding plane (horizontal tests). The range of permeability when tested perpendicular (vertical tests) to the bedding plane was 0.01 to 0.5 μD. The tests described here were originally designed for rapid sample screening and a cursory attempt was made to match shale permeability to a specific test or series of tests. Shale samples with permeability greater than 5 μD were either discarded or the collected data used for equipment evaluation only. Consistent media is considered more important for initial screening tests and may be superior to preserved shale for that purpose. Gauge displacement. When the project began, the first goal was to standardize on a simple screening process and test for the effects of fluid chemistry on permeability, sequentially applying as many candidate chemicals as possible. It was reasoned that thin shale disks would permit measurement of permeability changes in 8 hr or less for each individual candidate sample. Pressure of less than 200 psi was applied to test fluids and resultant reservoir response was recorded. Results were occasionally repeatable. Error investigation revealed that the precision transducers used to measure reservoir pressure required 80μL to achieve a full scale reading. Gauge displacement contributed to poor quality permeability measurements until the system pressure-volume relationships were delineated. Air Entrainment. Non-linearity of the system's PVT response was also attributed to residual air in the reservoir side

15

of the device. A small bubble of air in the 50-mL reservoir side of cell severely affects low pressure responsiveness of the device. An air bubble 10mm in diameter represents more than 500μL of readily compressible media in the reservoir. If excess air is not removed, all pressure build-ups below 250 psi are of questionable accuracy and usefulness. Temperature effects. The Honeywell precision transducers, as originally installed external to the oven, were sensitive to temperature changes with a design limit of 130°F. Transducers and pressure tubing mounted outside the test oven were directly affected by fluctuations of room temperature. Swings in reservoir pressure of more than 50 psi resulted from temperature-mediated fluid expansion or contraction in the gauge and tubing external to the oven. When gauge and tubing were mounted in the oven, accurate measurements originally were limited to 130°F or less due to gauge durability. Despite double electronic controllers, extra insulation, and a more rigorously controlled environment, reservoir pressure can respond to small temperature changes due to night and weekend building environmental changes. Opening the door to the oven for a few seconds can result in a temporary reservoir pressure change of more than 50 psi. When the temperature restabilizes, reservoir pressure returns to its original trendline unless some other problem exists or changes have been made in the system. There were many instances of data recorded which agreed with expectations. As often happens when things seem too good to be true, repeat runs revealed that interesting reservoir pressure changes reflected, more often than not, a fortuitous change in building temperature due to the setting sun rather than shale-fluid interactions or, more often, a system leak. Low displacement gauges providing calibrated response to 180°F and acceptable accuracy and excellent repeatability to 250°F are now in use and installed in the oven along with all valves and connecting tubing. The number of compression fittings has been reduced from eight to two on the reservoir side of the cell assembly. Seal effects. The rubber retaining ring for the shale disk is designed to translate compressive forces applied manually before the test begins to radial confining stress on the shale pellet. The preset confining stress preload remains constant until the wellbore fluid pressure exceeds the preload. Above the maximum preload of about 750 psi, confining stress is equal to wellbore fluid pressure. This is a weakness of the cell design and remains a nagging concern when high-pressure test results of certain fluids are considered. Shale bedding plane orientation. A technique used by earlier investigators was repeated in these tests. If a reducedpermeability shale was required for a specific test, the same shale, used for tests parallel to the bedding plane, was simply turned 90° so as to flow perpendicular to the bedding plane. The decision to use this technique rather than seek out a shale

16


with lower permeability parallel to the bedding plane was based upon expedience and cost. The dimensional and permeability change responses of shale to axial stress may vary markedly when comparing vertical and horizontal orientation. Manifold communication. Individual cells are manifolded to a common pressurizing pump through ⅛-in. plastic tubing. An earlier system design included individual accumulators to isolate each test fluid and cell from the next test fluid and cell. The accumulators were modified Baroid/OFI-type HTHP filtration cells with a piston to separate pressurizing fluid from test fluid. The additional thermal mass in the oven required warm up times of 4 hours. As fluid pressure of the tests increased, friction between o-rings and accumulator body produced pressure fluctuations of more than 25 psi. It was decided to forego use of the accumulators. Occasionally nearly identical pressure response curves were observed in adjacent cells. This was an indication that solute flux between the test fluids through the ⅛-in. pressurizing tubing may have been interfering with the test. A flexible nitrile rubber/vinyl laminated diaphragm is now installed in each static cell to physically preclude ion flux or water movement between cells through the pressurizing manifold. A single stirred cell is pressurized through an accumulator-type device devised from a small field-type HTHP cell with a standard PPA piston using one o-ring. Removal of one o-ring from the piston reduces frictional effects. The atmospheric-pressured cavity between two orings is eliminated which reduces friction. Recorded pressure fluctuations were reduced from 25 psi at 600-psi wellbore pressure to less than 5 psi when a small polished HTHP cell and modified piston was used.

SPE 74557